ML022180097

- Guarantee of Retrospective Premium

ML022180097
Person / Time
Site:	Calvert Cliffs
Issue date:	08/01/2002
From:	Katz P Constellation Energy Group
To:	Office of Nuclear Reactor Regulation
References
Download: ML022180097 (109)

Text

Peter E. Katz 1650 Calvert Cliffs Parkway Vice President Lusby, Maryland 20657 Calvert Cliffs Nuclear Power Plant 410 495-4455 Constellation Generation Group. LLC 410 495-3500 Fax Energy Constellation Group August 1, 2002 U. S. Nuclear Regulatory Commission Washington, DC 20555 ATTENTION: Director, Nuclear Reactor Regulation

SUBJECT:

Calvert Cliffs Nuclear Power Plant Unit Nos. I & 2; Docket Nos. 50-317 & 50-318 Guarantee of Retrospective Premium In accordance with the requirements of 10 CFR 140.21, we are attaching the guarantee of payment of deferred premiums for our Calvert Cliffs Nuclear Power Plant reactors.

Exhibit I A copy of the 2001 Annual Report to Shareholders of Constellation Energy Group Company containing certified financial statements Exhibit II "Acopy of quarterly financial statements as of June 30, 2002 Exhibit III "Acopy of Projected Cash Flow for the twelve months ended July 31, 2003 Exhibit IV Narrative statement on curtailment/deferment of capital expenditures (if any) to ensure that retrospective premiums up to $10 million per reactor year for each nuclear incident would be available for payment.

Should you have questions regarding this matter, we will be pleased to discuss them with you.

Very truly yours,

~~ /

PEK/MJY/dlm Attachments: As stated cc: Document Control Desk, NRC (Without Attachments)

R. S. Fleishman, Esquire H. J. Miller, NRC J. E. Silberg, Esquire Resident Inspector, NRC Director, Project Directorate I-1, NRC R. I. McLean, DNR XXI D. M. Skay, NRC

EXHIBIT I 2001 ANNUAL REPORT TO SHAREHOLDERS Calvert Cliffs Nuclear Power Plant August 1, 2002

L FINANCIAL HIGHLIGHTS 2001 2000  % Change (an millions, except per sha amount)

Common Stock Data Earnings per share Earnings per share before special costs included in operations and cumulative effect of change in accounting principle $ 2.60 $ 2.43 7.0%

Earnings per share before cumulative effect of change in accounting principle 0.52 2.30 (77.4)%

Earnings per share 0.57 2.30 (75.2)%

Dividends declared per share $ 0.48 $ 1.68 (71.4)%

Average shares outstanding 160.7 150.0 7.1%

Return on average common equity Excluding special costs and nonrecurring items 10.9% 11.9% (8.4)%

Reported 2.5% 11.3% (77.9)%

Book value per share-year end $ 23.48 $ 21.09 11.3%

Market price per share-year end $ 26.55 $ 45.06 (41.1)%

Market value of commona stock-year end $ 4,346 $ 6,783 (35.9)%

Financial Data Total r .e.v $ 3,928 $ 3,853 1.9%

Income from operations $ 358 $ 843 (57.5)%

Income before cumulative effect of change in accounting principle $ 82 $ 345 (76.2)%

Cumulative effect of change in accounting principle 9 Net income $ 91 $ 345 (73.6)%

Assets Merchant energy business $ 8,134 $ 7,296 11.5%

Regulated utility business 4,869 4,482 8.6%

Other businesses and corporate items 1,075 1,161 (7.4)%

Total assets $14,078 $12,939 8.8%

Total common equity $ 3,844 $ 3,174 21.1%

Nonregulated capital expenditures $ 1,850 $ 830 122.9%

Regulated capital expenditures $ 239 $ 350 (31.7)%

Certainprior-yearamounts have been mrclassifiedto confirm with the currntyearipresentation.

Earnings and Dividends Decdared* Common Stock Market Nrice Return on Average Common Equity Per Share of Common Stock and Book Value Per Snare MO0 14%

12%

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$4o 10%

$30

$20

$10 2%

$0 1997 1998 1999 2000 2001 1997 1998 1099 2000 2001 1997 1998 1999 2000 2001 SEarnings per Shared-*eorted 1 Book Value per Share - RWpOded I Earnings per Share-Before Special Costs 1 MarketPdce prShare 1 xcludingSpdICodts and and Nonrecurrng Items Nonrcumng ems M Dvidend Deacire. pro Share In January2002, the Boardof Directors announcedit will increase the dividend to 96 cents pershare (24 cents quarterdy).

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I I WXI Tith a long history in Central Maryland, Constellation Energy Group has repeatedly demonstrated the strength and flexibility V

• to prosper in diverse market conditions.

Our strength is rooted in industry knowledge, experience, and in valuable assets that include a premier gas and electric utility and a diverse portfolio of power plants.

OurJlexibilitycomes from a strong balance sheet, proven commercial skills, and strong decision-making abilities that allow us to adjust rapidly to evolving market conditions. This agility propels us forward as we act quickly to capitalize on the opportunities of the marketplace.

Together, strength andflexibility are theformulafor our success.

But strength and flexibility have another advantage: they are the perfect platform for growth. As our industry continues to change, we have the generation assets and the marketing expertise to capitalize. As the economy gains forward momentum, we are perfectly positioned to build upon the solid foundation that is our company.

Such is the success of Constellation Energy Group.

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4 / TO OUR FELLOW SHAREHOLDERS No doubt, 2001 was a tough yearfor our company, as it wasfor the entire energy industry. The combination of many factors, including the dramaticdecline in power prices, the collapse of Enron, and the dynamics of the California market, led us to make similarly dramaticchanges in our strategy and our organization.

In 2001, we canceled ourplans to separate, terminated our relationshipwith Goldman Sachs, and brought on a

new CEO. We also moved to controlcosts, streamline our organization,and intensif ourfocus on risk management.

As the year ended, we were already seeing the positive results of our decisive actions, and we arepleased to convey our confidence that we have emergedfrom a difficult year stronger than ever.

Ours has been an industry in transition for nearly a decade. accounting principle change in the first quarter that increased Much of the upheaval experienced in the past year may be an earnings per share by $.05. This resulted in reported earnings inevitable and necessary step in the evolution from a regulated for the calendar year of $.57 per share.

to a competitive market. This transformation has caused The special costs recognized in the fourth quarter (see volatility and uncertainty around many factors that affect our pages 22-23 in the Financial section) are the result of rigorous company's profitability. While we wholeheartedly endorse the analysis coupled with an aggressive strategy to monetize our industry's migration to a freely competitive market, we are non-core assets, improve our balance sheet, and rationalize our focused on maintaining our strength and flexibility, both cost structure. With these actions, we want to assure you that strategically and financially, and managing risk vigilantly while we are clearly focused on our core business of energy.

positioning our company for the future. Thus, that is the theme of this annual report. Dividend Policy Changes Going forward, we are committed and determined to improve Financial Highlights our results. Achieving a competitive totalreturn on your Our 2001 earnings from operations were $2.60 per share investment is our goal. Since deciding not to separate into two compared to $2.43 per share in 2000. In the fourth quarter, companies, we recognized that we needed to change our however, we reported a series of special costs that together dividend policy that became effective last year in April.

equal approximately $533 million, or a total earnings per share On January 30, we announced that we would increase our impact of $2.08. We also recorded a cumulative effect of an annual dividend from $.48 to $.96 per share beginning with I I

the next quarterly payment date of April 1, 2002. The Since canceling separation, we have moved quickly to dividend is a meaningful contributor to our goal of providing realign the management team and streamline our organization.

superior return to our shareholders. We have established three operating units and put the right people with the right skills in charge to manage them Focus on the Fundamentals In addition, we have created a new staff role of Chief Risk One of the most important strategic decisions we made last Officer, who is focused on defining and managing all key risks year was deciding not to separate our merchant from our retail across the company. It was particularly gratifying that our energy services business. This significant choice was partly prudent business practices allowed us to avoid any material driven by the capital markets, which had shifted dramatically Enron-related losses. This new position strengthens our ability and no longer awarded a cost-of-capital advantage to merchant to continue to manage risk responsibly.

generation companies. We also recognized that in times of The strategic and organizational decisions of 2001 provide economic uncertainty, it's wise to build from a base of scale real clarity to our direction. We are focused on being a leader and stability and that there is strength in a portfolio of in the wholesale merchant energy business and providing businesses that balances earnings growth and cash flow. premier utility and energy-related services in Maryland and the The collapse of Enron and the steady decline in the value surrounding region.

of all merchant energy companies have demonstrated that In pursuing these strategies, we are guided by the core our courageous decision not to separate was, in fact, the values that are fundamental to the successful operation of right decision. Constellation Energy Group. This is a company that has a

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186-year history of dealing fairly with its customers, of companies that have elected to outsource their wholesale maintaining the highest level of integrity, and of living up to its supply. Constellation is now a key player in the Northeast, the responsibility to its shareholders, communities, and employees.

Mid-Atlantic, and Texas-three regions that have meaningfully deregulated their retail energy markets. We plan to continue to A Solid Platform for Growth grow our load-serving market positions in these regions.

A Strong Base of GenerationAssets We built the risk management and long-term power We believe that the strongest energy businesses have physical contract origination business with the help of our advisor, assets to complement their merchant capabilities. Our strength Goldman Sachs. One of the strategic decisions made in 2001 in generation, including our expanding influence in the nuclear was the termination of the power business services agreement world, is a true core competency. In 2001, we started the year with Goldman. This allows us to benefit from 100% of the by winning the Edison Award, our industry's most prestigious profits and provides us with strategic and operating control honor, for our pioneering work in nuclear license renewal. We of this business, which is critically linked to our fleet of ended the year with the purchase of Nine Mile Point Nuclear generation assets.

Station. In the summer, we brought on line 1,100 megawatts of new gas-fired generation. We also have under construction Reliable Delivery and Returns an additional 2,900 megawatts in key parts of the country. Our regulated utility, Baltimore Gas and Electric Company As of year-end 2001, our Generation Group owned (BGE), balances our portfolio of energy businesses. BGE holds and operated about 9,200 megawatts of power. With a solid franchise in an economically healthy region that has 2,900 megawatts under construction, it will have more successfully deregulated the electric and gas supply. As an than 12,000 megawatts by the end of 2003 when all the energy-delivery company, BGE provides very predictable plants will be completed. earnings and generates high cash flow with a low risk profile.

BGE's 186-year heritage of serving Central Maryland is Leveraging OurAssets unique in our industry. Today, BGE delivers energy to more Our power marketing, long-term power contract origination, than 1.1 million electric and 600,000 gas customers. As and risk management business leverages off of the strength of always, its primary focus is on reliability, safety, and achieving our generation assets and is a vital part of our company's operational excellence.

success. Since its inception five years ago, this operation has Toward that end, the utility embraced a new initiative in generated strong earnings growth for Constellation. Much of 2001 to comprehensively review and re-engineer key business this growth has been driven by serving electric distribution processes. Now implementing the more than 200 recommen-This is a long-term business, and ConstellationEnergy Group has proven that the same strength and flexibility that have sustainedthis company for more than 186 years will help us withstand virtually any challenge the future may bring.

I I

/7 Maintaining the Balance more detail in the Financial section of this report. We believe these actions will prove critical to ensuring the strength of the 2002 Sources of Net Income company's balance sheet in the fiture.

While we have a jot of work ahead, our success is ultimately in our own hands. With employees focused on crisp execution of our strategy, we indeed are in control of our own destiny.

w o5% This is a long term business, and Constellation Energy Group has proven that the same strength and flexibility that have sustained this company for more than 186 years will help us 00 withstand virtually any challenge the future may bring.

That's cause for credit and applause for the many dedicated provide epen arle earingsrohn togcahfo employees who helped us weather a turbulent 2001.

Before closing, we want to thank and bid farewell to five Other 1% long-term board members who announced their retirement as of December 31, 2001: H. Furlong Baldwin, J. Owen Cole, Constellation Energy Group owns a balanced portfoijo ofmbusnesses-regula ted and nonregulated-that should Dan A. Colussy, Jerome W Geckle, and George L. Russell, Jr.

proid dependable earnings growth and strong cash flow All five combined have given 80 years of service to this with a moderate level of risk. company and provided impeccable leadership and guidance through the deregulation of Maryland's gas and electric industry and the formation of our merchant energy business.

dations that came out of the process, BGE has created the Sincerdy, blueprint for substantially improving business proccsses, functions, and activities while providing customers with mote efcicent, efkticve, and hasslefreeeservice.

A Company With Staying Power The California situation combined with Enron'. collapse and a Mayo A. Shattuck III slower pace of deregulation indicate that a lot is changing in Ptrident c e Chairmanofthe Board our world. Yet, Constellation Energy is operating from a Chiefllvecutive Officer position of strength with a very solid balance sheet. We have taken a series of decisive actions, all of which are discussed in March 25, 2002 c_(O2.

8 / AT A GLANCE Constellation Energy Group owns energy-rbteled businesses, including a North American wholesalepower marketing and merchantgeneration business, and the Baltimore Gas and Electric Company (BGE), a regulatedenergy delivery company in CentralMaryland In 2001, combined revenues totaled $3.9 billion.

Merchant Energy Our merchant eergy business has two main parts Generation andMarketing Constellation Generation Group: Owns and operates our fleet of power plants and generates the megawatts (MW) that we sell into the wholesale market.

Key Facts 2001 Highlights Generating Capacity 2003 Fuel Mix " Acquired Nine Mile Point Nuclear Station in eusands of MWS) (MWs of Capacity)

November resulting in the ownership of an additional 14 1,550 megawatts

"*Brought on-line more than 1,100 megawatts of natural 77e 1 hu""

gas-fired peaking plants at four sites (West Virginia, 2 Other Virginia, Illinois, and Pennsylvania)

Ony'xhu., 4%

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"*Owned and operated 9,200 megawatts of generation, with an annualized capacity output of 47,300 gigawatt-hours 2000 2001 2002 2003

"*Had under construction four new plants in Florida, Constellation Generation Group Constellation Generation Group Illinois, Texas, and California that combined will add owns and operates 9,200 MWs manages a diverse portfolio of nearly 2,900 megawatts by the end of 2003 as of year-end 2001; by year-end plants that maintains a balanced 2003, it will own and operate fuel mix and geographic and more than 12,000 MV/s. dispatch diversity Constellation Power Source: Oversees our power marketing, origination, and risk management operations and is responsible for selling every wholesale megawatt-hour Constelation Generation Group produces and managing all the associated market-hedgeable risk.

Key Facts 2001 Highlights

• Serves wholesale customers, including distribution

• Expanded its load-serving business in Texas by completing utilities, co-ops, municipalities, and other large, load a strategic alliance with TNP Enterprises, Inc., for serving companies that operate in deregulated energy managing the Texas power resource needs of its two markets, providing capacity, energy, and related products subsidiaries, Texas-New Mexico Power Company and and services First Choice Power

"*Serves significant volumes of the wholesale peak load in "*Expanded its total load-serving business in the Northeast, the Northeast, Mid-Atlantic, and Texas Mid Atlantic, and Texas to an expected peak of more than

"*Enhances our generation assets by providing access to 14,000 megawatts in 2002 national markets, market infrastructure, real-time market "*Signed long-term power sales contracts with California intelligence, risk management and arbitrage opportu Department of Water Resources and Florida's Seminole nities, and transmission and transportation expertise Electric Cooperative and Florida Power & Light to sell power from two of our plants under construction the High Desert plant in Southern California and the Oleander plant near Cocoa, Florida Cr23

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" Our menihant energy business currently owns 9,200 megawatts of generating casacity nationwideand focuses on serlng wholesale customers (distributionutilities, co-ops, municipalitiesand other large, ioad-sereingcompanies) that operate in deregulatedenergy markets, including the Noltheast and Mid-Atlantic regions, and Texass ft is also expanding its reach in Florida illinois, Texas, and Californiawith four power plants under construction in those states,

"*Our regulated energy deliveny business% BGE, delivers energy throughoutits 2,300-square-mile electrec ad BOO-squa-mie gas service territoryin CentralMary/and and is a member of the PJM Interconnection, which serves the Pennsylvania New Jersey,Marnlandregion.

"*Our offer retal menW services busness*s include ConstellationEnergy Source, which provides customized energy soluatons exclusively to commercial and industkalcustomers, and BGE Home Products &Se*uices, which provides home product* commercial building systems, and residentialand commercial electric and gas retailmarketing.

Regulated Energy Delivery Baltimore Gas and Electric Company (BGE)h Delivers energy to more than 1.1 million electric customers and 600,000 gas customers throughout Central Maryland.

Key Facts 2001 Highlights Electric Transmission and Distnibution

• Reported its best year ever for average interruptions per Operates in the PJM Interconnection and maintains customer, beating by 15% its previous all-time-best nearly 21,500 circuit miles of distribution lines and reliability record set in 2000 almost 1,300 circuit miles of transmission lines in a 0 Locked in wholesale power supply contracts with 2,300-square-mile service territory Constellation Power Source and Allegheny Energy Supply Company, LLC, ensuring it can meet its obligation as NatiralGas Distribution provider of last resort through the end of the transition to 0 Stores and delivers natural gas through two peak-shaving customer choice in 2006 plants, 10 gate stations, and nearly 6,000 miles of gas main

• Embarked on a new initiative-Achieving Operational in an over 800-square-mile service territory; natural gas Excellence-to enhance financial and operational suppliers include Columbia Gas Transmission Corporation, performance while increasing customer satisfaction, Transcontinental Gas Pipeline Corporation, and Dominion reliability and productivity, and reducing costs Transmission c(o-

"10/ THE FORMULA FOR SUCCESS Together,strength andflexibility are theformulafor our success.

In an industry buffeted by unpredictableforces, rangingfrom regulatory uncertainty to the bankruptcy of industry "leaders"suchas PG&Eand Enron, success can be measured by the ability to withstandpowerflforces and prosper under challengingconditions. It can also be measured in a commitment to values that have stood the test of time: service excellence, reliability,integrity, respectfor the environment, and involvement in the community.

On thesepages are some of our 2001 success stories.

They include the expansion ofourpower generationfleet anda continuedfocus on risk managementand customized approachesto supply the needs of wholesale energy customers. They also include significant reliability improvements and business milestones achieved by our utility operations,as well as some of our notable accomplishments in community outreach and environmentalstewardship.

From the momentum gainedfrom lastyear, we expect our strength andflexibility to bring us even greatersuccess in 2002 and beyond.

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\",: Supplier of Choice In deregulatedenergy markets like New England', customers can choose their electric supplier.

Those not making a choice receive afixed-rate energv supply, or standardoffer service,from their utility To meet that obligation, electric distributionutilities have turnedto companies like Constellation PowerSource, our originationand risk management business.

Last September, the Maine Public Utilities Commission chose Constellation Power Source to provide the standard-offer-service energy supply to 550,000 residential and small-business customers in the state. The three-year contract runs through February of 2005 and fits nicely with our overall strategy to be a key player in the national merchant energy market.

Constellation Power Source manages risk for large, load-serving customers (such as Co 'nstellation Power Source is a major utilities and municipalities), including their exposure to volatile energy prices. Balanced by ele ctric supplier in Maine. owned or controlled generation assets, it designs the wholesale products and services necessary for the emerging competitive marketplace.

Focusing on deregulated regions, Constellation Power Source has gained a major foothold in key markets, including

"*The Northeast, where contracts like the one in Maine have made it one of the major regional suppliers;

"*Maryland, where it won the competitively bid contract to supply 90% of BGE's standard-offer-service electric load from July 1, 2003, through June 30, 2006-an extension of its current contract to serve 100% of BGE's standard offer service through June 30, 2003; and

"*Texas, where it forged a special alliance with TNP Enterprises, Inc., for managing the Texas power resource needs of its two subsidiaries, Texas-New Mexico Power Company and First Choice Power.

Through transactions like these, we have built a strong platform for growth. m

/ 11 Powering Success ConstellationEnergy' balancedportfolio ofpowerplants provides us with theflexibility to meet our wholesale customers' energy needs. With plants located strategicallyacross the country, our porfolho includes a balancedmix ofnuclear, coal, natural gas, and renewableplants that have diverse dispatch capabilities.

Balanced Growth In 2001, the power behind Constellation's merchant energy business continued to grow. In the fall, Constellation completed the acquisition of the Nine Mile Point Nuclear Station in New York State. Also, last summer we added more than 1,100 megawatts, bringing on-line four new gas-fired peaking plants in strategic markets from Illinois to Virginia and Pennsylvania.

We are continuing our balanced growth trend with four Nine Mile Point Nuclear Station in Oswego County New York, is the largest addition to our merchant fleet.

gas-fired power plants currently under construction in SU S-California, Texas, Florida and Illinois that are scheduled to come Nuclear. A Banner Year on-line, adding another 2,900 megawatts to our competitive The momentum created by the historic generation portfolio by the end of 2003. license renewal of our Calvert Cliffs Nuclear Power Plant in 2000 carried over Strong Operations into 2001. In the spring, we received our The flexibility in our growing portfolio is enhanced by strong industry's highest honor-the Edison performances at our existing power plants. Electric Institute's Edison Award. This Our Calvert Cliffs plant had its second-best year ever in terms prestigious award recognized our of power production and continued to rank among the best in pioneering work as the first commercial worker safety. Plus, two of the plant's four new steam generators nuclear plant in the country to be arrived last year Workers will replace the steam generators in authorized to operate for an additional 2002 (Unit 1) and 2003 (Unit 2) and make other major upgrades 20 years by the U.S. Nuclear Regulatory Constellation Ener"gy, that will help the plant continue to safely generate clean electricity Commission. EEl's Edison Awari Our standing as an industry leader in winner in 2001 for many years to come.

On the fossil fuel side, our nine Baltimore-based plants safety and performance made a difference in our purchase of produced 14.7 million-megawatt-hours in 2001-a 2% increase Nine Mile Point. Niagara Mohawk Power Corporation---one over 2000. While maintaining one of the lowest forced outage of the sellers-and the New York Public Service Commission rates in their history, these plants also implemented a number of cited our reputation for performance, safety, and environ process improvement programs to reduce costs and be mental stewardship as major reasons why Constellation more competitive. won the bid E

/13 Serving the Communities Where We Work Despite a year of nationalturmoiland uncertainty,ConstellationEnergy and its employees remain constant in their commitment to the community. Below are some of the ways we respondedto those in need in 2001:

"*We continued our regional leadership in supporting the United Ways of Maryland, increasing our donation for the fourth consecutive year with a combined pledge of almost $2.5 million.

"*We again rolled up our sleeves to donate more than 4,000 units of blood, a 46% employee participation rate that is the highest among private-sector employers in the Maryland region. It's no surprise that for more than 40 years the American Red Cross has relied on our employees for much of our region's needed blood supply.

"*We translated our grief over the September 11th attacks into support for its heroes. In addition to a corporate donation to United Way of New York City's September 11th Fund, employees also gave victims their money, time, and blood.

"*We volunteered hundreds of hours and raised thousands of dollars to support charities such as Special Olympics and the March of Dimes, and local initiatives including community shelters and literacy programs.

"*We contributed corporately almost $4.7 million to community-strengthening initiatives that have proven to have a positive impact on education, economic development, and the environment in the areas where we operate. n F

Protecting the Environment Recognizedfor our environmentalstewardship, Constellation Baltimore, it is the Energy bridges the gap between protectingnaturalresources company's largest coal and creatinga better quality of hfe for customers. Hereare burning facility. Last some notable accomplishments that will have a positive, year, it completed the long-lastingefect on the environment: installation of two

"*Constellation Energy received the 2001 WasteWise selective catalytic Partner of the Year Award-the U.S. Environmental reduction (SCR)

Protection Agency's highest honor for its voluntary reactors. SCRs work program to reduce municipal solid waste. We were cited like the catalytic for our innovative and cost-effective new programs to converter in your prevent waste, increase recycling, and boost expenditures car to reduce on recycled-content products. nitrogen oxide

"*Constellation Generations Safe Harbor hydroelectric (NOx) plant in Pennsylvania, of which we have two-thirds emissions-known Located in the ChesapeakeBay to contribute to the CriticalArea, our Sprng Gardens natural ownership, received that state's Governor's Environmental gas facility won Baltimore's 2001 Majyor's Excellence Award. Recognized for its river-borne debris formation of Business RecognitionAward for our site removal program, the plant uses a floating harvester to ground-level ozone reforestationand clean-up efforts.

collect trash and refuse in the Susquehanna River, a or smog. Brandon tributary of the Chesapeake Bay, and brings it to shore for Shores is now capable of achieving a 90% NOx reduction sorting and recycling. and ranks as one of the country's cleanest coal-burning plants of its size. m

"*Constellation Generation's Brandon Shores power plant significantly reduced its air emissions. Located outside of

14 / A CONVERSATION WITH MAYO A. SHATTUCK III In October 2001, ConstellationEnergy Groups'Board ofDirectors elected Mayo A. Shattuck III Presidentand ChiefExecutive Officer. Notyour everyday utility CEO, Shattuck came to Constellationwith a unique and powerful backgroundofsuccess infields vital to the changing energy business--capitalmarkets, trading,investment banking, and corporatefinance.

Hejoined the company after leaving hisposition as ChairmanofDeutsche Banc Alex. Brown, the successor company to the nation's oldest investment bank, Alex. Brown & Sons, where he had been President.Earlierin his careeratAlex. Brown, he headed the firm's Technology Group, which managedseveral landmark initialpublic offerings includingMicrosoft, AOL, Sun Microsystems, and Oracle.

Shattuck says that his priority has always been, and always will be, creatingshareholdervalue. In the following question and answersession, he articulateshow his vision and unique skills will make thatpriority a reality at ConstellationEnergy Group.

-1 ,so1 s

-' You're the company'sfirst I assumed my new role at Constellation Energy during a CEO who has been hired time of great upheaval for this industry. In effect, we are from the outside. What experiencing the collapse of a speculative bubble. Bubbles are perspective do you bring created when financial markets allow too much capital to flow that's importantin todays to specific industries or ideas without sufficient pickup in energy marketplace? demand to meet the new level of supply.

I really feel fortunate to be It isn't difficult to find evidence of this in the power following in a long line of industry: the collapse of Enron and subsequent rating leaders who have helped agencies' actions; an expected oversupply in generation transform and steward capacity-, efforts across the industry to cut new generation this great company for spending and turbine orders, and to sell non-core assets; and almost two centuries. Chris Poindexter finally, a retrenchment in expectations for earnings growth.

has managed the company through its most challenging deregu I've seen similar bubbles and, over the years, I've learned latory years, and this management team is particularly grateful to that, regardless of the industry, a management team needs to have his ongoing guidance as Chairman and as an influential focus on its strengths and intensify the focus on managing risk industry leader in the many trade and regulatory issues we face. to successfully navigate through a transition period like the one we are experiencing.

/15 In my first several months on the job, we've taken steps to The benefits of address the weaknesses that have hindered our performance in Constellation's more stable the past. We have reorganized the management structure and businesses-like our utility reinvigorated the organization to focus on execution and our and our generating plants ability to manage risk in a prudent and responsible way. are that their solid cash flow and earnings balance We now have a ChiefRisk Officer as a partof our executive the growth potential of management team. Why didyou create thatposition? our new origination Success in today's energy market is all about managing risk, a business.

task that has become vastly more complex over the past several In effect, our decision years. Volatility in fuel costs and power prices, congestion in not to separate helped transmission, illiquidity in financial markets, and many other preserve a portfolio of businesses that, when factors all contribute to a much more dynamic business model. married together, create a nice balance between stability and We have to be smart in how we define and manage risk. growth. That allows us to be competitive on multiple fronts That's why I elevated the position of Chief Risk Officer to a going forward.

rMayo hmfuhkIII corporate level, much the way I've managed risk at large Thefailure ofderegulationin Californiaand then the collapse financial institutions in the past. ofEnron have hada dramaticimpact on the industry. What The Chief Risk Officer reports directly to me and is makes ConstellationEnergy differentfrom the rest of the sector?

responsible for defining our risk from a corporate portfolio First, Constellation Energy is not even close to Enron in terms standpoint. He bridges all business lines in an independent of the type of business we run and the way in which we fashion and systematically identifies the risks that each part of behave. The best energy businesses have physical assets to our business faces daily so we can proactively make decisions complement their merchant capabilities and they maintain about what we want to pursue. He also makes sure we're strong customer relationships. That's what our company has continually and vigilantly assessing the credit risk of the many and plans to preserve. In short, we have real assets, real counterparties with which we deal. customers, and a real business that has staying power.

We take the issue of disclosure very seriously. We have One of the reasons givenfor not separatingis the importanceof worked hard to ensure we provide our shareholders with the having a strong balance sheet. How has that helped set us apart information they need to understand our financials and the from the pack today? factors that could affect our earnings results. It used to be that Creditworthiness is a critical element of our strategic position. the weather was the main source of quarterly earnings To grow and take advantage of opportunities, it's important to variability. Today there are many other factors. Our goal is to have balanced sources of net income and a strong balance sheet. keep our shareholders informed while we build a business that is viable over the very long term.

continued on next page

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It's also important to understand that Maryland is not Are mergers and acquisi California in terms of deregulation. Since implementing tions apartofourfiture?

electric customer choice in July 2000, Maryland has been Are you planningon spared the problems associated with deregulation in California. buildingor acquiring Today, all BGE customers have a choice as to their energy more powerplants to commodity suppliers. As the provider of last resort, BGE continue to strengthen locked in wholesale power supply contracts in 2001 with your generatingasset Constellation Power Source and Allegheny Energy Supply portfolio?

Company, LLC. These contracts ensure the utility can meet its Our strategy is to grow obligation to provide power through June 2006 at rates and the merchant energy terms set by the Maryland Public Service Commission's business, so we are 1999 Restructuring Order. focused on merchant energy-related assets What makes certain regions more attractive than othersfor that support our our business? customer-focused origination business. We evaluate all Our merchant energy business is focused on the national opportunities against a strict set of criteria. We are only looking wholesale market. It serves customers-including distribution for acquisitions that provide strong return to our shareholders.

utilities, co-ops, municipalities, and other large, load-serving companies-that operate in regions that have meaningfully ConstellationEnergy Group has been a leader in the nuclear deregulated their retail energy markets. industry. What role will nuclearplay in the company'sfuture?

That is why we have built a significant presence in the Nuclear generation remains one of our core competencies and Northeast and Mid-Atlantic regions, and Texas. Over the next an important part of our balanced portfolio of generating two years, we plan to continue to grow our load-serving assets. We will continue to maintain a commitment to excel market positions in these regions and expand beyond as we lence at our two nuclear stations, which comprise more than bring on plants in Florida, Texas, Illinois, and California. 3,200 megawatts of our total 9,200-megawatt portfolio.

Toward that end, our Calvert Cliffs plant is replacing its What kind ofgrowth do you seefor our company? four steam generators. Once the project is complete, the plant We have set a long-term goal of growing earnings per share from can continue to safely generate dean electricity for many years organic sources at 10% a year, and we have a solid plan to achieve to come.

that. About 30% of our earnings still come from our regulated In addition, we are embarking on a long-term performance energy delivery business, while our competitive wholesale improvement plan at our Nine Mile Point plant and initiating merchant energy business contributes nearly 70%. If we combine a license renewal effort. Our goal is to take this asset to the the share price appreciation, which should result from our next level in terms of safety, reliability, capacity factors, earnings growth, with our new 3% dividend yield, we hope to and productivity.

achieve an overall total shareholder return of 13% or more.

How does thefuture look for ConstellationEnergy Group?

What challengesdo we face in meeting our growth targets? This company has some very bright prospects. I believe that it The most important thing we have to do is execute well. We is well-positioned to emerge from this period of uncertainty as also must be ever more vigilant about making sure we have the a strong company with solid building blocks for growth Our best competitive cost structure in the industry. And we must core strengths-high quality assets, the right people to operate leverage our human capital. Providing we do those things and them, and a strong balance sheet-will be the platform for improve the valuation of the company, we will be in control of that growth. m our own destiny.

/17 Contents Operating Statistics ............................. 18 Consolidated Statements of Common Shareholders' Equity ................... 53 Selected Financial D ata .......................... 20 Consolidated Statements of Capitalization ............ 54 Management's Discussion and Analysis .............. 21 Consolidated Statements of Income Taxes ............ 56 Report of M anagement .......................... 48 Notes to Consolidated Financial Statements ........... 57 Report of Independent Accountants ................. 48 Board of D irectors .............................. 88 Consolidated Statements of Income ................. 49 Executive Team ................................ 90 Consolidated Statements of Comprehensive Income ..... 49 Five-Year Statistical Summary ..................... 92 Consolidated Balance Sheets ...................... 50 Shareholder Information ......................... 93 Consolidated Statements of Cash Flows .............. 52

-fiin n~v wiarpr Forward Looking Statements We make statements in this report that are considered forward looking terrorism, liabilities associated with catastrophic events, and other statements within the meaning of the Securities Exchange Act of 1934. events beyond our control, Sometimes these statements will contain words such as "believes," "expects," Mthe inability of BGE to recover all its costs associated wvith providing "intends," "plans," and other similar words. These statements are not electric retail customers service during the electric rate freeze period, guarantees of our future performance and are subject to risks, uncertainties, "*the effect of weather and general economic and business conditions and other important factors that could cause our actual performance or on energy supply, demand, and prices, achievements to be materially different from those we project. These risks, "*regulatorsy or legislative developments that affect demand for energy.

uncertainties, and factors include, but are not limited to: or increase costs, including costs related to nuclear power plants,

"* the timing and extent of changes in commodity prices for energy safety, or environmental compliance, including coal, natural gas, oil, and electricitY, "*the actual outcome of uncertainties associated with assumptions and

"* the timing and extent of deregulation of, and competition in, the estimates using judgment when applying critical accounting policies energy markets in North America, and the rules and regulations and preparing financial statements, including factors that are adopted on a transitional basis in those markets, estimated in applying mark-to-market accounting, such as variable

"* the conditions of the capital markets generally, which are affected by contract quantities and the value of mark- to- market assets and interest rates and general economic conditions, as well as liabilities determined using models, Constellation Energy and BGE's ability to maintain their current "*cost and other effects of legal and administrative proceedings that credit ratings, may not be covered by insurance, including environmental liabilities,

"*the effectiveness of Constellation Energy's risk management policies or the outcome of pending appeals regarding the Maryland Public and procedures and the ability, of our counterparties to satisR' their Service Commission's (Maryland PSC) orders on electric deregu financial commitments, lation, and the transfer of BGE's generation assets to affiliates, and 1 the liquidity' and competitiveness of wholesale markets for energy "* operation of our generation assets in a deregulated market without commodities, the benefit of a fuel rate adjustment clause.

Moperational factors affecting the start-up or ongoing commercial Given these uncertainties, you should not place undue reliance on these operations of our generating facilities (including nuclear facilities) forward looking statements. Please see the other sections of this report and and BGE's transmission and distribution facilities, including our other periodic reports filed with the SEC for more information on catastrophic weather related damages, unscheduled outages or repairs, these factors. These forward looking statements represent our estimates unanticipated changes in fuel costs or availability, unavailability' of and assumptions only as of the date of this report.

gas transportation or electric transmission services, workforce issues, Changes may occur after that date, and we do not assume responsibility to update these forward looking statements.

Constellation Energy Group, Inc. and Subsidiaries

18 / OPERATING STATISTICS 2001 2000* 1999 1998 1997 Merchant Energy Mark-to-Market Energy Assets (In millions) $2,218.2 $2,522.4 $373.4 $133.0 $ 9.4 Mark-to-Market Energy Liabilities (In millions) 1,799.8 1,994.5 225.1 99.0 8.6 Revenues (In millions)

Standard Offer Service Revenue from BGE $1,269.0 $ 691.0 $ - $ - $

Other Generation Revenue 314.1 171.9 124.3 129.4 108.1 Mark-to-Market Energy Revenues 175.8 151.5 147.7 47.5 2.6 Other Revenue 6.6 11.3 5.3 6.7 2.3 Total Revenue $1,765.5 $1,025.7 $277.3 $183.6 $113.0 Generated (In millions)--iWH 37.4 18.8 1.3 1.3 1.2 Regulated Utility Electric Operating Statistics Revenues (In millions)

Residential $ 885.3 $ 922.6 $ 975.2 S 948.6 $ 932.5 Commercial 903.0 926.2 939.3 912.9 892.6 Industrial 218.1 203.6 204.3 211.5 211.9 System Sales 2,006.4 2,052.4 2,118.8 2,073.0 2,037.0 Interchange and Other Sales - 53.8 112.1 120.8 132.7 Other 33.6 29.0 29.1 27.0 22.3 Total $2,040.0 $2,135.2 $2,260.0 $2,220.8 $2,192.0 Sales (In thousands)--NWIH Residential 11,714 11,675 11,349 10,965 10,806 Commercial 14,147 14,042 13,565 13,219 12,718 Industrial 4,445 4,476 4,350 4,583 4,575 System Sales 30,306 30,193 29,264 28,767 28,099 Interchange and Other Sales - 2,064 4,785 5,454 6,224 Total 30,306 32,257 34,049 34,221 34,323 Customers (In thousands)

Residential 1,040.5 1,033.4 1,021.4 1,009.1 1,001.0 Commercial 110.9 108.9 107.7 106.5 105.9 Industrial 5.0 5.0 4.7 4.6 4.5 Total 1,156.4 1,147.3 1,133.8 1,120.2 1,111.4 Average Use per Residential Customer-KWIH 11,257 11,297 11,111 10,866 10,794 Average Rate per KW-H (System Sales)-c Residential 7.56 7.90 8.59 8.65 8.63 Commercial 6.38 6.60 6.92 6.91 7.02 Industrial 4.91 4.55 4.70 4.62 4.63 Operatingstatistics do not reflect the elimination of intercompany transactions. continued on next page

• Operatingstatistics reflect generationfunction as part of regulatedelectric operations through June 30, 2000.

ConstellationEnergy Group, Inc. andSubsidiaries

OPERATING STATISTICS / 19 2001 2000 1999 1998 1997 Gas Operating Statistics Revenues (In millions)

Residential -Excluding Delivery Service $378.4 $328.4 $298.1 $279.2 $321.7

-Delivery Service 16.3 23.5 11.5 4.9 0.5 Commercial--Excluding Delivery Service 115.5 97.9 79.3 75.6 113.5

-Delivery Service 21.4 25.8 24.4 19.4 12.9 12.8 10.9 8.2 8.0 11.4 Industrial -Excluding Delivery Service

-Delivery Service 13.8 16.3 16.1 16.0 17.2 558.2 502.8 437.6 403.1 477.2 System Sales 113.6 101.0 42.9 40.9 37.5 Off-System Sales 8.9 7.8 7.6 7.1 6.9 Other

$680.7 $611.6 $488.1 $451.1 $521.6 Total Sales (In thousans)--DTH 33,147 34,561 34,272 33,595 39,958 Residential -Excluding Delivery Service

-Delivery Service 7,201 9,209 4,468 1,890 205 12,334 13,186 11,733 11,775 18,435 Commercial -Excluding Delivery Service 25,037 22,921 20,288 16,633 12,964

-Delivery Service 1,386 1,386 1,367 1,412 2,016 Industrial -Excluding Delivery Service

-Delivery Service 23,872 32,382 33,118 34,798 38,791 102,977 113,645 105,246 100,103 112,369 System Sales 20,012 22,456 15,543 16,724 14,759 Off-System Sales 122,989 136,101 120,789 116,827 127,128 Total Customers (In thousands) 558.7 553.7 543.5 532.5 524.5 Residential 40.2 40.1 39.9 39.6 39.3 Commercial 1.4 1.4 1.3 1.3 1.3 Industrial 600.3 595.2 584.7 573.4 565.1 Total Average Rate per Therm-$

1.14 .95 .87 .83 .81 Residential -Excluding Delivery Service .74 .68 .64 .62

.94 Commercial -Excluding Delivery Service .79 .60 .57 .57

.93 Industrial -Excluding Delivery Service 727.8 658.4 765.0 668.6 795.7 Peak Day Sendout (In thousands)--DTH 836.6 833.0 870.0 937.8 825.1 Peak Day Capability (In thousands)--DTH Operatingstatistics do not reflect the elimination of intercompany transactions.

Constellation Energy Group, Inc. and Subsidiaries

20 / SELECTED FINANCIAL DATA 2001 2000 1999 1998 1997 (Do//ar amounts in millions, except per share amounts)

Summary of Operations Total Revenues $3,928.3 $3,852.5 $3,840.9 $3,386.4 $3,307.6 Total Expenses 3,570.5 3,009.9 3,081.0 2,647.9 2,584.0 Income From Operations 357.8 842.6 759.9 738.5 723.6 Other Income (Expense) 1.3 4.2 7.9 5.7 (52.8)

Income Before Fixed Charges and Income Taxes 359.1 846.8 767.8 744.2 670.8 Fixed Charges 238.8 271.4 255.0 260.6 258.7 Income Before Income Taxes 120.3 575.4 512.8 483.6 412.1 Income Taxes 37.9 230.1 186.4 177.7 158.0 Income Before Extraordinary Item and Cumulative Effect of Change in Accounting Principle 82.4 345.3 326.4 305.9 254.1 Extraordinary Loss, Net of Income Taxes - (66.3) - _

Cumulative Effect of Change in Accounting Principle, Net of Income Taxes 8.5 - - _

Net Income $ 90.9 $ 345.3 $ 260.1 S 305.9 $ 254.1 Earnings Per Common Share and Earnings Per Common Share-Assuming Dilution Before Extraordinary Item and Cumulative Effect of Change in Accounting Principle $.52 S2.30 $2.18 $2.06 $1.72 Extraordinary Loss - (.44)

Cumulative Effect of Change in Accounting Principle .05 ....

Earnings Per Common Share and Earnings Per Common Share-Assuming Dilution $ .57 $2.30 $1.74 $2.06 $1.72 Dividends Declared Per Common Share $ .48 S1.68 $1.68 $1.67 $1.63 Summary of Financial Condition Total Assets $14,077.6 $12,939.3 $9,745.1 $9,434.1 $8,900.0 Short-Term Borrowings $ 975.0 $ 243.6 $ 371.5 $ - $ 316.1 Current Portion of Long-Term Debt $ 1,406.7 $ 906.6 $ 808.3 $ 541.7 $ 271.9 Capitalization Long-Term Debt $ 2,712.5 $ 3,159.3 $2,575.4 $3,128.1 $2,988.9 Redeemable Preference Stock 90.0 Preference Stock Not Subject to Mandatory Redemption 190.0 190.0 190.0 190.0 210.0 Common Shareholders' Equitys 3,843.6 3,174.0 3,017.5 2,995.9 2,876.4 Total Capitalization $ 6,746.1 $ 6,523.3 $5,782.9 $6,314.0 $6,165.3 Financial Statistics at Year End Ratio of Earnings to Fixed Charges 1.18 2.78 2.87 2.60 2.35 Book Value Per Share of Common Stock $23.48 $21.09 $20.17 $20.08 $19.47 Certainprior-yearamounts have been reclassified to conform with the current years presentation.

Constellation Fonerj (;roup, Inc. and Subsidiaries I

MANAGEMENT'S DISCUSSION AND ANALYSIS / 21 OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Introduction Constellation Energy Group, Inc. (Constellation Energy) is a As you read this discussion and analysis, refer to our North American energy company that conducts its business Consolidated Statements of Income on page 49, which present through various subsidiaries including a merchant energy the results of our operations for 2001, 2000, and 1999. We business and Baltimore Gas and Electric Company (BGE). Our analyze and explain the differences between periods in the merchant energy business generates and markets wholesale specific line items of the Consolidated Statements of Income.

electricity in North America. BGE is an electric and gas public Also, this discussion and analysis is based on the operation of utility company with a service territory that covers the City of the electric generation portion of our utility business under rate Baltimore and all or part of ten counties in central Maryland. regulation through June 30, 2000. Our regulated electric We describe our operating segments in Note 3 on page 66. business changed as we transferred our electric generation assets References in this report to "we" and "our" are to and related liabilities to our merchant energy business, and we Constellation Energy and its subsidiaries, collectively. References entered into retail customer choice for electric generation in this report to the "utility business" are to BGE. effective July 1, 2000. Accordingly, the results of operations and Effective July 1, 2000, electric generation was deregulated in financial condition described in this discussion and analysis are Maryland. Also, on July 1, 2000, BGE transferred all of its generation not necessarily indicative of future performance.

assets and related liabilities at book value to our merchant energy business. As a result, the financial results of the electric generation Critical Accounting Policies portion of our business are included in the merchant energy business Our discussion and analysis of financial condition and results of beginning July 1, 2000. Prior to July 1, 2000, the financial results of operations are based on our consolidated financial statements electric generation were included in BGE's regulated electric business. that were prepared in accordance with accounting principles We discuss the deregulation of electric generation in the Business generally accepted in the United States of America.

Environment section on page 25. Management makes estimates and assumptions when preparing Our merchant energy business includes: financial statements. These estimates and assumptions affect various matters, including:

"*fossil, nuclear, and hydroelectric generating facilities, interests in domestic power projects, and nuclear "*our reported amounts of assets and liabilities in our consulting services, and Consolidated Balance Sheets at the dates of the financial statements,

"* power marketing, origination transactions, and risk management services. "*our disclosure of contingent assets and liabilities at the dates of the financial statements, and BGE is a regulated electric and gas public transmission and distribution utility company. "*our reported amounts of revenues and expenses in our Consolidated Statements of Income during the reporting Our other nonregulated businesses include:

periods.

"*energy products and services, These estimates involve judgments with respect to, among

"*home products, commercial building systems, and residential and commercial electric and gas retail other things, future economic factors that are difficult to predict marketing, and are beyond management's control. As a result, actual

"*a general partnership, in which BGE is a partner, that amounts could differ from these estimates.

provides cooling services for commercial customers in The Securities and Exchange Commission (SEC) recently Baltimore, issued disclosure guidance for accounting policies that

"*financial investments, management believes are most "critical." The SEC defines these

"*real estate and senior-living facilities, and critical accounting policies as those that are both most important to the portrayal of a company's financial condition

"*interests in Latin American power generation and distribution projects and investments. and results and require management's most difficult, subjective, In this discussion and analysis, we explain the general or complex judgment, often as a result of the need to make financial condition and the results of operations for estimates about the effect of matters that are inherently Constellation Energy including: uncertain and may change in subsequent periods.

"*what factors affect our businesses, Management believes the following accounting policies

"*what our earnings and costs were in the years presented, require us to use more significant judgments and estimates in

"*why earnings and costs changed between years, preparing our financial statements and could represent critical

"*where our earnings came from, accounting policies as defined by the SEC. We discuss our

"*how all of this affects our overall financial condition, significant accounting policies, including those that do not

"*what our expenditures for capital projects were for 1999 require management to make difficult, subjective, or complex through 2001, and what we expect them to be through judgments or estimates, in Note 1 on page 57.

2003, and

"*where we expect to get cash for future capital expenditures.

ConstellarionEnergy Group, Inc. and Subsidiaries

22/

Revenue Recognition/Mark-to-Market Method Evaluation of Assets for Impairment and Other Than of Accounting Temporary Decline In Value Our subsidiary, Constellation Power Source, uses the mark-to We are required to evaluate certain assets that have long lives market method of accounting to account for a portion of its (generating property and equipment and real estate) to power marketing activities. We record all other revenues in the determine if they are impaired if certain conditions exist. We period earned for services rendered, commodities or products determine if long-lived assets are impaired by comparing their delivered, or contracts settled. undiscounted expected future cash flows to their carrying Power marketing activities include new origination transac amount in our accounting records. We would record an tions and risk management activities using contracts for energy, impairment loss if the undiscounted expected future cash flows other energy-related commodities, and related derivative from an asset were less than the carrying amount of the asset.

contracts. We use the mark-to-market method of accounting Additionally, we evaluate our equity-method investments to for portions of Constellation Power Source's activities as determine whether they have experienced a loss in value that is required by EITF 98-10, Accountingfor Contracts Involved in considered other than a temporary decline in value.

Energy Trading and Risk Management Activities. Under the We use our best estimates in making these evaluations and mark-to-market method of accounting, we record the fair value consider various factors, including forward price curves for of commodity and derivative contracts as mark-to-market energy, fuel costs, and operating costs. However, actual future energy assets and liabilities at the time of contract execution. market prices and project costs could vary from those used in We record reserves to reflect uncertainties associated with our impairment evaluations, and the impact of such variations certain estimates inherent in the determination of fair value. could be material.

Mark-to-market energy revenues include:

"*the fair value of new transactions at origination, Events of 2001

"*unrealized gains and losses from changes in the fair value In the past year, the utility industry and energy markets experi of open positions, enced significant changes as a result of the slowing of the U.S.

i net gains and losses from realized transactions, and economy, the significant declines in both the short-term and a changes in reserves. long-term market prices of electricity in certain regions, the We record the changes in mark-to-market energy assets and events in California, the financial collapse of Enron Corporation liabilities on a net basis in "Nonregulated revenues" in our (Enron), as well as the effects of the September 11, 2001 Consolidated Statements of Income. Mark-to-market energy terrorist attacks, and the threat of additional attacks. We address assets and liabilities are comprised of a combination of energy certain of these issues in the Business Environment section on and energy-related derivative and non-derivative contracts. page 25.

While some of these contracts represent commodities or instru In response to our changing business environment, we ments for which prices are available from external sources, other canceled our separation plans and terminated our power commodities and certain contracts are not actively traded and business services agreement with Goldman Sachs & Co.

are valued using modeling techniques to determine expected (Goldman Sachs) on October 26, 2001. We believe that future market prices, contract quantities, or both. The market maintaining our current corporate structure provides a better prices used to determine fair value reflect management's best platform of size, strength, and stability from which to execute estimate considering various factors, including closing exchange our strategies. As a result of the significant declines in market and over-the-counter quotations, time value, and volatility prices of electricity, we terminated all planned development factors. However, it is possible that future market prices could projects not currently under construction.

vary from those used in recording mark-to-market energy assets Separately, we initiated efforts to reduce costs in order to and liabilities, and such variations could be material. become more competitive and to sell certain non-core assets in Certain power marketing and risk management transactions order to focus management's attention and our capital resources entered into under master agreements and other arrangements on our core energy businesses. We discuss our initiatives in provide our merchant energy business with a right of setoff in more detail in this section. We continue to examine plans to the event of bankruptcy or default by the counterparty. We achieve our strategies, and to further strengthen our balance report such transactions net in the balance sheets in accordance sheet and enhance our liquidity.

with FASB Interpretation No. 39, Offietting ofAmounts Related to Certain Contracts. Contract Termination Related Costs We discuss the impact of mark-to-market accounting on our We announced the termination of our power business services financial results in the Results of Operations-MerchantEnergy agreement with Goldman Sachs. We paid Goldman Sachs a Business section on page 30. total of $355 million, representing $196 million to terminate the power business services agreement with our power Constellation Energy Group, Inc. and Subsidiaries

/ 23 marketing operation and $159 million previously recognized as cost and interest expense that could trigger a settlement loss in a payable for services rendered under the agreement. We issued 2002 estimated to be approximately $20 million.

commercial paper and borrowed under our existing bank lines We discuss our early retirement and severance programs in to fund this payment. In the fourth quarter of 2001, we more detail in Note 2 on page 64, Note 6 on page 71, and recognized expenses of approximately $224.8 million pre-tax, Note 7 on page 72.

or $139.6 million after-tax, related to the termination of the contract with Goldman Sachs. Goldman Sachs also will not Impairment Losses and Other Costs make an equity investment in our merchant energy business as In the fourth quarter of 2001, our merchant energy business previously announced. We discuss the termination of our power recorded impairments of $46.9 million pre-tax, or $30.5 business services agreement with Goldman Sachs in Note 2 on million after-tax, primarily due to the termination of all planned page 65. development projects not currently under construction, including projects in Texas, California, Florida, and Sale of Guatemalan Operations Massachusetts and due to a decline in value of an investment in On November 8, 2001, we sold our Guatemalan power plant a power project in Michigan. We decided to terminate our operations to an affiliate of Duke Energy International, L.L.C., development projects due to the expected excess generation the international business unit of Duke Energy. Through this capacity in most domestic markets and the significant decline in sale, Duke Energy acquired Grupo Generador de Guatemala y the forward market prices of electricity. The impairments Cia., S.C.A., which owns two generating plants at Esquintla include costs associated with four turbines no longer expected to and Lake Amatitlan in Guatemala. The combined capacity of be placed in service.

the plants is 167 megawatts. In the fourth quarter of 2001, our other nonregulated We decided to sell our Guatemalan operations to focus our businesses recorded $107.3 million pre-tax, or $69.7 million efforts on our core energy businesses. As a result of this trans after-tax, in impairments of certain non-core assets as follows:

action, we are no longer committed to making significant future "*We decided to sell six real estate projects without further capital investments in this non-core operation. We recorded a development and our senior-living facilities and accelerate pre-tax loss of $43.3 million, or $28.1 million after-tax, in the the exit strategies for two other real estate projects that we fourth quarter of 2001, resulting from this sale. We discuss this will continue to hold and own over the next several years.

sale in Note 2 on page 65. "*We decided to accelerate the exit strategy for the investment in a distribution company in Panama.

Workforce Reduction Programs "*There was an other than temporary decline in value in In the fourth quarter of 2001, we undertook several measures to our equity method Bolivian investment due to a reduce our workforce through both voluntary and involuntary deterioration in our investment's position in the means. The purpose of these programs was to reduce our Bolivian capacity market.

operating costs to become more competitive. As part of this In addition, our financial investments business recorded a initiative, several companies including our merchant energy $4.6 million pre-tax, or $2.8 million after-tax, reduction of its business and BGE announced Voluntary Special Early investment in an aircraft due to the decline in value of used Retirement Programs (VSERP) to provide enhanced retirement airplanes as a result of the September 11, 2001 terrorist attacks benefits to certain eligible participants that elect to retire in and the general downturn in the aviation industry.

2002 and other involuntary severance programs. We discuss these special costs further in Note 2 on page 65.

As a result, we recorded $105.7 million pre-tax, or $64.1 million after-tax, of expenses related to these programs during Acquisition of Nine Mile Point the fourth quarter of 2001. BGE recorded $57.0 million of the On November 7, 2001, we completed our purchase of the Nine pre-tax amount as expense relating to its electric and gas Mile Point Nuclear Station (Nine Mile Point) located in Scriba, businesses. BGE also recorded $19.5 million on its balance sheet New York. Nine Mile Point Nuclear Station, LLC, a subsidiary as a regulatory asset of its gas business. We will continue cost of Constellation Nuclear, purchased 100 percent of Nine Mile cutting measures to remain competitive in our business Point Unit 1 and 82 percent of Unit 2 for cash of $382.7 environment and expect to record approximately $35 million of million including settlement costs and a sellers' note of $388.1 additional expense in 2002 related to the programs implemented million to be repaid over five years with an interest rate of to date. As a result of our workforce reduction efforts to date, we 11.0%. This note may be prepaid at any time without penalty.

expect annual cost savings of approximately $72 million. The sellers also transferred approximately $442 million in We also expect that a significant number of retiring employees decommissioning funds. As a result of this purchase, we own covered by our qualified, basic pension plan will elect to receive 1,550 megawatts of Nine Mile Point's 1,757 megawatts of total their pension benefit in the form of a lump-sum payment in generating capacity.

2002. These lump-sum payments may exceed annual plan service Constellation Energy Group, Inc. and Subsidiaries

24 /

We will sell 90% of our share of Nine Mile Point's output, Events of 2002 on a unit contingent basis (if the output is not available because Dividend Increase the plant is not operating, there is no requirement to provide On January 30, 2002, we announced an increase in our quarterly output from other sources), back to the sellers at an average dividend to 24 cents per share on our common stock payable price of nearly $35 per megawatt-hour for approximately 10 April 1, 2002 to holders of record on March 11, 2002. This is years under power purchase agreements. equivalent to an annual rate of 96 cents per share. Previously, our We discuss the acquisition of Nine Mile Point further in quarterly dividend on our common stock was 12 cents per share, Note 14 on page 86. equivalent to an annual rate of 48 cents per share.

Enron Investment in Orion On December 2, 2001, Enron Corporation filed for reorgani In February 2002, Reliant Resources, Inc. acquired all of the zation under Chapter 11 of the U.S. Bankruptcy Code. Our outstanding shares of Orion Power Holdings, Inc. (Orion) for financial exposure to Enron is not material. Prior to the $26.80 per share, including the shares we owned of Orion. We bankruptcy filing, our power marketing operation settled its received cash proceeds of $454.1 million and recognized a pre positions with Enron and as a result has no direct credit tax gain of $255.5 million on the sale of our investment.

exposure to Enron.

Investment in Corporate Office Properties Trust (COPT)

Bethlehem Steel In March 2002, we sold all of our COPT equity-method On October 15, 2001, Bethlehem Steel Corporation filed for investment, approximately 8.9 million shares, as part of a public reorganization under Chapter 11 of the U.S. Bankruptcy Code. offering. We received cash proceeds of $101.3 million on the Bethlehem Steel's Sparrows Point plant, located in Baltimore, sale, which approximates the book value of our investment.

Maryland is BGE's largest customer, accounting for approxi mately three percent of electric revenues and one percent of gas Strategy revenues. At December 31, 2001, our exposure to Bethlehem On October 26, 2001, we announced the decision to remain a Steel was not material. There is uncertainty regarding the single company and canceled prior plans to separate our continuation of Bethlehem Steel's operations; however, we do merchant energy business from our other businesses and termi not expect the impact to be material to our financial results. nated our power business services agreement with Goldman Sachs as previously discussed in the Events of2001 section on New President and Chief Executive Officer page 22.

Effective November 1, 2001, Mayo A. Shattuck, III was elected Our primary growth strategy centers on our merchant President and Chief Executive Officer of Constellation Energy. energy business. The strategy for our merchant energy business Christian H. Poindexter remains as Chairman of the Board. Mr. is to be a leading competitive provider of energy solutions for Shattuck has been a Director of Constellation Energy or a wholesale customers in North America. Our merchant energy subsidiary for seven years. Prior to joining Constellation Energy, business has electric generation assets located in various regions he was Global Head of Investment Banking for Deutsche Bank of the United States and engages in power marketing and risk and Co-Chairman and Co-Chief Executive Officer of DB Alex. management activities and provides energy solutions to meet Brown and Deutsche Bank Securities. wholesale customers' needs throughout North America.

Our merchant energy business integrates electric generation Certain Relationships assets with power marketing and risk management of energy Michael J. Wallace, prior to becoming President of and energy-related commodities. This integration allows our Constellation Generation Group on January 1, 2002, was a merchant energy business to maximize value across energy Managing Member and Managing Director and greater than products, over geographic regions, and over time. Our power 10% owner of Barrington Energy Partners, LLC. Upon marketing operation adds value to our generation assets by becoming President of Constellation Generation Group, Mr. providing national market access, market infrastructure, real Wallace terminated his affiliation with Barrington, and no time market intelligence, risk management and arbitrage longer holds any ownership interest in it. Barrington Energy opportunities, and transmission and transportation expertise.

Partners provided consulting services to Constellation Energy Generation capacity supports our power marketing operation by and its subsidiary, Constellation Nuclear during 2001, and is providing a source of reliable power supply, enhancing our continuing to do so during 2002. We paid Barrington ability to structure sophisticated products and services for approximately $4.4 million in 2001. customers, building customer credibility, and providing a physical hedge.

Constellation Energy Group, Inc. and Subsidiaries I I

/ 25 Currently, our merchant energy business controls over Business Environment 11,500 megawatts of generation including the 1,550 megawatts With the shift toward customer choice, competition, and the of the nuclear generating capacity at Nine Mile Point and the growth of our merchant energy business, various factors will 1,100 megawatts of natural gas-fired peaking capacity that affect our financial results in the future. We discuss these various commenced operations in the Mid-Atlantic and Mid-West factors in the ForwardLooking Statements section on page 17.

regions during mid-summer 2001. We also have approximately In this section, we discuss in more detail several factors that 2,900 megawatts of natural gas-fired peaking and combined affect our businesses.

cycle production facilities under construction in Texas, California, Florida, and Illinois. Electric Competition To achieve our strategic objectives, we expect to continue to We are facing competition in the sale of electricity in wholesale support our power marketing and risk management operations power markets and to retail customers.

with generation assets that have diversified geographic, fuel, and dispatch characteristics. We also expect to use a disciplined Maryland growth strategy through originating transactions with wholesale On April 8, 1999, Maryland enacted the Electric Customer customers and by acquiring and developing additional Choice and Competition Act of 1999 (the Act) and accompa generating facilities when necessary to support our power nying tax legislation that significantly restructured Maryland's marketing operation. electric utility industry and modified the industry's tax structure.

Our merchant energy business will focus on long term, In the Restructuring Order discussed below, the Maryland high-value sales of energy, capacity, and related products to PSC addressed the major provisions of the Act. The accompa distribution companies and other wholesale purchasers, nying tax legislation is discussed in detail in Note 5 on page 69.

primarily in the regional markets in which end user electricity On November 10, 1999, the Maryland PSC issued a rates have been deregulated and thereby separated from the cost Restructuring Order that resolved the major issues surrounding of generation supply. These markets include the Northeast electric restructuring, accelerated the timetable for customer region, the Mid-Atlantic region, and Texas. choice, and addressed the major provisions of the Act. The The growth of BGE and our retail energy services businesses Restructuring Order also resolved the electric restructuring is expected through focused and disciplined expansion. proceeding (transition costs, customer price protections, and Customer choice, regulatory change, and energy market unbundled rates for electric services) and a petition filed in conditions significantly impact our business. In response, we September 1998 by the Office of People's Counsel (OPC) to regularly evaluate our strategies with these goals in mind: to lower our electric base rates. The major provisions of the improve our competitive position, to anticipate and adapt to Restructuring Order are discussed in Note 5 on page 69.

business environment and regulatory changes, and to maintain As a result of the deregulation of electric generation, the a strong balance sheet and an investment-grade credit quality. following occurred effective July 1, 2000:

In the fourth quarter of 2001, we undertook a number of mAll customers can choose their electric energy supplier.

initiatives to reduce our costs towards competitive levels and to BGE will provide a standard offer service for customers ensure that our management and capital resources are focused that do not select an alternative supplier. In either case, on our core energy businesses. This included the implemen BGE will continue to deliver electricity to all customers in tation of workforce reduction programs, efforts to reduce capital areas traditionally served by BGE.

spending for planned development projects not currently under

• BGE reduced residential base rates by approximately construction, and to accelerate our exit strategy for certain non 6.5%, on average about $54 million a year. These rates will core assets. not change before July 2006.

We also might consider one or more of the following m BGE transferred, at book value, its nuclear generating strategies: assets, its nuclear decommissioning trust fund, and related m the complete or partial separation of BGE's transmission liabilities to Calvert Cliffs Nuclear Power Plant, Inc. In function from its distribution function, addition, BGE transferred, at book value, its fossil gener mmergers or acquisitions of utility or non-utility businesses ating assets and related liabilities and its partial ownership or assets, and interest in two coal plants and a hydroelectric plant located msale of assets or one or more businesses. in Pennsylvania to Constellation Power Source Generation.

In total, these generating assets represent about 6,240 megawatts of generation capacity with a total net book value at June 30, 2000 of approximately $2.4 billion.

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26 /

"*BGE assigned approximately $47 million to Calvert Cliffs discussed in the FERC Regulation-RegionalTransmission Nuclear Power Plant, Inc. and $231 million to Organizationssection on page 28.

Constellation Power Source Generation of tax-exempt Our merchant energy business has $296.4 million invested debt related to the transferred assets. in operating power projects of which our ownership percentage

"*Constellation Power Source Generation issued approxi represents 146 megawatts of electricity that are sold to Pacific mately $366 million in unsecured promissory notes to Gas & Electric (PGE) and to Southern California Edison (SCE)

BGE. All of these notes have been repaid by Constellation in California under power purchase agreements as discussed in Power Source Generation. The proceeds were used to service the CaliforniaPower PurchaseAgreements section on page 32.

the current maturities of certain BGE long-term debt. Our merchant energy business was not paid in full for its sales

"*BGE transferred equity associated with the generating from these plants to the two utilities from November 2000 assets to Calvert Cliffs Nuclear Power Plant, Inc. and through early April 2001. At December 31, 2001, our portion Constellation Power Source Generation. of the amount due for unpaid power sales from these utilities i The fossil fuel and nuclear fuel inventories, materials and was approximately $45 million. We recorded reserves of approx supplies, and certain purchased power contracts of BGE imately 20% of this amount.

were also assumed by these subsidiaries. These projects entered into agreements with PGE and SCE Effective July 1, 2000, BGE provides standard offer service that provide for five-year fixed-price payments averaging $53.70 to customers at fixed rates over various time periods during the per megawatt-hour plus the stated capacity payments in the transition period (July 1, 2000 to June 30, 2006) for those original Interim Standard Offer No. 4 (S04) contracts. These customers that do not choose an alternate supplier. In addition, agreements also provide for the payment of all past due the electric fuel rate was discontinued effective July 1, 2000. amounts plus interest. As of the date of this report, we have Pursuant to the Restructuring Order, Constellation Power received $28 million related to the $45 million of unpaid power Source provides BGE with the energy and capacity required to sales, of which 100% of the SCE outstanding balance was paid.

meet its standard offer service obligations for the first three years We expect to collect the remaining outstanding balance from of the transition period (July 1, 2000 to June 30, 2003). PGE within the next year.

In August 2001, following a competitive bidding process, However, as a result of ongoing litigation before the FERC BGE entered into contracts with Constellation Power Source to regarding sales into the spot markets of the California provide 90% and Allegheny Energy Supply Company, LLC to Independent System Operator (ISO) and Power Exchange, we provide the remaining 10% of the energy and capacity required may be required to pay refunds of between $3 and $4 million for BGE to meet its standard offer service requirements for the for transactions that we entered into with these entities for the final three years (July 1, 2003 to June 30, 2006) of the period between October 2000 and June 2001. While the transition period. BCE awarded these contracts primarily based process at FERC is ongoing, FERC has indicated that we will on price and access to the PJM region. The amount BGE pays have the ability to reduce the potential refund amount in order for energy and capacity does not exceed the standard offer to recover outstanding receivables we are owed. FERC also has service rates received from customers. Over the transition indicated that it will consider adjustments to the refund amount period, the standard offer service rate that BGE receives from its to the extent we can demonstrate that its refund methodology customers increases. This is offset by a corresponding decrease resulted in an overall revenue shortfall for our transactions in in the competitive transition charge BGE receives. these markets during the refund period.

Constellation Power Source obtains the energy and capacity The situation with PGE and SCE has not had a material to supply BGE's standard offer service obligations from nonreg impact on our financial results. However, we cannot provide ulated affiliates that own Calvert Cliffs Nuclear Power Plant any assurance that the events in California will not have a (Calvert Cliffs) and BGE's former fossil plants, supplemented material, adverse impact on our financial results, or that any with energy and capacity purchased from the wholesale market legislative, regulatory, or other solution enacted in California if necessary. will permit us to recover any past losses or will not have a negative effect on our business opportunities in California.

Other States We are currently leasing and supervising the construction of Several states, other than Maryland, have supported complete the High Desert project, a 750 megawatt generating facility in deregulation of the electric industry. Other states that were California. The High Desert project uses an off-balance sheet considering deregulation have slowed their plans or postponed financing structure through a special-purpose entity (SPE) that consideration. While our power marketing operation may be currently qualifies as an operating lease. The project is scheduled affected by the slow down in deregulation, the Federal Energy for completion in the summer of 2003. We signed a contract to Regulatory Commission (FERC) initiatives regarding the sell all of the plant's output to the California Department of formation of larger Regional Transmission Organizations could Water Resources on a unit contingent basis. The contract has a provide our merchant energy business other opportunities as term of eight years and three months.

Constellation Energy Group, Inc. and Subsidiaries I I

/ 27 In February 2002, the FASB proposed a new accounting Base Rate interpretation that potentially would impact the accounting for, The base rate is the rate the Maryland PSC allows BGE to but not the cash flows associated with, our High Desert charge its customers for the cost of providing them service, plus operating lease and the related SPE. Under the proposed inter a profit. BGE has both an electric base rate and a gas base rate.

pretation, we may be required to consolidate the SPE in our Higher electric base rates apply during the summer when the Consolidated Balance Sheets. We would have recorded approxi demand for electricity is higher. Gas base rates are not affected mately $221 million of development, construction, and by seasonal changes.

capitalized financing costs as an asset and the related financial BGE may ask the Maryland PSC to increase base rates from obligations as a liability in our Consolidated Balance Sheets had time to time. The Maryland PSC historically has allowed BGE we consolidated this project at December 31, 2001. to increase base rates to recover increased utility plant asset and We discuss our High Desert project in more detail in the higher operating costs, plus a profit, beginning at the time of CapitalResources section on page 43. replacement. Generally, rate increases improve our utility In February 2002, the California Department of Water earnings because they allow us to collect more revenue.

Resources filed a claim with the FERC that all long-term However, rate increases are normally granted based on historical contracts for power supply that the California Department of data, and those increases may not always keep pace with Water Resources entered into in the first quarter of 2001, which increasing costs. Other parties may petition the Maryland PSC includes the contracts related to our High Desert project, were to decrease base rates.

not just and reasonable. The California Department of Water On June 19, 2000, the Maryland PSC authorized a Resources is requesting the FERC to terminate the contracts $6.4 million annual increase in our gas base rates effective entirely or, at least, modify the prices to terms that the FERC June 22, 2000.

considers just and reasonable. Currently, we are discussing the As a result of the Restructuring Order, BGE's residential renegotiations of our contracts with the California Department electric base rates are frozen until 2006. Electric delivery service of Water Resources. We cannot estimate the timing or impact rates are frozen until 2004 for commercial and industrial of the FERC proceedings or the renegotiations of our contracts. customers. The generation and transmission components of rates are frozen for different time periods depending on the Gas Competition service options selected by those customers.

Currently, no regulation exists for the wholesale price of natural gas as a commodity, and the regulation of interstate trans Fuel Rate mission at the federal level has been reduced. All BGE gas Through June 30, 2000, we charged our electric customers customers have the option to purchase gas from other suppliers. separately for the fuel we used to generate electricity (nuclear fuel, coal, gas, or oil) and for the net cost of purchases and sales Market Risks of electricity. We charged the actual cost of these items to the The decline in both short-term and long-term market prices of customer with no profit to us. If these fuel costs went up, the electricity has had, and is expected to continue to have, a signif Maryland PSC generally permitted us to increase the fuel rate.

icant, negative impact on our financial results in certain regions Under the Restructuring Order, BGE's electric fuel rate was in which we operate or expect to operate. In addition, signif frozen until July 1, 2000, at which time the fuel rate clause was icant uncertainties exist in the competitive energy marketplace. discontinued. We deferred the difference between our actual We discuss our market risks in detail on page 44. costs of fuel and energy and what we collected from customers under the fuel rate through June 30, 2000.

Regulation by the Maryland PSC In September 2000, the Maryland PSC approved the In addition to electric restructuring which was discussed earlier, collection of the $54.6 million accumulated difference between regulation by the Maryland PSC influences BGE's businesses. our actual costs of fuel and energy and the amounts collected Under traditional rate regulation that continues after July 1, from customers that were deferred under the electric fuel rate 2000 for BGE's electric transmission and distribution, and gas clause through June 30, 2000. We collected this accumulated businesses, the Maryland PSC determines the rates we can difference from customers over the twelve-month period ended charge our customers. Prior to July 1, 2000, BGE's regulated October 2001. Effective July 1, 2000, our earnings are affected electric rates consisted primarily of a "base rate" and a "fuel by the changes in the cost of fuel and energy.

rate." Effective July 1, 2000, BGE discontinued its electric fuel We charge our gas customers separately for the natural gas rate and unbundled its rates to show separate components for they purchase from us. The price we charge for the natural gas delivery service, competitive transition charges, standard offer is based on a market-based rates incentive mechanism approved services (generation), transmission, universal service, and taxes. by the Maryland PSC. We discuss market-based rates in more The rates for BGE's regulated gas business continue to consist detail in the Gas CostAdjustments section on page 39 and in of a "base rate" and a "fuel rate." Note 1 on page 58.

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FERC Regulation-Regional Transmission Organizations actual temperature exceeds the 65 degree baseline. Heating In December 1999, FERC issued Order 2000, amending its degree days result when the average daily' actual temperature is regulations under the Federal Power Act to advance the less than the baseline.

formation of Regional Transmission Organizations (RTOs). During the cooling season, hotter weather is measured by On July 12, 2001, FERC provisionally granted RTO status more cooling degree days and results in greater demand for to PJM and ordered it to engage in mediation with the New electricity to operate cooling systems. During the heating York ISO and the New England ISO to create a business plan season, colder weather is measured by more heating degree days to form one Northeast RTO, using PJM as a platform. After and results in greater demand for electricity and gas to operate further hearings by FERC, it announced that it is re-evaluating heating systems.

its Order regarding a Northeast RTO. In the meantime, PJM is We show the number of cooling and heating degree days in exploring opportunities to expand into other regions. 2001 and 2000, the percentage change in the number of degree The creation of large RTOs could benefit our merchant days from the prior year, and the number of degree days in a energy business by allowing easier access to transmission and a "normal" year as represented by the 30-year average in the uniform rate across various regions. following table.

In addition, PJM is required to submit a filing by July 1, 30-year 2002 addressing implementation of a uniform transmission rate 2001 2000 Average by January 1, 2003. A uniform rate could expose BGE to Cooling degree days 787 736 839 higher transmission rates. Percentage change from prior year 6.9% (12.9)%

BGE, jointly with other PJM transmission owners, requested Heating degree days 4,514 4,936 4,725 rehearing and clarification from FERC on its July 12, 2001 Percentage change from prior year (8.5)% 7.7%

order regarding certain incentive rates, interconnection proce dures, and allocations of interconnection costs. FERC has not Other Factors yet issued an order on this request. Other factors, aside from weather, impact the demand for electricity and gas in our regulated businesses. These factors Weather include the "number of customers" and "usage per customer" Merchant Energy Business during a given period. We use these terms later in our discus Weather conditions in the different regions of North America sions of regulated electric and gas operations. In those sections, influence the financial results of our merchant energy business. we discuss how these and other factors affected electric and gas Weather conditions can affect the supply of and demand for sales during the periods presented.

electricity and fuels, and changes in energy supply and demand The number of customers in a given period is aflected by may impact the price of these energy commodities in both the new home and apartment construction and by the number of spot market and the forward market. Typically, demand for businesses in our service territory. Under the Restructuring electricity and its price are higher in the summer and the winter, Order, BGE's electric customers can become delivery service when weather is more extreme. Similarly, the demand for and customers only and can purchase their electricity from other price of natural gas and oil are higher in the winter. However, sources. We will collect a delivery' service charge to recover the all regions of North America typically do not experience fixed costs for the service we provide. The remaining electric extreme weather conditions at the same time. We discuss our customers will receive standard offer service from BGE at the market risk in detail on page 45. fixed rates provided by the Restructuring Order. Usage per customer refers to all other items impacting customer sales that BGE cannot be measured separately. These factors include the strength Weather affects the demand for electricity and gas for our of the economy in our service territory. When the economy is regulated businesses. Very hot summers and very cold winters healthy and expanding, customers tend to consume more increase demand. Mild weather reduces demand. Residential electricity' and gas. Conversely, during an economic downtrend, sales for our regulated businesses are impacted more by weather our customers tend to consume less electricity and gas.

than commercial and industrial sales, which are mostly affected by business needs for electricity and gas. Environmental and Legal Matters However, the Maryland PSC allows us to record a monthly You will find details of our environmental and legal matters in adjustment to our regulated gas business revenues to eliminate Note 11 on page 79 and in our most recent Annual Report on the effect of abnormal weather patterns. We discuss this further Form 10-K. Some of the information is about costs that may be in the Weather Normalizationsection on page 39. material to our financial results.

We measure the weather's effect using "degree days." The measure of degree days for a given day is the difference between Accounting Standards Adopted and Issued the average daily actual temperature and a baseline temperature We discuss recently adopted and issued accounting standards in of 65 degrees. Cooling degree days result when the average daily Note 1 on page 63.

Constellation Energy Group, Inc. and Subsidiaries I I

/ 29 Results of Operations 2001 In this section, we discuss our earnings and the factors affecting Our total net income for 2001 decreased $254.4 million, or them. We begin with a general overview, then separately discuss $1.73 per share, compared to 2000 mostly because of the net income for our operating segments. Changes in fixed following special costs in operations:

charges and income taxes are discussed in the aggregate for all "*Our merchant energy business recorded expenses of segments in the ConsolidatedNonoperatingIncome and Expenses $139.6 million after-tax, or $.87 per share, related to the section on page 41. termination of our power marketing operation's power business services agreement with Goldman Sachs.

Overview "*Our Latin American operation recognized a $28.1 million Net Income after-tax, or $.17 per share, loss on the sale of the 2001 2000 1999 Guatemalan power plant operations.

(in millions) "*We recorded costs of $64.1 million after-tax, or $.40 per Net Income Before Special Costs share, associated with our corporate-wide workforce Included in Operations: reduction program.

Merchant energy $291.2 $213.6 $ 66.6

"*Our merchant energy business recorded impairments that Regulated electric 84.5 106.5 270.0 total $30.5 million after-tax, or $.19 per share, primarily Regulated gas 38.3 30.6 33.0 due to the termination of certain planned development Other nonregulated 3.2 13.8 2.2 projects and due to a decline in value of an investment in a Net Income Before Special Costs power project.

Included in Operations 417.2 364.5 371.8 "*Our other nonregulated businesses recorded $69.7 million Special Costs Included after-tax, or $.43 per share, impairments of certain real in Operations: estate projects, senior-living facilities, and international Contract termination related assets. This was a result of our decision to sell certain non costs (139.6) core assets and accelerate the exit strategies on other assets Loss on sale of Guatemalan that we will continue to hold and own over the next operations (28.1) -

Workforce reduction costs (64.1) (4.2) several years, as well as an other than temporary decline in Impairments of domestic the value of our equity method Bolivian investment.

power projects (30.5) - (14.2) "*Our financial investments business recorded a $2.8 million Impairments of real estate, after-tax, or $.02 per share, reduction of its investment in senior-living, and an aircraft due to the decline in value of used airplanes as a international investments (69.7) - (10.3) result of the September 11, 2001 terrorist attacks and the Reduction of financial general downturn in the aviation industry.

investments (2.8) - (16.0) These decreases were partially offset by the following:

Deregulation transition cost (15.0) "*Our merchant energy business recorded in 2000 an Hurricane Floyd - (4.9) expense of $15.0 million after-tax, or $.10 per share, for a Net Income Before Extraordinary deregulation transition cost to Goldman Sachs.

Item and Cumulative Effect of "*BGE recorded an expense of $4.2 million after-tax, or $.03 Change in Accounting Principle 82.4 345.3 326.4 per share, for its employees that elected to participate in a Extraordinary Loss - - (66.3) targeted VSERP in 2000 that had a negative impact in Cumulative Effect of Change that year.

in Accounting Principle 8.5 -

"*We recorded an $8.5 million after-tax, or $.05 per share, Net Income $ 90.9 $345.3 $260.1 gain for the cumulative effect of adopting Statement of Net incomefor the periodspresented reflect a significant shfi from the regulated Financial Accounting Standard (SFAS) No. 133, electric business to the merchant energy business as a result of the transferof BGEs Accounting for Derivative Instruments and Hedging electric generation assets to nonregulatedsubsidiarieson July 1, 2000. We discuss this Activities, as amended, in the first quarter of 2001.

in more detail in Note 5 on page 69. "*Net income before special costs increased $.17 per share compared to 2000 as discussed in more detail below.

Net income before special costs was $417.2 million, or

$2.60 per share, in 2001 compared to $364.5 million, or $2.43 per share, in 2000. Net income before special costs were higher compared to 2000 mostly because BGE recorded $75.0 million pre-tax, or approximately $30 per share, of amortization expense for the reduction of our generating plants associated Constellation Energy Group, Inc. and Subsidiaries

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with the Restructuring Order in 2000 that had a negative of the deregulation of electric generation, starting July 1, 2000.

impact in that year. In addition, we had higher earnings from These decreases were offset partially by higher earnings in our our regulated gas business in 2001 mostly because of increases merchant energy and our other nonregulated businesses.

in the sharing mechanism under our gas cost adjustment clauses In 2000, net income from our merchant energy business and the increase in our base rates. These increases were offset by before special costs increased compared to 1999 because of the impact of a 6.5% annual electric residential rate reduction higher earnings in both our power marketing and generation that was effective July 1, 2000, and decreases in earnings from operations.

our other nonregulated businesses. In 2000, net income from our other nonregulated businesses Net income before special costs from our other nonregulated increased mostly because of higher earnings in our financial businesses decreased primarily due to declining equity values investments operation.

and lower gains on sales of equity securities in our financial In the following sections, we discuss our net income, investments business. including the special costs, by business segment in greater detail.

2000 Merchant Energy Business Our 2000 total net income increased $85.2 million, or $.56 per Our merchant energy business is exposed to various market share, compared to 1999 mostly because we recorded an risks as discussed further on page 45.

extraordinary charge of $66.3 million after-tax, or $.44 per We record the financial impacts of these market risks in share, associated with the deregulation of the electric generation earnings in different periods depending upon which portion of portion of our business in 1999. In addition, we recorded our merchant energy business they affect.

several special costs in 1999 that had a negative impact in that "*We record changes in the value of contracts in our power year as follows: marketing operation that are subject to mark-to-market

"*Our regulated electric business recorded $4.9 million after accounting in earnings in the period in which the change tax, or $.03 per share, of expenses related to Hurricane occurs.

Floyd. "*Prior to the settlement of the anticipated transaction being

"*Our generation operation recorded impairments of certain hedged, we record changes in the value of contracts desig power projects of $14.2 million after-tax, or $.09 per nated as cash flow hedges of our generation operations in share. other comprehensive income to the extent that the hedges

"*Our Latin American operation recorded a $4.5 million are effective. We record the effective portion of hedges in after-tax, or $.03 per share, impairment of an investment earnings in the period the settlement of the hedged trans in a power project. action occurs. We record the ineffective portion of such

"*Our financial investments business recorded a $16.0 hedges, if any, in earnings in the period in which the million after-tax, or $.11 per share, reduction of a financial change occurs.

investment. Mark-to-market accounting requires us to make estimates

"*Our real estate and senior-living facilities business recorded and assumptions using judgment in determining the fair value a $5.8 million after-tax, or $.04 per share, impairment of of our contracts and in recording revenues from those contracts.

certain senior-living facilities. We discuss the effects of mark-to-market accounting on our These were partially offset by the following special costs in revenues in the Mark-to-MarketEnergy Revenues section on operations recorded in 2000: page 32. We discuss mark-to-market accounting and the

• $15.0 million after-tax deregulation transition cost in June accounting policies for the merchant energy business further in 2000 to Goldman Sachs incurred by our power marketing the CriticalAccountingPolicies section on page 22 and in Note 1 operation to provide BGE's standard offer service require on page 58.

ments, and As discussed in the Business Environment Electric

• $4.2 million after-tax expense during the first and second Competition section on page 25, our merchant energy business quarters of 2000 for BGE employees that elected to partic was significantly impacted by the July 1, 2000 implementation ipate in a targeted VSERP of customer choice in Maryland. At that time, BGE's generating Net income before special costs was $364.5 million, or $2.43 assets became part of our nonregulated merchant energy per share, in 2000 compared to $371.8 million, or $2.48 per business, and Constellation Power Source began selling to BGE share, in 1999. Net income before special costs included in the energy and capacity required to meet its standard offer operations decreased mostly because we recognized $29.9 service obligations for the first three years (July 1, 2000 to June million, or $18.1 million after-tax, of the 6.5% annual 30, 2003) of the transition period. In August 2001, BGE residential rate reduction that was effective July 1, 2000, and we entered into a contract with Constellation Power Source to had higher interest costs in 2000 compared to 1999. We also provide 90% of the energy and capacity required for BGE to recognized $5.7 million after-tax, or $.04 per share, for contribu meet its standard offer service requirements for the final three tions to the universal service fund relating to the implementation years (July 1, 2003 to June 30, 2006) of the transition period.

Constellation Energy Group, Inc. and Subsidiaries I I

/ 31 In addition, effective July 1, 2000, the merchant energy Merchant energy revenues increased $691.0 million, business revenues include 90% of the competitive transition including $110.0 million of CTC and decommissioning charges (CTC revenues) BGE collects from its customers and revenues, in 2000 compared to 1999 related to providing BGE's the portion of BGE's revenues providing for nuclear decommis standard offer service requirements effective July 1, 2000.

sioning costs.

Other Generation Revenues Net Income Other generation revenues increased $142.2 million in 2001 as 2001 2000 1999 compared to 2000 primarily due to the construction of new (In millions) power plants and the acquisition of Nine Mile Point, as well as Revenues $1,765.5 $1,025.7 $277.3 additional sales from our existing facilities. Revenues from Operating expenses 1,082.3 586.8 151.5 peaking facilities that commenced operations during mid Workforce reduction costs 46.0 -

summer 2001 totaled $83.6 million, and revenues from Nine Contract termination related costs 224.8 Mile Point, which we acquired in November 2001, totaled Impairment losses and other costs 46.9 - 21.4

$55.2 million.

Depreciation and amortization 174.9 83.6 7.5 49.4 24.6 Additionally, sales of power from our Baltimore plants in Taxes other than income taxes Income from Operations $ 141.2 $ 330.7 $ 96.9 excess of that required to serve BGE's standard offer service

$ 93.1 $ 198.6 $ 52.4 requirements increased $51.2 million. Our generation operation Net Income also recognized a $9.5 million gain on the sale of a project Net Income Before Special Costs under development in the PJM region in March 2001.

Included in Operations $ 291.2 $ 213.6 $ 66.6

- These increases were partially offset by the following:

Workforce reduction costs (28.0)

Contract termination "* Revenues associated with the California power purchase related costs (139.6) agreements decreased $22.0 million. We discuss the Deregulation transition cost - (15.0) California power purchase agreements on page 32.

Impairment of power projects (30.5) - (14.2) "*In April 2000, our generation operation terminated an Net Income $ 93.1 $ 198.6 $ 52.4 operating arrangement and sold certain subsidiaries of Constellation Operating Services Inc. (COSI) to Orion.

Above amounts include intercompany transactions eliminatedin our Consolidated COSI ended its exclusive arrangement with Orion to FinancialStatements- Note 3 on page 67provides a reconciliation of operating results b segment to our ConsolidatedFinancialStatements. operate Orion's facilities, and Orion purchased from COSI the four subsidiary companies formed to operate power Revenues plants owned by Orion. Our generation operation recog Merchant energy revenues increased $739.8 million during nized a $13.3 million gain on this sale in 2000 which had 2001 compared to 2000 mostly due to: a positive impact on that year, and we also had lower

"*supplying BGE's standard offer service requirements for a revenues during 2001 compared to 2000 due to the sale of full year in 2001 as compared to six months in 2000, these subsidiaries.

"*higher revenues from other sales of generation, including Other generation revenues increased $47.6 million during new peaking facilities and Nine Mile Point, and 2000 compared to 1999 mostly because of the following:

"*higher mark-to-market energy revenues. "*sales of power from our Baltimore plants in excess of that Merchant energy revenues increased $748.4 million during required to serve BGE's standard offer requirements 2000 compared to 1999 mostly due to: totaled $40.7 million, and

"*providing BGE's standard offer service requirements "*our generation operation recognized a $13.3 million gain effective July 1, 2000, and on the termination of an operating arrangement and the

"*higher revenues from our generation and power marketing sale of certain subsidiaries of COSI as discussed above.

operations. These increases were partially offset by a decrease of $14.9 We discuss the revenues from our generation and power million in revenues associated with our California power marketing operations below. purchase agreements. We discuss the California power purchase agreements on page 32.

Revenues from BGE StandardOffer Service The significant decline in the long-term prices of electricity Our merchant energy business provided BGE's standard offer since early 2001 has affected, and may continue to affect, our service requirements for a full year in 2001 as compared to six facilities that have not entered into contracts for the sale of their months in 2000. As a result, merchant energy revenues generation.

increased $578.0 million in 2001, including CTC and decom Under the Restructuring Order, larger industrial customers missioning revenues that increased $74.4 million. have available standard offer service until June 30, 2002.

Beginning in July 2002, approximately 1,000 megawatts of Constellation Energy Group, Inc. and Subsidiaries

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industrial customer load will move from BGE's standard offer Mark-to-market energy revenues were as follows:

service to market-based rates. As a result, our merchant energy 2001 2000 1999 business will have an increasing amount of generating capacity (In mi/oms) that will be sold at wholesale market rates and thus be subject to New origination transactions $227.0 $158.8 $141.5 future changes in wholesale electricity prices. Refer to the Risk management activities Business Environment section on page 25 for further discussion. Realized 19.7 (57.0) 22.2 Unrealized (70.9) 49.7 (16.0)

CaliforniaPower PurchaseAgreements Total risk management Our generation operation has $296.4 million invested in 14 activities (51.2) (7.3) 6.2 operating projects of which our ownership percentage represents Total $175.8 $151.5 $147.7 146 megawatts of electricity that are sold in California to PGE and SCE under power purchase agreements called S04 agree Revenues from new origination transactions represent the ments. initial unrealized fair value of new wholesale energy transactions Under these agreements, the projects supply electricity to at the time of contract execution. Risk management revenues these utilities at variable rates. Revenues from these projects represent both realized and unrealized gains and losses from were $22.1 million in 2001 compared to $44.1 million in changes in the value of our entire portfolio. We discuss the 2000. Revenues decreased because of lower power prices in changes in origination and risk management revenues below.

California during the second half of 2001. While energy rates Constellation Power Source's mark-to-market revenues are were higher during the first half of 2001, the higher rates were influenced by our focus on serving the full electric energy and offset by reserves established for our exposure in California capacity requirements of electric utility customers. Providing during that period. utilities' full energy and capacity requirements requires greater As previously discussed in the Business Environment-Other ownership of or contractual access to power generating facilities, States section on page 26, the projects entered into agreements as opposed to merely standard products obtainable in liquid with PGE and SCE that provide for five-year fixed-price trading markets.

payments averaging $53.70 per megawatt-hour plus the stated In order to enable us to serve such customers, during 2000 capacity payments in the original S04 contracts. We expect and 2001, we obtained access to physical power by entering the revenues from these projects to be lower in 2002 compared into a portfolio of tolling arrangements and other physical to 2001. delivery energy contracts. Tolling arrangements are contracts We also describe these projects in Note 11 on page 83. which provide us the right, but not the obligation, to purchase power at a price linked to the variable cost of production, Mark-to-Market Energy Revenues including fuel. This inventory of energy supply somewhat Mark-to-market energy revenues include net gains and losses exceeded the energy demands from existing transactions and from Constellation Power Source origination and risk provides resources to enable us to close additional transactions.

management activities for which the mark-to-market method The relationship of the realized portion of revenue to total of accounting is required by Emerging Issues Task Force Issue mark-to-market energy revenue in the table above reflects the 98-10, Accountingfor Contracts Involved in Energy Trading and nature of the origination transactions which Constellation Risk ManagementActivities. We discuss the mark-to-market Power Source has executed. A significant portion of these method of accounting and Constellation Power Source's activ contracts provided for Constellation Power Source to serve ities in more detail in the CriticalAccountingPolicies section on customers' energy requirements at fixed prices that were lower page 22 and in Note 1 on page 58. in the early years of the contracts but that are expected to As a result of the nature of its operations and the use of provide increased margins and cash flows over the remaining mark-to-market accounting for certain activities, Constellation terms of the contracts. We discuss the settlement terms of our Power Source's revenues and earnings will fluctuate. We cannot contracts on the next page.

predict these fluctuations, but the impact on our revenues and Mark-to-market energy revenues increased $24.3 million earnings could be material. We discuss our market risk in more during 2001 compared to 2000 mostly because of higher detail on page 44. The primary factors that cause fluctuations in revenues from new origination transactions, partially offset by our revenues and earnings are: net losses from risk management activities. The increase in

"*the number, size, and profitability of new transactions, origination revenue reflects primarily new full-requirements load

"*the magnitude and volatility of changes in commodity serving transaction volumes, primarily in New England and prices and interest rates, and Texas which were enabled by the portfolio of physical supply

"*the number and size of our open commodity and arrangements discussed above. The increase in net losses from derivative positions. risk management activities is primarily due to decreases in both future power prices and price volatility during 2001 and costs of Constellation Energy Group, Inc. and Subsidiaries I I

/ 33 establishing hedges for new origination transactions. The Following are the primary sources of the change in net mark decrease in forward price and volatility negatively affected the to-market energy asset during 2001:

mark-to-market value of our portfolio of supply arrangements. Chance in Net Mark-to-MarketEnergfy Asset These mark-to-market losses were, however, more than offset by (In millions) mark-to-market gains in the form of new origination transac Fair value at December 31, 2000 $527.9 tions that were in part enabled by these supply arrangements. Changes in fair value recorded as revenues Mark-to-market energy revenues increased $3.8 million New origination transactions $227.0 during 2000 compared to 1999 due to increased origination Unrealized risk management revenues:

revenue, which was offset partially by net losses from risk Contracts settled (19.7) management activities. The increase in origination revenue Changes in valuation techniques 4.5 reflects new transaction volumes, primarily in New England, Unrealized changes in fair value (55.7) the Mid-Atlantic, and Texas. The net losses from risk Total unrealized risk management revenues $ (70.9) management activities resulted from realized losses in serving Total changes in fair value recorded as revenues 156.1 the initial year of long-term, fixed-price energy sales contracts as Changes in fair value recorded as operating expenses (15.0)

Net change in premiums on options (242.2) described above, substantially offset by unrealized gains on Other changes in fair value (8.4) portions of the portfolio which benefited from the increases in Fair value at December 31, 2001 $418.4 future power prices and price volatility during 2000.

Constellation Power Source's mark-to-market energy assets New origination transactions represent the initial unrealized and liabilities are comprised of a combination of derivative and non-derivative contracts. While some of these contracts fair value at the time these contracts are executed. Changes in represent commodities or instruments for which prices are valuation techniques represent improvements in the models available from external sources, other commodities and certain used to value our portfolio to reflect more accurately the contracts are not actively traded and are valued using other economic value of our contracts. Unrealized changes in fair pricing sources and modeling techniques to determine expected value represents the change in value of our unrealized mark-to market energy net asset due to changes in commodity prices, future market prices, contract quantities, or both.

the volatility of options on commodities, the time value of Mark-to-market energy assets and liabilities consisted of the following: options, and net changes in valuation allowances. Changes in fair value recorded as operating expenses represent accruals for At December 31, 2001 2000 future incremental expenses in connection with servicing origi (In millions) nation transactions. While these accruals are reductions in the Current Assets $ 398.4 S 453.1 Noncurrent Assets 1,819.8 2,069.3 fair value of the net mark-to-market energy asset, they are recorded in the income statement as expenses rather than Total Assets 2,218.2 2,522.4 revenue. The net change in premiums on options reflects a net increase in options sold during 2001. We record premiums on Current Liabilities 323.3 358.2 Noncurrent Liabilities 1,476.5 1,636.3 options purchased as an increase in the net mark-to-market energy asset and premiums on options sold as a decrease in the Total Liabilities 1,799.8 1,994.5 net mark-to-market energy asset. Prior to 2001, we had entered Net mark-to-market energy asset $ 418.4 S 527.9 into purchased option and energy tolling contracts in connection with serving our energy sales contracts. The option and tolling contracts, by their nature, exposed us to changes in the volatility of energy prices. During 2001, we sold options to reduce our exposure to option volatility.

The settlement term of the net mark-to-market energy asset and sources of fair value as of December 31, 2001 are as follows:

Settlement Term Total 2002 2003 2004 2005 2006 2007 2008-2009 Thereafter Fair Value (In millions)

Prices provided by external sources $67.0 $10.8 $25.8 $41.8 $26.8 $(0.7) S 4.0 $ 0.4 $175.9 Prices based on models 8.2 25.9 (2.4) 47.9 48.1 50.2 84.4 (19.8) 242.5 Total net mark-to-market energy asset $75.2 $36.7 $23.4 $89.7 $74.9 $49.5 $88.4 S(19.4) $418.4 Constellation Energy Group, Inc. and Subsidiaries

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Constellation Power Source manages its risk on a portfolio porate, where appropriate, option pricing models and statistical basis based upon the delivery period of its contracts and the simulation procedures. Inputs to the models include observable individual components of the risks within each contract. market prices, estimated market prices in the absence of quoted Accordingly, we record and manage the energy purchase and market prices, the risk-free market discount rate, volatility sale obligations under our contracts in separate components factors, estimated correlation of energy commodity prices, based upon the commodity (e.g., electricity or gas), the product contractural volumes, and estimated volumes for requirements (e.g., electricity for delivery during peak or off-peak hours), the contracts. Additionally, we incorporate counterparty-specific delivery location (e.g., by region), the risk profile (e.g., forward credit quality and factors for market price uncertainty and other or option), and the delivery period (e.g., by month and year). risks in our valuation. The inputs and factors used to determine Consistent with our risk management practices, we have fair value reflect management's best estimates.

presented the information in the table on the previous page The electricity, fuel, and other energy contracts held by based upon the ability to obtain reliable prices for components Constellation Power Source have varying terms to maturity, of the risks in our contracts from external sources rather than ranging from contracts for delivery the next hour to contracts on a contract-by-contract basis. Thus, the portion of long-term with terms often years or more. Because an active, liquid contracts that is valued using external price sources is classified electricity futures market comparable to that for other in the same caption as other shorter-term transactions that settle commodities has not developed, the majority of contracts used in the same period. This presentation is consistent with how we in the power marketing business are direct contracts between manage our risk, and we believe it provides the best indication market participants and are not exchange-traded or financially of the basis for the valuation of our portfolio. Since we manage settling contracts that readily can be liquidated in their entirety our risk on a portfolio basis rather than contract-by-contract, it through an exchange or other market mechanism.

is not practicable to determine separately the portion of long Consequently, Constellation Power Source and other market term contracts that is included in each valuation category. We participants generally realize the value of these contracts as cash describe the commodities, products, and delivery periods flows become due or payable under the terms of the contracts included in each valuation category in detail below. rather than through selling or liquidating the contracts The amounts for which fair value is determined using prices themselves.

provided by external sources represent the portion of forward, Consistent with our risk management practices, the amounts swap, and option contracts for which price quotations are shown in the table on the previous page as being valued using available through brokers or over-the-counter transactions. The prices from external sources include the portion of long-term term for which such price information is available varies by contracts for which we can obtain reliable prices from external commodity, region, and product. The fair values included in sources. The remaining portions of these long-term contracts this category are the following portions of our contracts: are shown in the table as being valued using models. In order to

"*forward purchases and sales of electricity during peak realize the entire value of a long-term contract in a single trans hours for delivery terms of four to six years, depending action, we would need to sell or assign the entire contract. If we upon the region, were to sell or assign any of our long-term contracts in their

"*forward purchases and sales of electricity during off-peak entirety, we may not realize the entire value reflected in the hours for delivery terms of two to four years, depending table. However, based upon the nature of the power marketing upon the region, business, we expect to realize the value of these contracts, as well

"*options for the purchase and sale of electricity for delivery as any contracts we may enter into in the future to manage our terms of up to two years, risk, over time as the contracts and related hedges settle in

"*forward purchases and sales of electric capacity for delivery accordance with their terms. We do not expect to realize the terms of up to two years, value of these contracts and related hedges by selling or

"*forward purchases and sales of natural gas and oil for assigning the contracts themselves in total.

delivery terms of up to four years, and The fair values in the table represent expected future cash

"*options for the purchase and sale of natural gas and oil for flows based on the level of forward prices and volatility factors delivery terms of up to two years. as of December 31, 2001. These amounts do not represent the The remainder of the net mark-to-market energy asset is contractual maturities and could change significantly as a result valued using models. The portion of contracts for which such of future changes in these factors. Additionally, because the techniques are used includes standard products for which depth and liquidity of the power markets varies substantially external prices are not available and customized products which between regions and time periods, the prices used to determine are valued using modeling techniques to determine expected fair value could be affected significantly by the volume of trans future market prices, contract quantities, or both. actions executed. Constellation Power Source's management Modeling techniques include estimating the present value of uses its best estimates to determine the fair value of commodity cash flows based upon underlying contractual terms and incor- and derivative contracts it holds and sells. These estimates Constellation Energy Group, Inc. and Subsidiaries I

/ 35 consider various factors including closing exchange and over the impact on our financial results of any additional security the-counter price quotations, time value, volatility factors, and measures that may be required by the NRC.

credit exposure. However, it is possible that future market prices could vary from those used in recording mark-to-market energy Extended Nuclear Outages assets and liabilities, and such variations could be material. Our merchant energy business will experience extended outages at Calvert Cliffs to replace the steam generators during the 2002 Operating Expenses refueling outage for Unit 1 and during the 2003 refueling Merchant energy operating expenses increased $495.5 million outage for Unit 2. As a result of the extended outages, we expect during 2001 compared to 2000 mostly because of the lower annual revenues and higher annual operating costs for following: each extended outage.

"*Fuel and purchased energy costs increased $291.5 million and operations and maintenance costs increased $236.7 Workforce Reduction Costs, Contract Termination Related million. These increases reflect a full year's operation of the Costs, and Impairment Losses and Other Costs generation plants that were transferred from BGE effective As previously discussed in the Events of 2001 section on page July 1, 2000, as well as, the added operations of the new 22, our merchant energy business recognized the following:

peaking facilities and Nine Mile Point. The fuel cost * $46.0 million, or $.17 per share, of expenses associated increase also reflects higher fuel prices for generating with our workforce reduction efforts, electricityý Coal prices increased during 2001, and we * $224.8 million, or $.87 per share, of expenses related to expect to incur additional costs in the future to operate the termination of the power business services agreement our coal generating facilities due to higher prices. with Goldman Sachs,

"*Power marketing operating expenses associated with the

• a $40.8 million, or $.16 per share, impairment of certain growth of the operation increased $31.6 million. planned development projects that were terminated, and These increased costs were partially offset by lower fees

• a $6.1 million, or $.03 per share, loss on the impairment earned by Goldman Sachs at our power marketing operation of a power project.

due to the termination of the power business services agreement As a result of our workforce reduction efforts, our merchant in October 2001. The Goldman Sachs fees were $28.9 million energy business expects to generate annual savings of approxi in 2001, $81.3 million in 2000, and $31.8 million in 1999. mately $24 million.

The amount of fees for 2000 includes the $24.0 million, or In 1999, our generation operation recorded a $21.4 million,

$. 10 per share, deregulation transition cost as discussed below. or $.09 per share, write-off of two geothermal power projects, These fees will not be incurred in the future due to the termi which had a negative impact in that year.

nation of the power business services agreement with Goldman We discuss these workforce reduction costs, contract termi Sachs. In addition, COSI had lower operating expenses due to nation related costs, and impairment losses and other costs the sale of certain subsidiaries to Orion, as previously discussed. further in Note 2 on page 64.

Operating expenses increased $435.3 million in 2000 compared to 1999 mostly because of three factors: Depreciation and Amortization Expense

" an increase of $191.6 million in fuel costs and $157.2 Merchant energy depreciation and amortization expense million in operations and maintenance costs associated increased $91.3 million in 2001 compared to 2000 mostly with the generation plants that were transferred from BGE because 2001 includes a full year of expenses associated with effective July 1, 2000, the generation plants that were transferred from BGE effective

" an increase in Goldman Sachs fees of $49.5 million, July 1, 2000. Additionally, 2001 expenses include depreciation including the $24.0 million deregulation transition cost and amortization associated with the new peaking facilities and incurred by our power marketing operation to provide Nine Mile Point.

BGE's standard offer service requirements, and Merchant energy depreciation and amortization expense

"*a $6.2 million increase in power marketing operating increased $76.1 million in 2000 compared to 1999 mostly expenses associated with the growth of the operation. because of $73.8 million of expenses associated with the In light of the events of September 11, 2001, we have taken generation plants that were transferred from BGE effective additional security measures at our nuclear facilities. While we July 1, 2000.

anticipate continuing to incur additional security related costs at our nuclear facilities, we do not expect that these costs will be Taxes Other than Income Taxes material. However, the Nuclear Regulatory Commission (NRC) Merchant energy taxes other than income taxes increased in currently is evaluating additional security measures that may be 2001 and 2000 compared to their respective prior year mostly required at nuclear facilities. At this time, we cannot determine because of taxes other than income taxes associated with the generation plants that were transferred from BGE effective July 1, 2000.

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Regulated Electric Business Electric System Sales Volumes As previously discussed, our regulated electric business was "Electric system sales volumes" are sales to customers in BGE's significantly impacted by the July 1, 2000 implementation of service territory at rates set by the Maryland PSC. As part of the customer choice. These changes include BGE's generating assets Restructuring Order, the rates received from customers under and related liabilities becoming part of our nonregulated the standard offer service increase over the transition period as merchant energy business on that date. discussed further in the Business Environment-Electric Competition section beginning on page 25. These sales do not Net Income include interchange sales and sales to others.

2001 2000 1999 The percentage changes in our electric system sales volumes, (In millions) by type of customer, in 2001 and 2000 compared to the Electric revenues $2,040.0 $2,135.2 S2,260.0 respective prior year were:

Electric fuel and 2001 2000 purchased energy 1,192.8 870.7 487.7 Operations and maintenance Residential 0.3% 2.9%

258.7 447.2 629.6 Workforce reduction costs 55.7 7.0 Commercial 0.7 3.5 Depreciation and amortization 173.3 319.9 376.4 Industrial (0.7) 2.9 Taxes other than income taxes 139.5 157.8 188.9 Income from Operations $ 220.0 $ 332.6 $ 577.4 In 2001, we sold about the same amount of electricity to all customer classes compared to 2000 due primarily to milder Net Income Before Extraordinary Item winter weather offset by an increased number of customers.

$ 50.9 $ 102.3 $ 265.1 Extraordinary loss - - (66.3) In 2000, we sold more electricity to residential customers Net Income $ 50.9 S 102.3 $ 198.8 compared to 1999 due to colder winter weather, higher usage per customer, and an increased number of customers, offset Net Income Before Special Costs partially by mild summer weather. We sold more electricity to Included in Operations commercial customers mostly due to higher usage per customer and Extraordinary Item $ 84.5 $ 106.5 S 270.0 Workforce reduction costs (33.6) (4.2) and an increased number of customers. We sold more electricity, Hurricane Floyd (4.9) to industrial customers due to higher usage by Bethlehem Steel Extraordinary loss - - (66.3) and an increased number of customers, offset partially by lower Net Income $ 50.9 $ 102.3 $ 198.8 usage by other industrial customers. Usage was higher at Bethlehem Steel in 2000 as a result of a 1999 shut down for a Above amounts include intercompany transactionselimninted in our Consolidated FinancialStatements. Note 3 on page 67provides i reconciliationof operating planned upgrade to their facilities that temporarily reduced their results b- segnent to our ConsolidatedFinancialStatements. electricity consumption in that year.

Electric Revenues Rates The changes in electric revenues in 2001 and 2000 compared Prior to July 1, 2000, our rates primarily consisted of an electric to the respective prior year were caused by: base rate and an electric fuel rate. Effective July 1, 2000, BGE discontinued its electric fuel rate and unbundled its rates to 2001 2000 show separate components for delivery service, transition (In millions)

Electric system sales volumes $ 2.8 S 40.9 charges, standard offer services (generation), transmission, Rates (79.3) (119.9) universal service, and taxes. BGE's rates also were frozen in total Fuel rate surcharge 30.5 12.6 except for the implementation of a residential base rate Total change in electric revenues reduction totaling approximately $54 million annually. In from electric system sales (46.0) (66.4) addition, 90% of the CTC revenues BGE collects and the Interchange and other sales (53.8) (58.3) portion of its revenues providing for decommissioning costs, are Other 4.6 (0.1) included in revenues of the merchant energy business effective Total change in electric revenues $(95.2) $(124.8) July 1, 2000.

Rate revenues decreased in 2001 compared to 2000 mostly due to:

• the 6 .5% annual residential rate reduction of $17.6 million recorded through June 30, 2001, and

• $74.4 million of revenues that were transferred to the merchant energy business discussed above.

Constellation Energy Group, Inc. and Subsidiaries I I

/ 37 These decreases were partially offset by the increase in the Actual Costs standard offer service rate that BGE charges its customers and As discussed in the Business Environment Electric Competition other net impacts of the rate restructuring discussed above. section on page 25, effective July 1, 2000, BGE transferred its Rate revenues decreased in 2000 compared to 1999 mostly generating assets to, and began purchasing substantially all of because of the $29.9 million decrease caused by the 6.5% the energy and capacity required to provide electricity to annual residential rate reduction, and the $110.0 million standard offer service customers from, the merchant energy transfer of revenues to the merchant energy business. This was business.

offset partially by higher fuel rate revenues during the first half Our actual costs of fuel and purchased energy increased in of 2000. 2001 compared to 2000 mostly because of the deregulation of electric generation. The higher amount BGE paid for purchased Fuel Rate Surcharge energy from our merchant energy business is offset by the In September 2000, the Maryland PSC approved the collection absence of $206.4 million in 2001 and $191.6 million in 2000 of the $54.6 million accumulated difference between our actual in fuel costs, and lower operations and maintenance, depreci costs of fuel and energy and the amounts collected from ation, taxes, and other costs at BGE as a result of no longer customers that were deferred under the electric fuel rate clause owning and operating the transferred electric generation plants.

through June 30, 2000. We discuss this further in the Electric Prior to July 1, 2000, BGE's purchased fuel and energy costs Fuel Rate Clause section below. only included actual costs of fuel to generate electricity (nuclear fuel, coal, gas, or oil) and electricity we bought from others.

Interchange and Other Sales "Interchange and other sales" are sales in the PJM energy Electric Fuel Rate Clause market and to others. PJM is a RTO/ISO that also operates a Prior to July 1, 2000, we deferred (included as an asset or regional power pool with members that include many wholesale liability on the Consolidated Balance Sheets and excluded from market participants, as well as BGE and other utility the Consolidated Statements of Income) the difference between companies. Prior to the implementation of customer choice, our actual costs of fuel and energy and what we collected from BGE sold energy to PJM members and to others after it had customers under the fuel rate in a given period. Effective July 1, satisfied the demand for electricity in its own system. 2000, the fuel rate clause was discontinued under the terms of Effective July 1, 2000, BGE no longer engages in inter the Restructuring Order. In September 2000, the Maryland change sales, and these activities are included in our merchant PSC approved the collection of the $54.6 million accumulated energy business, which resulted in a decrease in interchange and difference between our actual costs of fuel and energy and the other sales for 2001 and 2000 compared to their respective amounts collected from customers that were deferred under the prior year. In addition, BGE had lower interchange and other electric fuel rate clause through June 30, 2000. We collected this sales during the first half of 2000 when increased demand for accumulated difference from customers over the twelve-month system sales reduced the amount of energy BGE had available period ended October 2001.

for off-system sales.

Electric Operationsand MaintenanceExpenses Electric Fuel and PurchasedEnergy Expenses Regulated electric operations and maintenance expenses decreased $188.5 million during 2001 compared to 2000 2001 2000 1999 mostly because effective July 1, 2000, costs of $194.7 million (In millions) were no longer incurred by this business segment. These costs Actual costs $1,150.5 $868.0 $558.0 were associated with the electric generation assets that were Net recovery (deferral) transferred to the merchant energy business.

of costs under electric Regulated electric operations and maintenance expenses fuel rate clause 42.3 2.7 (70.3) decreased $182.4 million during 2000 compared to 1999 mostly because effective July 1, 2000, $157.2 million of costs were no Total electric fuel and longer incurred by this business segment. These costs were purchased energy, associated with the electric generation assets that were transferred expenses $1,192.8 $870.7 $487.7 to the merchant energy business. In addition, 1999 operations and maintenance expenses included costs for system restoration activities related to Hurricane Floyd and a major winter ice storm, and costs associated with the preparation for the year 2000 (Y2K). These costs had a negative impact in that year.

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Workforce Reduction Costs Regulated Gas Business In 2001, BGE's electric business recognized $55.7 million, or Net Income

$.21 per share, of expenses associated with our workforce 2001 2000 1999 (In mih'ions) reduction efforts. As a result of our workforce reduction efforts, our regulated electric business expects to generate annual Gas revenues $680.7 $611.6 $488.1 savings of approximately $36 million. In 2000, BGE's electric Gas purchased for resale 401.3 350.6 233.8 Operations and maintenance 104.3 100.6 97.7 business recognized $7.0 million, or $.03 per share, of expenses Workforce reduction costs 1.3 -

for employees that elected to participate in a targeted VSERP Depreciation and amortization 47.7 46.2 44.9 that had a negative impact in that year. We discuss these Taxes other than income taxes 34.3 34.8 34.5 programs further in Note 2 on page 64.

Income from Operations $ 91.8 $ 79.4 $ 77.2 Net Income $ 37.5 $ 30.6 $ 33.0 Electric Depreciationand Amortization Expense Regulated electric depreciation and amortization expense Net Income Before Special Costs decreased $146.6 million during 2001 compared to 2000 Included in Operations $ 38.3 $ 30.6 $ 33.0 Workforce reduction costs (0.8) -

mostly due to:

• the absence of $75.0 million of amortization expense Net Income $ 37.5 $ 30.6 $ 33.0 recorded in 2000 associated with the $150 million Above amounts include intercompany transactionseliminated in our Consolidated FinancialStatements. Note 3 on page 67provides a reconciliationof operating reduction of our generating plants provided for in the results ly segment to our ConsolidatedFinancialStatements.

Restructuring Order, and

• $75.1 million of expenses associated with the transfer of Net income from our regulated gas business increased during the generation assets to the merchant energy business 2001 compared to 2000 mostly due to the sharing mechanism effective July 1, 2000.

under our gas cost adjustment clauses and the increase in our Regulated electric depreciation and amortization expense base rates.

decreased $56.5 million during 2000 compared to 1999 mostly Net income from the regulated gas business decreased during because of the absence of $73.8 million of depreciation and 2000 compared to 1999 mostly due to a slight increase in amortization expense associated with the transfer of the gener operations and maintenance and depreciation expenses partially ation assets. This decrease was offset partially by more electric offset by an increase in our base rates.

plant in service and higher amortization associated with All BGE customers have the option to purchase gas from regulatory assets.

other suppliers. To date, customer choice has not had a material effect on our, or BGE's, financial results.

Electric Taxes Other Than Income Taxes Regulated electric taxes other than income taxes decreased Gas Revenues

$18.3 million during 2001 compared to 2000 mostly due to The changes in gas revenues in 2001 and 2000 compared to the the absence of taxes other than income taxes associated with the respective prior year were caused by:

generation assets that were transferred to the merchant energy business effective July 1, 2000 partially offset by fewer tax 2001 2000 (In millions) credits.

Gas system sales volumes $(3.4) $ 34.5 Regulated electric taxes other than income taxes decreased Base rates 3.3 2.7

$31.1 million during 2000 compared to 1999. This was mostly Weather normalization 11.9 (26.7) due to two factors: Gas cost adjustments 43.6 54.7

"*regulated electric taxes other than income taxes reflect the Total change in gas revenues absence of $23.8 million of taxes other than income taxes from gas system sales 55.4 65.2 associated with the generation assets that were transferred Off-system sales 12.5 58.1 to the merchant energy business effective July 1, 2000, and Other 1.2 0.2

"*comprehensive changes to the tax laws. Total change in gas revenues $69.1 $123.5 The comprehensive tax law changes are discussed further in Note 5 on page 69.

Constellation Fnergy Group, Inc. andSubsidiaries I i

/ 39 Gas System Sales Volumes market-based rates incentive mechanism. These provisions The percentage changes in our gas system sales volumes, by require that BGE secure fixed-price contracts for at least 10%,

type of customer, in 2001 and 2000 compared to the respective but not more than 20%, of forecasted system supply require prior year were: ments for the November through March period. These fixed price contracts are not subject to sharing under the market 2001 2000 based rates incentive mechanism. We do not expect these Residential (7.8)% 13.0%

changes to have a material impact on our financial results.

Commercial 3.5 12.8 Delivery service customers, including Bethlehem Steel, are Industrial (25.2) (2.1) not subject to the gas cost adjustment clauses because we are not selling gas to them. We charge these customers fees to We sold less gas to residential customers during 2001 recover the fixed costs for the transportation service we provide.

compared to 2000 mostly due to milder winter weather and These fees are the same as the base rate charged for gas sales and lower usage per customer partially offset by an increased are included in gas system sales volumes.

number of customers. We sold more gas to commercial Gas cost adjustment revenues increased during 2001 customers mostly due to higher usage per customer. We sold compared to 2000 mostly because the gas we sold to non less gas to industrial customers mostly because of lower usage by delivery service customers was at a higher price partially offset Bethlehem Steel and other industrial customers due to their by less gas sold. In the first half of 2001, the revenue increase switching to lower cost alternative fuel sources and lower reflects the significant increase in natural gas prices.

business needs related to the general downturn in the economy Gas cost adjustment revenues increased during 2000 partially offset by an increased number of customers.

compared to 1999 mostly because we sold more gas at a higher We sold more gas to residential and commercial customers price. The revenue increase reflects the significant increase in during 2000 compared to 1999 due to higher usage per natural gas prices.

customer, colder weather, and an increased number of customers. We sold less gas to industrial customers mostly Off-System Sales because of lower usage by Bethlehem Steel and other industrial Off-system gas sales are low-margin direct sales of gas to customers partially offset by an increased number of customers. wholesale suppliers of natural gas outside our service territory.

Off-system gas sales, which occur after we have satisfied our Base Rates customers' demand, are not subject to gas cost adjustments. The Base rate revenues increased during 2001 and 2000 compared Maryland PSC approved an arrangement for part of the margin to the respective prior year mostly because the Maryland PSC from off-system sales to benefit customers (through reduced authorized a $6.4 million annual increase in our base rates costs) and the remainder to be retained by BGE (which benefits effective June 22, 2000.

shareholders).

Revenues from off-system gas sales increased during 2001 Weather Normalization compared to 2000 mostly because the gas we sold off-system The Maryland PSC allows us to record a monthly adjustment was at a higher price partially offset by less gas sold. In the first to our gas revenues to eliminate the effect of abnormal weather half of 2001, the revenue increase reflects the significant increase patterns on our gas system sales volumes. This means our in natural gas prices.

monthly gas revenues are based on weather that is considered "normal" for the month and, therefore, are not affected by Revenues from off-system gas sales increased during 2000 compared to 1999 mostly because we sold more gas off-system actual weather conditions.

at significantly higher prices.

Gas Cost Adjustments Gas PurchasedForResale Expenses We charge our gas customers for the natural gas they purchase Actual costs include the cost of gas purchased for resale to our from us using gas cost adjustment clauses set by the Maryland customers and for off-system sales. Actual costs do not include PSC as described in Note 1 on page 58. However, under the cost of gas purchased by delivery service customers.

market-based rates, our actual cost of gas is compared to a Our gas costs increased during 2001 compared to 2000 market index (a measure of the market price of gas in a given mostly because gas we purchased was at a higher price partially period). The difference between our actual cost and the market offset by less gas purchased for both system and off-system sales.

index is shared equally between shareholders and customers.

Our gas costs increased during 2000 compared to 1999 mostly The shareholders' portion increased $3.6 million during 2001 because we bought more gas for both system and off-system compared to 2000. Effective November 2001, the Maryland sales, and all of the gas purchased was at a higher price due to PSC approved an order that modifies certain provisions of the the significant increase in natural gas prices during 2000.

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Other Gas Operating Expenses of our senior-living facilities in 2002 and accelerate the exit Other gas operating expenses were about the same during 2001 strategies for two other real estate projects that we will and 2000 compared to the respective prior year. continue to hold and own over the next several years. We As a result of our workforce reduction efforts, our regulated also decided to accelerate the exit strategy for the investment gas business expects to generate annual savings of approximately in a distribution company in Panama and expect to

$12 million. The cost of these programs was deferred as a complete the sale by mid-to-late 2003. Finally, there was an regulatory asset. See Note 6 on page 71. other than temporary decline in value in our equity method Bolivian investment due to a deterioration in our Other Nonregulated Businesses investment's position in the Bolivian capacity market.

Net Income mOur financial investments business recorded a $2.8 million 2001 2000 1999 after-tax, or $.02 per share, reduction of its investment in (In millions) an aircraft due to the decline in value of used airplanes as a Revenues $602.1 $713.3 $848.4 result of the September 11, 2001 terrorist attacks and the Operating expenses 510.7 588.8 771.5 general downturn in the aviation industry.

Workforce reduction costs 2.7 - We discuss these special costs further in Note 2 on page 65.

Impairment losses and other costs 155.2 - 42.9 In addition, our financial investments business had lower Depreciation and amortization 23.2 20.3 21.0 earnings due to declining equity values and lower gains on sales Taxes other than income taxes 3.4 4.3 3.9 of equity securities, partially offset by an $8.5 million after-tax, (Loss) Income from Operations $ (93.1) $ 99.9 $ 9.1 or $.05 per share, gain for the cumulative effect of adopting Net (Loss) Income Before SFAS No. 133 in the first quarter of 2001. The gains on sales of Cumulative Effect of Change securities include a $9.0 million after-tax gain on the sale of one in Accounting Principle $ (99.1) $ 13.8 $ (24.1) million shares of the Orion investment in 2001 and a $9.5 Cumulative Effect of Change million after-tax gain on the sale of two million shares of our in Accounting Principle 8.5 Orion investment in 2000.

Net (Loss) Income $ (90.6) $ 13.8 $ (24.1) Net income from our other nonregulated businesses Net Income Before Special Costs increased during 2000 compared to 1999 mostly because of Included in Operations $ 3.2 $ 13.8 S 2.2 better market performance of certain of our financial invest Workforce reduction costs (1.7) - ments including the sale of certain equity securities. In addition, Loss on sale of Guatemalan in 1999, we reduced the values of a financial investment, our operations (28.1) investment in an electric generating company in Bolivia, and Impairment of real estate, certain senior-living facilities, which had negative impacts in senior-living, and inter national investments (69.7) that year, as discussed in more detail in Note 2 on page 66.

- (10.3)

Reduction of financial These increases were offset partially by lower earnings from our investment (2.8) - (16.0) Latin American operation primarily due to increased operating Net (Loss) Income Before Cumulative expenses in Guatemala in 2000.

Effect of Change in As previously discussed in the Events of2001 section, we Accounting Principle (99.1) 13.8 (24.1) decided to sell certain non-core assets and accelerate the exit Cumulative Effect of Change strategies on other assets that we will continue to hold and own in Accounting Principle 8.5 over the next several years. These assets include approximately Net (Loss) Income $ (90.6) $ 13.8 S(24.1) 1,300 acres of land holdings in various stages of development located in seven sites in the central Maryland region, an Above amounts include intercompany transactionseliminated in our Consolidated FinancialStatements. Aote 3 on page 67provides a reconciliationof operating operating waste water treatment plant located in Anne Arundel results bysegment to our ConsolidatedFinancialStatements. County, Maryland, all of our 18 senior-living facilities, and certain international power projects. While our intent is to Net income from our other nonregulated businesses dispose of these assets, market conditions and other events decreased during 2001 compared to 2000 mostly because of the beyond our control may affect the actual sale of these assets. In following items: addition, a future decline in the fair value of these assets could

"*Our Latin American operations recorded a loss of $28.1 result in additional losses.

million after-tax, or $.17 per share, on the sale of our Our remaining projects are partially or substantially Guatemalan operations. developed. Our strategy is to hold and in some cases further

"*We recorded $69.7 million after-tax, or $.43 per share, in develop these projects to increase their value. However, if we impairments of certain non-core assets. We decided to sell were to sell these projects in the current market, we may have six real estate projects without further development and all losses that could be material, although the amount of the losses is hard to predict.

Constellation Energy Group, Inc. andSubsidiaries I I

/41 Consolidated Nonoperating Income and Expenses Fixed Charges Income Taxes Total fixed charges decreased $32.6 million during 2001 The differences in income taxes result from a combination of compared to 2000 mostly because of lower interest rates and the changes in income and the effective tax rate. We include an higher capitalized interest associated with our construction of analysis of the changes in the effective tax rate in our new generating facilities. These decreases were offset partially by Consolidated Statements of Income Taxes on page 56.

a higher average level of debt outstanding.

Fixed charges increased $16.4 million during 2000 compared to 1999 mostly because we had more debt outstanding.

Financial Condition Cash Flows its ratings of Constellation Energy. Standard & Poors Rating Cash provided by operations was $573.3 million in 2001 Group downgraded Constellation Energy's commercial paper compared to $850.9 million in 2000 and $679.0 million from A-I to A-2 and senior unsecured debt from A- to BBB+.

in 1999. In addition, Moody's Investors Service downgraded Cash used in investing activities was $1,472.7 million in Constellation Energy's commercial paper from P-I to P-2 and 2001 compared to $1,106.5 million in 2000 and $615.1 senior unsecured debt from A3 to Baal. All Constellation million in 1999. The increase in 2001 compared to 2000 was Energy ratings have stable outlooks.

mostly due to increased purchases of property, plant and Moody's Investors Service and FitchRatings recently affirmed equipment and other capital expenditures including $382.7 the ratings of BGE. Standard & Poors Rating Group million relating to the net cash paid for the acquisition of Nine downgraded BGE commercial paper from A-I to A-2, senior Mile Point. The increase in 2000 compared to 1999 was mostly unsecured debt from A to BBB+, mortgage bonds from AA- to due to substantial increases in our merchant energy capital A, and Trust Originated Preferred Securities and Preference expenditures to support our construction program. Stock from A- to BBB. All BGE ratings have stable outlooks.

Cash provided by financing activities was $789.1 million in At the date of this report, our credit ratings were as follows:

2001 compared to $345.6 million in 2000 and cash used in Standard

& Poors Moody's financing activities of $144.9 million in 1999. The increase in Rating Investors Fitch 2001 compared to 2000 was mostly due to increased proceeds Group Service Ratings from the issuance of common stock, an increase in proceeds Constellation Energy from the net issuance of short-term borrowings, and a $130.0 Commercial Paper A-2 P-2 F-2 million decrease in common stock dividends paid. These items Senior Unsecured Debt BBB+ Baa I A were partially offset by the issuance of less long-term debt and higher repayments of our long-term debt. The increase in 2000 BGE compared to 1999 was mostly because we issued more long Commercial Paper A-2 P-1 F-1 term debt and common stock. This was offset partially by an Mortgage Bonds A A] A+

increase in net maturities of short-term borrowings, and we Senior Unsecured Debt BBB+ A2 A repaid more long-term debt. Trust Originated Preferred Securities and Preference Stock BBB Baal A-Security Ratings Independent credit-rating agencies rate Constellation Energy's and BGE's fixed-income securities. The ratings indicate the agencies' assessment of each company's ability to pay interest, Available Sources of Funding distributions, dividends, and principal on these securities. These As previously discussed in the Events of2001 section, we ratings affect how much it will cost each company to sell these decided to sell certain non-core assets to focus on our core securities. The better the rating, the lower the cost of the strategies. We expect to use the proceeds from these sales to securities to each company when they sell them. The factors reduce our debt and fund our merchant energy business. We that credit rating agencies consider in establishing Constellation continuously monitor our liquidity requirements and believe Energy's and BGE's credit ratings include cash flows, liquidity, that our facilities and access to the capital markets provide and the amount of debt as a component of total capitalization. sufficient liquidity to meet our business requirements. We All three rating agencies recently completed reviews of discuss our available sources of funding in more detail on Constellation Energy's and BGE's ratings. FitchRatings affirmed the next page.

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ConstellationEnergy Actual requirements may vary from the estimates included in Constellation Energy has a commercial paper program where it the table below because of a number of factors including:

can issue short-term notes to fund its subsidiaries. To support "*regulation, legislation, and competition, its commercial paper program, Constellation Energy maintains "*BGE load requirements, two 364-day revolving credit agreements totaling $2.9 billion "*environmental protection standards, maturing in June 2002, as well as a $188.5 million multi-year "*the type and number of projects selected for construction revolving credit facility. Two of these facilities can also issue or acquisition, letters of credit. As of December 31, 2001, Constellation "*the effect of market conditions on those projects, Energy had $246 million in outstanding letters of credit and "*the cost and availability of capital, and

$955 million of outstanding commercial paper which results in "*the availability of cash from operations.

approximately $1.8 billion of unused credit facilities. Our estimates are also subject to additional factors. Please see Constellation Energy also has access to interim lines of credit as the ForwardLooking Statements section on page 17.

required from time to time to support its outstanding Effective July 1, 2000, we transferred all of BGE's generation commercial paper. We expect to refinance the majority of our assets to nonregulated subsidiaries of Constellation Energy. The outstanding short-term debt during the first half of 2002 with discussion and table for capital requirements below include long-term debt. these generation assets as part of the utility's regulated electric business through June 30, 2000. After that date, the capital BGE requirements are included in the merchant energy business.

BGE maintains $168.0 million in annual committed bank lines of credit and has $75.0 million in bank revolving credit agree 1999 2000 2001 2002 2003 ments to support the commercial paper program. As of (Zn millions.)

December 31, 2001, BGE had no outstanding commercial Nonregulated Capital Requirements:

paper, which results in $243.0 million in unused credit facil Merchant Energy ities. BGE also has access to interim lines of credit as required Construction program S 86 $ 537 S 697 $152 $

from time to time to support its outstanding commercial paper Steam generators - 21 53 91 65 Nine Mile Point acquisition - - 771 -

and maintains a program to sell receivables up to $25 million.

Environmental controls - 45 89 69 16 Continuing requirements Other NonregulatedBusinesses (including nuclear fuel) 77 96* 205 243 199 BGE Home Products & Services maintains a program to sell Total Merchant Energy receivables up to $50 million. ComfortLink has a revolving capital requirements 163 699 1,815 555 280 credit agreement totaling $50 million to provide liquidity for Other Nonregulated short-term financial needs. capital requirements 115 131 35 39 34 If we can get a reasonable value for our remaining real estate Total Nonregulated projects and other investments, additional cash may be obtained capital requirements 278 830 1,850 594 314 by selling them. Our ability to sell or liquidate assets will depend on market conditions, and we cannot give assurances Utility Capital Requirements:

that these sales or liquidations could be made. Regulated electric Generation Capital Resources (including nuclear fuiel) 117 73 - -

Our business requires a great deal of capital. Our actual consoli Steam generators 34 13 - -

Environmental controls 31 17 - -

dated capital requirements for the years 1999 through 2001, Transmission and along with the estimated annual amounts for the years 2002 distribution 185 187 180 174 174 through 2003, are shown in the table below.

Total regulated electric 367 290 180 174 174 We will continue to have cash requirements for:

Regulated gas 69 60 59 56 56

"*working capital needs including the payments of interest, Total Utility distributions, and dividends, capital requirements 436 350 239 230 230

"*capital expenditures, and Total capital

"*the retirement of debt and redemption of preference stock. requirements $714 $1,180 $2,089 $824 $544 Capital requirements for 2002 through 2003 include estimates of spending for existing and anticipated projects. We "Effectiveijuly 1, 2000, includes $44.6 millionfrr electricgeneration and nuclear continuously review and modify those estimates. frel frmerly partof BGEi regulated electric business.

Constellation Energy Group, Inc. and Subsidiaries I I

/ 43 Capital Requirements project; however, this may vary based on the ultimate cost of Merchant Energy Business construction and interest incurred during the construction Our merchant energy business will require additional funding period.

for constructing planned power projects and growing its power marketing operation. These capital requirements include: Regulated Electric and Gas m Construction expenditures for approximately 2,900 Regulated electric and gas construction expenditures primarily megawatts of natural gas-fired peaking and combined cycle include new business construction needs and improvements to production facilities in various regions of North America existing facilities.

under construction.

m Cost for replacing the steam generators at Calvert Cliffs. Funding for Capital Requirements In March 2000, we received a license extension from the Merchant Energy Business NRC that extends Calvert Cliffs' operating licenses to Funding for the expansion of our merchant energy business is 2034 for Unit 1 and 2036 for Unit 2. Replacement of the expected from internally generated funds, commercial paper steam generators will allow us to operate these units issuances, issuances of long-term debt and equity, leases, and through our operating license periods. We expect the other financing instruments issued by Constellation Energy and steam generator replacement to occur during the 2002 its subsidiaries. Specifically related to the Nine Mile Point refueling outage for Unit 1 and during the 2003 refueling acquisition, approximately one-half of the purchase price was outage for Unit 2. paid in November 2001, and the remainder is being financed m Construction expenditures for improvements to generating through the sellers in a note to be repaid over five years with an plants, including costs of complying with Environmental interest rate of 11.0%. This note may be prepaid at any time Protection Agency (EPA), Maryland and Pennsylvania without penalty. We closed the transaction using existing credit nitrogen oxides emissions (NOx) regulations. We discuss facilities. In addition, we also used existing credit facilities to the NOx regulations and timing of expenditures in Note pay Goldman Sachs a total of $355 million. This represented 11 on page 79. $196.7 million to terminate the power business services The above table does not include the financing for the High agreement with our power marketing operation and $159 Desert 750 megawatt gas-fired generation project in California, million previously recognized as a payable for services rendered.

which is under an operating lease with a term through February The projects that our merchant energy business develops 2006. As an operating lease, we do not record any assets or debt typically require substantial capital investment. Most of the associated with the project in our Consolidated Balance Sheets. projects recently constructed or currently under construction We are leasing the project and supervising its construction. are funded through corporate borrowings by Constellation Under the terms of the lease, we are required to make Energy. Certain other projects in which we have an interest are payments that represent all or a portion of the lease balance if financed primarily with non-recourse debt that is repaid from one of the following events occurs: termination of construction the project's cash flows. This debt is collateralized by interests in prior to completion or our default under the lease. the physical assets, major project contracts and agreements, cash Under certain circumstances, we may be required to either accounts and, in some cases, the ownership interest in that post cash collateral equal to the outstanding lease balance or we project.

may elect to purchase the property for the outstanding lease Longer term, we expect to fund our growth and operating balance. At any time during the term of the lease we have the objectives primarily with internally generated funds supple right to pay off the lease and acquire the asset from the lessor. mented, if necessary, by a mixture of debt and equity with an At December 31, 2001, the outstanding lease balance plus other overall goal of maintaining an investment grade credit profile.

committed expenses was $271.2 million.

At the conclusion of the lease term in 2006, we have the BGE following options: Funding for utility capital expenditures is expected from inter m renew the lease upon approval of the lessors, nally generated funds. During 2002 and 2003, we expect our melect to purchase the property for a price equal to the lease regulated utility business to provide at least 140% of the cash balance at the end of the term, or needed to meet the capital requirements for its operations, m request the lessor to sell the property. excluding cash needed to retire debt. If necessary, additional If we request the lessor to sell the property, we guarantee the funding may be obtained from commercial paper issuances, sale proceeds up to approximately 83% of the lease balance. available capacity under credit facilities, the issuance of long The lease balance at the end of the term is currently estimated term debt, trust securities, or preference stock, and/or from to be $600 million, which represents the estimated cost of the time to time equity contributions from Constellation Energy.

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Other NonregulatedBusinesses Liquidity Provisions Funding for our other nonregulated businesses is expected from We have certain agreements that contain provisions that would internally generated funds, commercial paper issuances, require additional collateral upon significant decreases in the issuances of long-term debt of Constellation Energy, and sales Senior Unsecured Debt credit ratings of Constellation Energy.

of assets. BGE Home Products & Services can continue to fund Decreases in Constellation Energy's credit ratings would not capital requirements through sales of receivables. ComfortLink trigger an early payment on any of our credit facilities.

has a revolving credit agreement totaling $50 million to provide However, if Constellation Energy's credit ratings were to fall liquidity for short-term financial needs. three or more rating levels from our present rating to a level Our ability to sell or liquidate assets will depend on market below investment grade, we would have collateral obligations of conditions, and we cannot give assurances that these sales or $470 million under our current contractual obligations related liquidations could be made. We discuss our remaining real to our power marketing operation. In many cases, customers of estate projects and market conditions in the Other Nonregulated our power marketing operation rely on the creditworthiness of Businesses section beginning on page 40. Constellation Energy. A decline below investment grade by Constellation Energy would negatively impact the business Committed Amounts prospects of that operation.

Our total contractual and contingent obligations as of The credit facilities of Constellation Energy and BGE have December 31, 2001 are shown in the following table: limited material adverse change clauses that only consider a Pavments/Exviradon material change in financial condition and are not directly Less than One- Four- Over affected by decreases in credit ratings. If these clauses are one year three years five years five years Total violated, the lending institutions can decline making new (In millions) advances or issuing new letters of credit, but cannot accelerate ContractualObligations existing amounts outstanding. The credit facilities of Short-term borrowings $ 975.0 S $ - 975.0 Constellation Energy contain a provision requiring Nonregulated long-term debt 720.4 169.8 456.8 357.1 1,704.1 Constellation Energy to maintain a ratio of debt to capital BGE long-term debt 519.8 441.0 511.8 947.7 2,420.3 ization equal to or less than 0.65. The long-term debt BGE preference stock 130.0 60.0 190.0 Fuel and transportation 353.1 330.0 97.9 177 798.7 indentures of Constellation Energy and BGE do not contain Purchased capacity and energy 16.4 31.5 30.1 98.5 I76.5 material adverse change clauses or financial covenants.

Operating leases 9.1 63.3 51.2 145.8 269.4 Constellation Nuclear guarantees the $388 million sellers' Capital and loan commitments* 81.5 0.8 - 82.3 note to finance the acquisition of Nine Mile Point. This Total contractual obligations 2,675.3 1,166.4 1,207.8 1,566.8 6,616.3 guarantee contains provisions that require Constellation Nuclear Contingent Obligations to maintain a net worth of at least $500 million and a ratio of Letters of credit 245.6 0.2 - 245.8 current assets to current liabilities of at least 1.1. Constellation Guarantees, net** 427.8 38.4 666.1 236.1 1,368.4 Energy is required to provide adequate support to Constellation Total contingent obligations 673.4 38.6 666.1 236.1 1,614.2 Nuclear to meet these provisions. In addition, Constellation Total obligations $3,348.7 $1,205.0 $1,873.9 $1,802.9 $8,230.5 Energy provides credit support to Calvert Cliffs and Nine Mile Point to ensure these plants have funds to meet expenses and

'Amounts are includedfor applicableperiods in our capital requirements table on obligations to safely operate and maintain the plants.

page 42.

We discuss our short-term borrowings in Note 8 on page 75, Guarantees in the above table are shown net of liabilities recordedat long-term debt in Note 9 on page 75, lease requirements in December 31. 2001 in our ConsolidatedBalance Sheets.

Note 10 on page 77, and commitments and guarantees in Note 11 on page 78.

While we included our contingent obligations in the table above, we do not expect to fund the full amounts under the Market Risk letters of credit and guarantees.

We are exposed to various market risks, including changes in Lease payments under the High Desert operating lease are interest rates, certain commodity prices, credit risk, and equity reflected in the table above. The lease balance at the end of the prices. To manage our market risk, we may enter into various lease term is currently estimated to be $600 million. This derivative instruments including swaps, forward contracts, amount is included as a guarantee in the table above.

futures contracts, and options. We discuss our market risk The table above does not include the fixed payment portions further in Note 1 on page 59. In this section, we discuss of our mark-to-market energy assets and liabilities. We discuss our current market risk and the related use of derivative the expected settlement terms of these contracts in the Mark-to instruments.

Market Energy Revenues section on page 33.

Constellation Energy Group, Inc. and Subsidiaries I I

/ 45 Interest Rate Risk We are exposed to changes in interest rates as a result of rate risks. The following table provides information about our financing through our issuance of variable-rate and fixed-rate debt obligations that are sensitive to interest rate changes:

debt. We may use derivative instruments to manage our interest PrincipalPayments and Interest Rate Detailby ContractualMaturity Date Fair value at 2002 2003 2004 2005 2006 Thereafter Total Dec. 31, 2001 (Dollar amounts in millions)

Short-term debt Variable-rate debt $975.0 $ $ $ $ $ 975.0 $ 975.0 Average interest rate 3.20% 3.20%

Long-term debt Variable-rate debt $835.5 $ 7.9 $ 5.4 $ - $111.5 $ 218.8 $1,179.1 $1,179.1 Average interest rate 4.31% 3.88% 4.45% 6.11% 3.18% 4.27%

Fixed-rate debt $404.7 $363.8 $233.7 $425.3 $431.8 $1,086.0 $2,945.3 $3,069.6 Average interest rate 7.78% 7.46% 7.53% 8.32% 5.65% 6.83% 7.26%

In 2001, we entered into forward starting interest rate swap to buy or sell energy, capacity, or fuel during such periods contracts to manage a portion of our interest rate exposure for of volatility to meet fixed-price contract obligations, our anticipated long-term borrowings to refinance our outstanding earnings could be affected.

commercial paper obligations and maturing long-term debt. m Operational risk-operational risk is the risk that a gener The swaps have notional or contract amounts that total $800 ating plant will not be available to produce energy. In million with an average rate of 4.9% and expire at the end of addition, if we have to buy energy in the market to fulfill a the first quarter of 2002. At December 31, 2001, the fair value sales requirement because a generating plant is not of these swap contracts was an unrealized pre-tax gain of $36.3 available to produce that energy, our earnings could be million. In 2002, we entered into additional forward starting affected adversely.

interest rate swaps with notional amounts that total $700 Commodity price risk arises from the potential for changes million. These swaps have an average rate of 5.9% and expire at in the price of, and transportation costs for, electricity, natural the end of the first quarter of 2002. gas, coal, and other commodities; the volatility of commodity prices; and changes in interest rates. A number of factors Commodity Price Risk associated with the structure and operation of the electricity We are exposed to the impact of market fluctuations in the markets significantly influence the level and volatility of prices price and transportation costs of electricity, natural gas, coal, for energy commodities and related derivative products. These and other commodities. factors include:

"*seasonal daily and hourly changes in demand, MerchantEnergy Business "*extreme peak demands due to weather conditions, Our merchant energy business is exposed to various risks in the "*available supply resources, competitive marketplace that may impact its financial results "*transportation availability and reliability within and and affect our earnings. These risks include changes in between regions, commodity prices, imbalances in supply and demand, and "*procedures used to maintain the integrity of the physical operational risk: electricity system during extreme conditions, and

"*Commodity prices--contracts for energy commodities to "*changes in the nature and extent of federal and state be purchased or delivered in the future and derivatives regulations.

related to such commodities exhibit significant price These factors can affect energy commodity and derivative volatility. We use such contracts in our merchant energy prices in different ways and to different degrees. These effects business, and if we have not hedged the associated may vary throughout the country as a result of regional financial exposure, this price volatility could affect our differences in:

earnings. "*weather conditions,

"*Supply and demand imbalances-supply and demand "*market liquidity, imbalances can occur because of plant outages, trans "*capability and reliability of the physical electricity and gas mission system constraints, or extreme temperatures and systems, and can cause significant volatility in energy prices. If we have "*the nature and extent of electricity deregulation.

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Power Marketing The value at risk amount represents the potential pre-tax loss Our power marketing operation is exposed to market risk as a in the fair value of mark-to-market energy assets and liabilities result of the number and size of unhedged positions it holds. over a one-day holding period with a 99.6% confidence level.

The power marketing operation manages market risk on a Using this confidence level, Constellation Power Source would portfolio basis, subject to established risk management policies. expect a one-day change in fair value greater than or equal to In order to manage market risk, the power marketing operation the daily value at risk at least once per year. Constellation Power uses a variety of derivative and non-derivative instruments, Source's value at risk was $18.0 million as of December 31, including: 2001, $13.7 million as of December 31, 2000, and $7.2

"*forward contracts, which commit us to purchase or sell million as of December 31, 1999. The average, high, and low energy commodities in the future; value at risk for the year ended December 31, 2001 were $18.0

"*futures contracts, which are exchange-traded standardized million, $68.9 million, and $8.7 million, respectively. The high commitments to purchase or sell a commodity or financial value at risk amount for the year represents certain hedge instrument, or to make a cash settlement, at a specific contracts entered into in anticipation of closing an offsetting price and future date; transaction. When the offsetting transaction closed within

"*swap agreements, which require payments to or from several days, the value at risk amount returned to a level more counterparties based upon the differential between two representative of the average for the year.

prices for a predetermined contractual (notional) Due to the inherent limitations of statistical measures such quantity; and as value at risk, the relative immaturity of the competitive

"*option contracts, which convey the right to buy or sell a market for electricity and related derivatives, and the seasonality commodity, financial instrument, or index at a predeter of changes in market prices, the value at risk calculation may mined price. not reflect the full extent of our commodity price risk exposure.

While some of these contracts represent commodities or Additionally, actual changes in the value of options may differ instruments for which prices are available from external sources, from the value at risk calculated using a linear approximation other commodities and certain contracts are not actively traded inherent in our calculation method. As a result, actual changes and are valued using other pricing sources and modeling in the fair value of mark-to-market energy assets and liabilities techniques to determine expected future market prices, contract could differ from the calculated value at risk, and such changes quantities, or both. Constellation Power Source's management could have a material impact on our financial results.

uses its best estimates to determine the fair value of commodity and derivative contracts it holds and sells. These estimates Generation consider various factors including closing exchange and over For 2002, we expect to use the majority of the generating the-counter price quotations, time value, volatility factors, and capacity controlled by our merchant energy business to provide credit exposure. However, it is likely that future market prices standard offer service to BGE or to be sold back to the sellers of could vary from those used in recording mark-to-market energy Nine Mile Point to service their load requirements. However, assets and liabilities, and such variations could be material. beginning in July 2002, we expect approximately 1,000 Constellation Power Source uses various methods, including megawatts of industrial customer load will move from BGE's a value at risk model, to measure its exposure to market risk standard offer service to market-based rates. Going forward, our from its energy trading portfolio. Value at risk is a statistical merchant energy business will supply 100% of the standard model that attempts to predict risk of loss based on historical offer service to BGE through June 30, 2003 and 90% from July market price volatility. Constellation Power Source calculates 1, 2003 through June 30, 2006.

value at risk using a variance/covariance technique that models As a result of declines in BGE's standard offer service load option positions using a linear approximation of their value. and the additional 2,900 megawatts of natural gas-fired peaking Additionally, Constellation Power Source estimates variances and combined cycle production facilities under construction, and correlation using historical commodity price changes over our generation operation has a substantial amount of generating the most recent rolling three-month period. Constellation capacity that is subject to future changes in wholesale electricity Power Source's value at risk calculation includes all mark-to prices and has fuel requirements that are subject to future market energy assets and liabilities, including contracts for changes in coal, natural gas, and oil prices. Our power gener energy commodities and derivatives that result in physical ation facilities purchase fuel under contracts or on the spot settlement and contracts that require cash settlement. market. Fuel prices may be volatile and the price that can be obtained from power sales may not change at the same rate as changes in fuel costs. Additionally, if one or more of our gener-Constellation Energy Group, Inc. and Subsidiaries I I

/47 ating facilities is not able to produce electricity when required limits, employing credit mitigation measures such as margin, due to operational factors, we may have to forego sales opportu collateral, or prepayment arrangements, and using master nities or fulfill fixed-price sale commitments through the netting agreements. Constellation Power Source measures credit operation of other more costly generating facilities or through risk as the replacement cost for open energy commodity and the purchase of energy in the wholesale market at higher prices. derivative positions plus amounts owed from counterparties for As part of its overall portfolio, our power marketing settled transactions. The replacement cost of open positions operation manages the commodity price risk of our electric represents unrealized gains, net of any unrealized losses, where generation facilities including power sales, fuel purchases, we have a legally enforceable right of setoff.

emission credits, weather risk, and the market risk of outages. As of December 31, 2001, approximately 85% of In order to manage this risk, our merchant energy business may Constellation Power Source's mark-to-market energy assets enter into fixed-price derivative or non-derivative contracts to consisted of contracts with counterparties rated investment hedge the variability in future cash flows from forecasted sales of grade by the major credit rating agencies, 5% of these assets electricity and purchases of fuel. The objectives for entering into consisted of contracts with counterparties rated below such hedges include: investment grade, and 10% of these assets consisted of contracts m fixing the price for a portion of anticipated future with governmental authorities which are not rated but which electricity sales at a level that provides an acceptable return Constellation Power Source assesses are equivalent to on our electric generation operations, and investment grade based upon its internal credit ratings.

n fixing the price of a portion of anticipated fuel purchases Due to the possibility of extreme volatility in the prices of for the operation of our power plants. energy commodities and derivatives, the market value of The portion of forecasted transactions hedged may vary contractual positions with individual counterparties could based upon management's assessment of market, weather, exceed established credit limits or collateral provided by those operational, and other factors. counterparties. If such a counterparty were then to fail to Our merchant energy business has hedged more than 85% perform its obligations under its contract (for example, fail to of our expected energy output and fuel purchases for 2002. The deliver the electricity the power marketing operation had amount hedged is more than 75% for 2003. contracted for), we could sustain a loss that could have a material impact on our financial results.

RegulatedElectric Business Our merchant energy business sells electricity under long Under the Restructuring Order, effective July 1, 2000, BGE's term power purchase agreements to two California residential rates are frozen for a six-year period, and its investor-owned utilities that were downgraded by rating commercial and industrial rates are frozen for four to six years. agencies to below investment grade. We discuss the credit and BGE entered into standard offer service arrangements with other exposures under these agreements in the Business Constellation Power Source and Allegheny Energy Supply Environment-OtherStates section on page 26.

Company to provide the energy and capacity required to meet its standard offer service obligations through June 30, 2006. Equity Price Risk We are exposed to price fluctuations in equity markets primarily Regulated Gas Business through our financial investments business, our pension plan Our regulated gas business may enter into gas futures, options, assets, and our nuclear decommissioning trust funds. We are and swaps to hedge its price risk under our market-based rate required by the NRC to maintain an externally funded trust for incentive mechanism and our off-system gas sales program. We the costs of decommissioning our nuclear power plants. We discuss this further in Note 1 on page 59. At December 31, discuss our nuclear decommissioning trust funds in more detail 2001 and 2000, our exposure to commodity price risk for our in Note 1 on page 62.

regulated gas business was not material. A hypothetical 10% decrease in equity prices would result in an approximate $80 million reduction in the fair value of our Credit Risk financial investments that are classified as trading or available We are exposed to credit risk, primarily through Constellation for-sale securities, excluding our investment in Orion. In 2001, Power Source. Credit risk is the loss that may result from a the value of our pension plan assets decreased by $42.7 million counterparty's nonperformance. Constellation Power Source due to declines in the markets in which plan assets are invested.

uses credit policies to manage its credit risk, including utilizing We describe our financial investments in more detail in Note 4 an established credit approval process, monitoring counterparty on page 68, and our pension plans in Note 7 on page 72.

Constellation Energy Group, Inc. and Subsidiaries

48 / REPORT OF MANAGEMENT The management of the Company is responsible for the infor accordance with auditing standards generally accepted in the mation and representations in the Company's financial United States of America.

statements. The Company prepares the financial statements in The Audit Committee of the Board of Directors, which accordance with accounting principles generally accepted in the consists of three outside Directors, meets periodically with United States of America based upon available facts and management, internal auditors, and PricewaterhouseCoopers circumstances and management's best estimates and judgments LLP to review the activities of each in discharging their respon sibilities. The internal audit staff and PricewaterhouseCoopers of known conditions.

LLP have free access to the Audit Committee.

The Company maintains an accounting system and related system of internal controls designed to provide reasonable assurance that the financial records are accurate and that the Company's assets are protected. The Company's staff of internal auditors, which reports directly to the Chief Executive Officer, conducts periodic reviews to maintain the effectiveness ayo A. Shattuck III E. Follin Smith of internal control procedures. PricewaterhouseCoopers LLP, Prcsdent and Senior Vice President c_

independent accountants, audit the financial statements and ChiefExecutive Officer ChiefFinancialOfficer express their opinion on them. They perform their audit in REPORT OF INDEPENDENT ACCOUNTANTS To the Shareholders of Constellation Energy Group, Inc.

In our opinion, the accompanying consolidated balance sheets used and significant estimates made by management, and evalu and the related consolidated statements of income, compre ating the overall financial statement presentation. We believe hensive income, cash flows, common shareholders' equity, that our audits provide a reasonable basis for our opinion.

capitalization, and income taxes present fairly, in all material As discussed in Note 1 to the consolidated financial state respects, the financial position of Constellation Energy Group, ments, the Company changed its method of accounting for Inc. and Subsidiaries ("the Company") at December 31, 2001 derivative and hedging activities pursuant to Statement of and 2000, and the results of their operations and their cash Financial Accounting Standards No. 133, Accountingfor flows for each of the three years in the period ended December Derivative Instruments and HedgingActivities, as amended by 31, 2001 in conformity with accounting principles generally Statement of Financial Accounting Standards No. 138, accepted in the United States of America. These financial Accountingfor Certain Derivative Instruments and Certain statements are the responsibility of the Company's Hedging Activities (an amendment of FASB Statement No. 133).

management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on PricewaterhouseCoopers LLP a test basis, evidence supporting the amounts and disclosures in Baltimore, Maryland the financial statements, assessing the accounting principles January 21, 2002 Constellation Fnergy Group, Inc. andSubsidiaries I

CONSOLIDATED STATEMENTS OF INCOME / 49 Year Ended December 31, 2001 2000 1999 (In millions, except per share amounts)

Revenues Nonregulated revenues $1,214.4 $1,114.0 $1,105.6 Regulated electric revenues 2,039.6 2,134.7 2,258.8 Regulated gas revenues 674.3 603.8 476.5 Total revenues 3,928.3 3,852.5 3,840.9 Expenses Operating expenses 2,392.2 2,311.4 2,339.6 Workforce reduction costs 105.7 7.0 Contract termination related costs 224.8 -

Impairment losses and other costs 202.1 - 64.3 Depreciation and amortization 419.1 470.0 449.8 Taxes other than income taxes 226.6 221.5 227.3 Total expenses 3,570.5 3,009.9 3,081.0 Income from Operations 357.8 842.6 759.9 Other Income 1.3 4.2 7.9 Income Before Fixed Charges and Income Taxes 359.1 846.8 767.8 Fixed Charges Interest expense 283.2 282.4 248.0 Interest capitalized and allowance for borrowed funds used during construction (57.6) (24.2) (6.5)

BGE preference stock dividends 13.2 13.2 13.5 Total fixed charges 238.8 271.4 255.0 Income Before Income Taxes 120.3 575.4 512.8 Income Taxes 37.9 230.1 186.4 Income Before Extraordinary Item and Cumulative Effect of Change in Accounting Principle 82.4 345.3 326.4 Extraordinary Loss, Net of Income Taxes of $30.4 (see Note 5) - - (66.3)

Cumulative Effect of Change in Accounting Principle, Net of Income Taxes of $5.6 (see Note 1) 8.5 Net Income $ 90.9 $ 345.3 $ 260.1 Earnings Applicable to Common Stock $ 90.9 $ 345.3 $ 260.1 Average Shares of Common Stock Outstanding 160.7 150.0 149.6 Earnings Per Common Share and Earnings Per Common Share-Assuming Dilution Before Extraordinary Item and Cumulative Effect of Change in Accounting Principle $ .52 $2.30 $2.18 Extraordinary Loss - - (.44)

Cumulative Effect of Change in Accounting Principle .05 -

Earnings Per Common Share and Earnings Per Common Share-Assuming Dilution $ .57 $2.30 $1.74 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME Year Ended December 31, 2001 2000 1999 (In millions)

Net Income $ 90.9 $345.3 $260.1 Other comprehensive income, net of taxes Financial securities 124.5 18.6 3.9 Hedging instruments 102.6 -

Minimum pension liability (44.7) -

Comprehensive Income Before Cumulative Effect of Change in Accounting Principle 273.3 363.9 264.0 Cumulative Effect of Change in Accounting Principle, Net of Income Taxes of $22.6 (35.5) -

Comprehensive Income $237.8 $363.9 $264.0 See Notes to ConsolidatedFinancialStatements.

Certainprior-yearamounts have been reclassified to conform with the currentyears presentation.

Constellation Energy Group, Inc. and Subsidiaries

50 / CONSOLIDATED BALANCE SHEETS At December31, 2001 2000 (In millions)

Current Assets Cash and cash equivalents $ 72.4 $ 182.7 Accounts receivable (net of allowance for uncollectibles of $22.8 and $21.3, respectively) 738.9 792.6 Trading securities 178.2 189.3 Mark-to-market energy assets 398.4 453.1 Fuel stocks 108.0 78.2 Materials and supplies 196.3 151.3 Prepaid taxes other than income taxes 93.4 73.5 Other 74.6 52.8 Total current assets 1,860.2 1,973.5 Investments and Other Assets Real estate projects and investments 210.7 290.3 Investments in power projects 499.1 510.6 Investment in Orion Power Holdings, Inc. 442.5 192.0 Financial investments 60.7 161.0 Nuclear decommissioning trust funds 683.5 228.7 Net pension asset - 93.2 Mark-to-market energy assets 1,819.8 2,069.3 Other 207.4 123.0 Total investments and other assets 3,923.7 3,668.1 Property, Plant and Equipment Regulated property, plant and equipment Plant in service 4,862.4 4,780.3 Construction work in progress 81.8 75.3 Plant held for future use 4.5 4.5 Total regulated property, plant and equipment 4,948.7 4,860.1 Nonregulated generation property, plant and equipment 6,551.1 5,286.8 Other nonregulated property, plant and equipment 192.9 147.0 Nuclear fuel (net of amortization) 169.5 128.3 Accumulated depreciation (4,161.8) (3,756.7)

Net property, plant and equipment 7,700.4 6,665.5 Deferred Charges Regulatory assets (net) 463.8 514.9 Other 129.5 1173 Total deferred charges 593.3 632.2 Total Assets $14,077.6 $12,939.3 See Notes to ConsolidatedFinancialStatements.

Certainprior-yearamounts have been reclassifiedto conform with the currentyears presentation.

Constellation Fnergy Group, Inc. andSubsidiaries I I

CONSOLIDATED BALANCE SHEETS / 51 At December 31, 2001 2000 (In millions)

Uabilities and Capitalization Current Liabilities Short-term borrowings $ 975.0 $ 243.6 Current portion of long-term debt 1,406.7 906.6 Accounts payable 534.4 750.0 Mark-to-market energy liabilities 323.3 358.2 Dividends declared 23.0 66.5 Other 297.1 250.8 Total current liabilities 3,559.5 2,575.7 Deferred Credits and Other Liabilities Deferred income taxes 1,431.0 1,353.2 Mark-to-market energy liabilities 1,476.5 1,636.3 Net pension liability 173.3 Postretirement and postemployment benefits 330.9 265.2 Deferred investment tax credits 93.4 101.4 Other 266.9 484.2 Total deferred credits and other liabilities 3,772.0 3,840.3 Capitalization Long-term debt 2,712.5 3,159.3 BGE preference stock not subject to mandatory redemption 190.0 190.0 Common shareholders' equity 3,843.6 3,174.0 Total capitalization 6,746.1 6,523.3 Commitments, Guarantees, and Contingencies (see Note 11)

Total Liabilities and Capitalization $14,077.6 $12,939.3 See Notes to ConsolidatedFinancialStatements.

Certain prior-yearamounts have been reclassified to conform with the currentyear'spresentation.

Constellation Energy Group, Inc. and Subsidiaries

52 / CONSOLIDATED STATEMENTS OF CASH FLOWS Year Ended December 31, 2001 2000 1999 2000 1999 (In millions)

Cash Flows From Operating Activities Net income $ 90.9 $ 345.3 $ 260.1 Adjustments to reconcile to net cash provided by operating activities Cumulative effect of change in accounting principle (8.5)

Extraordinary loss 66.3 Depreciation and amortization 468.9 524.8 505.9 Deferred income taxes (26.5) 42.1 13.0 Investment tax credit adjustments (8.1) (8.4) (8.6)

Deferred fuel costs 37.6 2.8 (61.1)

Accrued pension and postemployment benefits 55.3 27.9 36.1 Gain on sale of investments (40.7) (64.1)

Loss (gain) on sale of subsidiaries and plant assets 43.3 (13.3)

Deregulation transition cost 24.0 Workforce reduction costs 105.7 7.0 Contract termination related costs 26.2 Impairment losses and other costs 158.7 64.3 Equity in earnings of affiliates and joint ventures (net) 2.0 (5.3) (7.6)

Changes in mark-to-market energy assets and liabilities 109.5 (379.6) (114.3)

Changes in other current assets (57.7) (230.7) (216.4)

Changes in other current liabilities (218.8) 406.2 121.0 Other (164.5) 172.2 20.3 Net cash provided bv overatine activities 573.3 890.9 679.0 Cash Flows From Investing Activities Purchases of property, plant and equipment and other capital expenditures (1,318.3) (1,079.0) (616.5)

Acquisition of Nine Mile Point (382.7)

Sale of (investment in) Orion 26.2 (101.5) (97.7)

Contributions to nuclear decommissioning trust funds (22.0) (13.2) (17.6)

Purchases of marketable equity securities (33.2) (80.8) (27.3)

Sales of marketable equity securities 132.6 110.2 34.9 Proceeds from the sale of property, plant, and equipment 112.0 20.8 Other investments 12.7 37.0 109.1 Net cash used in investing activities (1,472.7) (1,106.5) (615.1)

Cash Flows From Financing Activities Net issuance (maturity) of short-term borrowings 731.4 (127.9) 371.5 Proceeds from issuance of Long-term debt 1,175.2 1,374.0 302.8 Common stock 504.4 35.9 9.6 Repayment of long-term debt (1,510.2) (697.0) (584.4)

Redemption of preference stock (7.0)

Common stock dividends paid (120.7) (250.7) (251.1)

Other 9.0 11.3 13.7 Net cash provided by (used in) financing activities 789.1 345.6 (144.9)

Net (Decrease) Increase in Cash and Cash Equivalents (110.3) 90.0 (81.0)

Cash and Cash Equivalents at Beginning of Year 182.7 92.7 173.7 Cash and Cash Equivalents at End of Year $ 72.4 $ 182.7 $ 92.7 Other Cash Flow Information:

Cash paid during the year for:

Interest (net of amounts capitalized) $ 238.3 $ 268.2 $ 245.3 Income taxes $ 101.5 $ 184.7 $ 165.6 Non-Cash Transaction:

In connection with our purchase of Nine Mile Point, the fair value of the net assets purchased was $770.8 million. We paid $382.7 million in cash, including settlement costs, and incurred a sellers' note of $388.1 million as discussed further in Note 14 on page 86.

See Notes to ConsolidatedFinancialStatements.

Certainprior-yearamounts have been reclassifiedto conform with the currentyears presentation.

ConstellationEnergy Group, Inc. andSubsidiaries I I

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY / 53 Accumulated Other Common Stock Retained Comprehensive Total Years Ended December 31, 2001, 2000, and 1999 Shares Amount Earnings Income Amount (Dollaramounts in millions, number ofs/ars in thousands)

Balance at December 31, 1998 149,246 S1,485.1 S1,490.3 S 20.5 S2,995.9 Net income 260.1 260.1 Common stock dividend declared (S1.68 per share) (251.3) (251.3)

Common stock issued 310 9.6 9.6 (0.7) (0.7)

Other Net unrealized gain on securities, net of taxes of S3.2 3.9 3.9 Balance at December 31, 1999 149,556 1,494.0 1,499.1 24.4 3,017.5 Net income 345.3 345.3 Common stock dividend declared (51.68 per share) (251.8) (251.8)

Common stock issued 976 35.9 35.9 Other 8.8 (0.3) 8.5 Net unrealized gain on securities, net of taxes of $9.5 18.6 18.6 Balance at December 31, 2000 150,532 1,538.7 1,592.3 43.0 3,174.(0 Net income 90.9 90.9 Common stock dividend declared ($.48 per share) (77.1) (77.1)

Common stock issued 13,176 504.4 504.4 Other (0.9) 5.4 4.5 Cumulative effect of change in accounting principle, net of taxes of $22.6 (35.5) (35.5)

Net unrealized gain on securities, net of taxes of $71.8 124.5 124.5 Net unrealized gain on hedging instruments, net of taxes of $65.6 102.6 102.6 Minimum pension liability, net of taxes of S29.3 (44.7) (44.7)

Balance at December 31, 2001 163,708 $2,042.2 $1,611.5 $189.9 $3,843.6 See Notes to Consolidated EtnancialStatenients.

Certain prior-yearainottnt have been reclassified to conflrot wit/I the current year'spresentation.

C.onstellation fr-ner m (lGroup, b. and Subsidiaries

54 / CONSOLIDATED STATEMENTS OF CAPITALIZATION At December 31, 2001 2000 (in millions)

Long-Term Debt Long-term debt of Constellation Energy 7,4% Notes, due April 1, 2005 $ 300.0 $ 300.0 Floating rate notes, due April 4, 2003 - 200.0 Extendible notes, due June 21, 2010 - 300.0 Floating rate reset notes, due March 15, 2002 - 200.0 Floating rate notes, due January 17, 2002 635.0 Total long-term debt of Constellation Energy 935.0 1,000.0 Long-term debt of nonregulated businesses Tax-exempt debt transferred from BGE effective July 1, 2000 Pollution control loan, due July 1, 2011 36.0 36.0 Port facilities loan, due June 1, 2013 48.0 48.0 Adjustable rate pollution control loan, due July 1, 2014 20.0 20.0 5.55% Pollution control revenue refunding loan, due July 15, 2014 47.0 47.0 Economic development loan, due December 1, 2018 35.0 35.0 6.00% Pollution control revenue refunding loan, due April 1, 2024 75.0 75.0 Floating rate pollution control loan, due June 1, 2027 8.8 8.8 5Y0% Installment series, due July 15, 2002 6.7 7.6 District Cooling facilities loan, due December 1, 2031 25.0 Loans under revolving credit agreements 46.0 34.0 110% Installment note, due November 7, 2006 388.1 Mortgage and construction loans Floating rate mortgage notes and construction loans, due through 2005 13.8 51.3 Other mortgage notes ranging from 4.25% to 9. 6 5% due March 15, 2009 to November 1, 2033 19.7 20.3 Unsecured notes - 287.0 Total long-term debt of nonregulated businesses 769.1 670.0 First Refunding Mortgage Bonds of BGE 8Y8% Series, due August 15, 2001 - 122.2 7Y.% Series, due July 1, 2002 124.0 124.0 6Y% Series, due February 15, 2003 124.8 124.8 6Ys% Series, due July 1, 2003 124.9 124.9 5Y2% Series, due April 15, 2004 125.0 125.0 Remarketed floating rate series, due September 1, 2006 111.5 111.5 7Y2% Series, due January 15, 2007 123.5 123.5 6Y8% Series, due March 15, 2008 124.9 124.9 7Y,% Series, due March 1, 2023 98.1 109.9 7Y% Series, due April 15, 2023 84.0 84.0 Total First Refunding Mortgage Bonds of BGE 1,040.7 1,174.7 Other long-term debt of BGE 5.25% Notes, due December 15, 2006 300.0 Floating rate reset notes, due February 5, 2002 200.0 Floating rate reset notes, due October 19, 2001 - 200.0 Medium-term notes, Series B 23.1 23.1 Medium-term notes, Series C 25.5 25.5 Medium-term notes, Series D 68.0 128.0 Medium-term notes, Series E 200.0 200.0 Medium-term notes, Series G 140.0 200.0 Medium-term notes, Series H - 27.0 6.75% Remarketable or redeemable securities, due December 15, 2012 173.0 173.0 Total other long-term debt of BGE 1,129.6 976.6 BGE obligated mandatorily redeemable trust preferred securities of subsidiary trust holding solely 7.16% deferrable interest subordinated debentures due June 30, 2038 250.0 250.0 Unamortized discount and premium (5.2) (5.4)

Current portion of long-term debt (1,406.7) (906.6)

Total long-term debt $2,712.5 $3,159.3 See Notes to ConsolidatedFinancialStatements. continued on next page Constellation Energy Group, Inc. andSubsidiaries I I

CONSOLIDATED STATEMENTS OF CAPITALIZATION / 55 At December 31, 2001 2000 (In millions)

BGE Preference Stock Cumulative preference stock not subject to mandatory redemption, 6,500,000 shares authorized 7.125%, 1993 Series, 400,000 shares outstanding, not callable prior to July 1, 2003 $ 40.0 $ 40.0 6.97%, 1993 Series, 500,000 shares outstanding, not callable prior to October 1, 2003 50.0 50.0 6.70%, 1993 Series, 400,000 shares outstanding, not callable prior to January 1, 2004 40.0 40.0 6.99%, 1995 Series, 600,000 shares outstanding, not callable prior to October 1, 2005 60.0 60.0 Total preference stock not subject to mandatory redemption 190.0 190.0 Common Shareholders' Equity Common stock without par value, 250,000,000 shares authorized; 163,707,950 and 150,531,716 shares issued and outstanding at December 31, 2001 and 2000, respectively. (At December 31, 2001 11,797,976 shares were reserved for the Shareholder Investment Plan and 6,000,000 were reserved for the long-term incentive plans.) 2,042.2 1,538.7 Retained earnings 1,611.5 1,592.3 Accumulated other comprehensive income 189.9 43.0 Total common shareholders' equity 3,843.6 3,174.0 Total Capitalization $6,746.1 $6,523.3 See Notes to ConsolidatedFinancialStatements.

Certainprior-yearamounts have been reclassified to conform with the current year'spresentation.

Constellation Energy Group, Inc. andSubsidiaries

56 / CONSOLIDATED STATEMENTS OF INCOME TAXES Year Ended December 31, 2001 2000 1999 (Dolliramounts in raillions)

Income Taxes Current Federal $45.5 S148.2 S176.3 State 27.0 48.2 5.7 Current taxes charged to expense 72.5 196.4 182.0 Deferred Federal (22.4) 53.9 5.8 State (4.1) (11.8) 7.)

Deferred taxes charged to expense (26.5) 42.1 13.0 Investment tax credit adjustments (8.1) (8.4) (8.6)

Income taxes per Consolidated Statements of Income $37.9 $230.1 $186.4 Reconciliation of Income Taxes Computed at Statutory Federal Rate to Total Income Taxes Income before income taxes (excluding BGE preference stock dividends) $133.5 $588.6 S526.3 Statutory federal income tax rate 35% 35% 350%

Income taxes computed at statutory federal rate 46.7 206.0 184.2 Increases (decreases) in income taxes due to Depreciation differences not normalized on regulated activities 5.6 12.6 15.3 Allowance for equity funds used during construction (1.1) (0.9) (2.2)

Amortization of deferred investment tax credits (8.1) (8.4) (8.6)

Tax credits flowed through to income (13.4) (6.5) (3.2)

Amortization of deferred tax rate differential on regulated activities (2.1) (2.9) (3.0)

State income taxes, net of federal income tax benefit 13.5 31.7 8.2 Other (3.2) (1.5) (4.3)

Total income taxes $37.9 S230.1 $186.4 Effective income tax rate 28.4% 39.1% 35.40/

At December 31, 2001 2000 (Dollaramounts in millions)

Deferred Income Taxes Deferred tax liabilities Net property, plant and equipment $1,156.0 S1,135.5 Income taxes recoverable through future rates 31.4 32.8 Deferred termination and postemployment costs 7.0 13.6 Deferred fuel costs 11.7 24.9 Powser marketing and risk management activities 776.4 819.4 Deferred electric generation-related regulatory assets 87.1 93.7 Financial investments and hedging instruments 153.9 42.6 Other 140.9 135.6 Tbtal deferred tax liabilities 2,364.4 2,298.1 Deferred tax assets Accrued pension and postemployment benefit costs 132.7 76-5 Deferred investment tax credits 35.1 35.5 Nuclear decommissioning liability 32.1 28.2 Power marketing and risk management activities 549.1 638.2 Reduction of investments 82.3 29.8 Other 102.1 136.7 Total deferred tax assets 933.4 944.9 Deferred tax liability, net $1,431.0 $1.353.2 See ,'Votes to Consolidated 1-inan'ia i Statements.

Certainprior-ICaramounts have been reckassifiedto conforn* uit/7 the current years presentation.

C'onstellarion norgv (6,roip,Inc. andSubsidiaries I

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS / 57 Note 1. Significant Accounting Policies Nature of Our Business Sheets. The only time we do not use this method is when we Constellation Energy Group, Inc. (Constellation Energy) is a can exercise significant influence over the operations and North American energy company that conducts its business policies of the company. If we have significant influence, through various subsidiaries including a merchant energy accounting rules require us to use the equity method.

business and Baltimore Gas and Electric Company (BGE). Our merchant energy business generates and markets wholesale Regulation of Utility Business electricity in North America. BGE is an electric and gas public The Maryland Public Service Commission (Maryland PSC) transmission and distribution utility company with a service provides the final determination of the rates we charge our territory that covers the City of Baltimore and all or part of ten customers for our regulated businesses. Generally, we use the counties in central Maryland. We describe our operating same accounting policies and practices used by nonregulated segments in Note 3 on page 66. companies for financial reporting under accounting principles References in this report to "we" and "our" are to generally accepted in the United States of America. However, Constellation Energy' and its subsidiaries, collectively. Reference sometimes the Maryland PSC orders an accounting treatment in this report to the "utility business" is to BGE. different from that used by nonregulated companies to determine the rates we charge our customers. When this Consolidation Policy happens, we must defer (include as an asset or liability in our We use three different accounting methods to report our invest Consolidated Balance Sheets and exclude from our ments in our subsidiaries or other companies: consolidation, the Consolidated Statements of Income) certain utility expenses equity method, and the cost method. and income as regulatory assets and liabilities. We have recorded these regulatory assets and liabilities in our Consolidated Consolidation Balance Sheets in accordance with Statement of Financial Accounting Standards (SEAS) No. 71, Accountgfor the Fff'cts We use consolidation when we own a majority of the voting stock of the subsidiary. This means the accounts of our of Certain Types of Regulation. We summarize and discuss our subsidiaries are combined with our accounts. We eliminate regulatory assets and liabilities further in Note 6 on page 71.

intercompany balances and transactions when we consolidate In 1997, the Financial Accounting Standards Board (FASB) these accounts. through its Emerging Issues Task Force (EITF) issued EITF 97-4, Deregulation ofthe Pricingof Electricitj-IssuesRelated to the The Equity Method Application of FASB Statements No. 71 and 101. The EITF We usually use the equity method to report investments, concluded that a company should cease to apply SFAS No. 71 corporate joint ventures, partnerships, and affiliated companies when either legislation is passed or a regulators body issues an (including power projects) where we hold a 20% to 50% voting order that contains sufficient detail to determine how the interest. Under the equity method, we report: transition plan will affect the deregulated portion of the 0 our interest in the entity as an investment in our business. Additionally, a company would continue to recognize Consolidated Balance Sheets, and regulatory assets and liabilities in the Consolidated Balance I our percentage share of the earnings from the entity' in our Sheets to the extent that the transition plan provides for Consolidated Statements of Income. their recovery'.

The only time we do not use this method is if we can On November 10, 1999, the Maryland PSC issued a exercise control over the operations and policies of the Restructuring Order that we believe provided sufficient details company. If we have control, accounting rules require us to use of the transition plan to competition for BGE's electric gener consolidation. ation business to require BGE to discontinue the application of SEAS No. 71 for that portion of its business. Accordingly, in The Cost Method the fourth quarter of 1999, we adopted the provisions of SFAS We usually use the cost method if we hold less than a 20% No. 10 1, Regulated Enterprises-Accountingfor the voting interest in an investment. Under the cost method, we Discontinuationof FASB Statement No. 71 and EITF 97-4 for report our investment at cost in our Consolidated Balance BGE's electric generation business. BGE's transmission and distribution business continues to meet the requirements of SFAS No. 71, as that business remains regulated. We discuss this further in Note 5 on page 70.

Constellation Fnergl, (6roup,hic and Subsidiaries

58 /

Revenues NonregulatedBusinesses Regulated Utility Our subsidiary, Constellation Power Source, uses the mark-to We record utility revenues when we provide service to market method of accounting, as discussed below, to account customers.

for a portion of its power marketing activities. We record all other nonregulated revenues in the period earned for services Fuel and Purchased Energy Costs rendered, commodities or products delivered, or contracts We incur costs for:

settled. Equity in earnings from our investments in power "*the fuel we use to generate electricity, projects is included in revenues. "*purchases of electricity from others, and Power marketing activities include new origination transac "* natural gas that we resell.

tions and risk management activities using contracts for energy, These costs are included in "Operating expenses" in our other energy-related commodities, and related derivative Consolidated Statements of Income. We discuss each of these contracts. We use the mark-to-market method of accounting for separately below.

portions of Constellation Power Source's activities as required by EITF 98-10, Accountingfor Contracts Involved in Energy Trading Fuel Used to Generate Electricityand Purchases and Risk ManagementActivities. Under the mark-to-market of ElectricityFrom Others method of accounting, we record the fair value of commodity Effective July 1, 2000, these costs are recorded as incurred.

and derivative contracts as mark-to-market energy assets and Historically and until July 1, 2000, we were allowed to recover liabilities at the time of contract execution. We record reserves our costs of electric fuel under the electric fuel rate clause set by to reflect uncertainties associated with certain estimates inherent the Maryland PSC. Under the electric fuel rate clause, we in the determination of fair value. Mark-to-market energy charged our electric customers for:

revenues include: "*the fuel we use to generate electricity (nuclear fuel, coal,

"*the fair value of new transactions at origination, gas, or oil), and

"*unrealized gains and losses from changes in the fair value "*the net cost of purchases and sales of electricity.

of open positions, We charged the actual costs of these items to customers with

"*net gains and losses from realized transactions, and no profit to us. To do this, we had to keep track of what we

"*changes in reserves. spent and what we collected from customers under the fuel rate We record the changes in mark-to-market energy assets and in a given period. Usually these two amounts were not the same liabilities on a net basis in "Nonregulated revenues" in our because there was a difference between the time we spent the Consolidated Statements of Income. Mark-to-market energy money and the time we collected it from our customers.

assets and liabilities are comprised of a combination of energy Under the electric fuel rate clause, we deferred the difference and energy-related derivative and non-derivative contracts. between our actual costs of fuel and energy and what we "Whilesome of these contracts represent commodities or instru collected from customers under the fuel rate in a given period.

ments for which prices are available from external sources, other We either billed or refunded our customers that difference in commodities and certain contracts are not actively traded and the future. As a result of the Restructuring Order, the fuel rate are valued using modeling techniques to determine expected was discontinued effective July 1, 2000. We discuss this further future market prices, contract quantities, or both. The market in Note 6 on page 71.

prices used to determine fair value reflect management's best estimate considering various factors, including closing exchange Natural Gas and over-the-counter quotations, time value, and volatility We charge our gas customers for the natural gas they purchase factors. However, it is possible that future market prices could from us using "gas cost adjustment clauses" set by the Maryland vary from those used in recording mark-to-market energy assets PSC. These clauses operate similarly to the electric fuel rate and liabilities, and such variations could be material. clause described earlier in this note. However, the Maryland Certain power marketing and risk management transactions PSC approved a modification of the gas cost adjustment clauses entered into under master agreements and other arrangements to provide a market-based rates incentive mechanism. Under provide our merchant energy business with a right of setoff in market-based rates, our actual cost of gas is compared to a the event of bankruptcy or default by the counterparty. We market index (a measure of the market price of gas in a given report such transactions net in the balance sheets in accordance period). The difference between our actual cost and the market with FASB Interpretation No. 39, Offietting ofAmounts Related index is shared equally between shareholders and customers.

to Certain Contracts. Effective November 2001, the Maryland PSC approved an order that modifies certain provisions of the market-based rates incentive mechanism. These provisions require that BGE secure Constellation Energy Group, Inc. and Subsidiaries I I

/ 59 fixed-price contracts for at least 10%, but not more than 20%, purchases of fuel. The objectives for entering into such hedges of forecasted system supply requirements for the November include:

through March period. These fixed price contracts are not m fixing the price for a portion of anticipated future subject to sharing under the market-based rates incentive electricity sales at a level that provides an acceptable return mechanism. on our electric generation operations, and m fixing the price of a portion of anticipated fuel purchases Risk Management for the operation of our power plants.

We are exposed to market risk, including changes in interest The portion of forecasted transactions hedged may vary rates and the impact of market fluctuations in the price and based upon management's assessment of market, weather, transportation costs of electricity, natural gas, and other operational, and other factors.

commodities as discussed further in Note 12 on page 83. We Under the provisions of SEAS No. 133, we record gains and use interest rate swaps to manage our interest rate exposures losses on derivative contracts designated as cash-flow hedges of associated with new debt issuances. These swaps are designated firm commitments or anticipated transactions in "Accumulated as cash-flow hedges under SEAS No. 133, Accountingfor other comprehensive income" in our Consolidated Statements Derivative Instruments and Hedging Activities, as discussed later of Common Shareholders' Equity and Consolidated Statements in this note, with our gains recorded in "Other current assets" of Capitalization prior to the settlement of the anticipated in our Consolidated Balance Sheets and "Accumulated other hedged physical transaction. We reclassify these gains or losses comprehensive income," in our Consolidated Statements of into earnings upon settlement of the underlying hedged trans Common Shareholders' Equity and Consolidated Statements of action. We record derivatives used for hedging activities from Capitalization, in anticipation of planned financing transac our merchant energy business in "Other assets," and in "Other tions. Any gain or loss on the hedges will be reclassified from deferred credits and other liabilities," in our Consolidated "Accumulated other comprehensive income" into "Interest Balance Sheets.

expense" and be included in earnings during the periods in which the interest payments being hedged occur. Regulated Electric Business Our merchant energy' and regulated gas businesses use deriv Under the Restructuring Order, effective July 1, 2000, BGE's ative and non-derivative instruments to manage changes in their residential rates are frozen for a six-year period, and its respective commodity prices as discussed in more detail below. commercial and industrial rates are frozen for four to six years.

BGE entered into standard offer service arrangements with Merchant Energy Business Constellation Power Source and Allegheny Energy Supply The power marketing operation manages market risk on a Company to provide the energy and capacity required to meet portfolio basis, subject to established risk management policies. its standard offer service obligations through June 30, 2006.

The power marketing operation uses a variety of derivative and non-derivative instruments, including: Regulated Gas Business E forward contracts, which commit us to purchase or sell We use basis swaps in the winter months (November through energy commodities in the future; March) to hedge our price risk associated with natural gas m futures contracts, which are exchange-traded standardized purchases under our market-based rates incentive mechanism.

commitments to purchase or sell a commodity or financial We also use fixed-to-floating and floating-to-fixed swaps to instrument, or to make a cash settlement, at a specific hedge our price risk associated with our off-system gas sales.

price and future date; The fixed portion represents a specific dollar amount that we m swap agreements, which require payments to or from will pay or receive, and the floating portion represents a fluctu counterparties based upon the differential between two ating amount based on a published index that we will receive or prices for a predetermined contractual (notional) quantity; pay. Our regulated gas business internal guidelines do not and permit the use of swap agreements for any purpose other than m option contracts, which convey the right to buy or sell a to hedge price risk.

commodity, financial instrument, or index at a predeter BGE's off-system gas sales activities represent trading activ mined price. ities under EITF 98-10. Accordingly, we use mark-to-market As part of its overall portfolio, the power marketing accounting to record these transactions. The trading activities operation manages the commodity price risk of our electric relating to our off-system gas sales were not material at generation facilities, including power sales, fuel purchases, December 31, 2001 and 2000.

emission credits, weather risk, and the market risk of outages. In We defer, as unrealized gains or losses, the changes in fair order to manage this risk, we may enter into fixed-price deriv value of the swap agreements under the market-based rates ative or non-derivative contracts to hedge the variability in incentive mechanism and the customers' portion of off-system future cash flows from forecasted sales of electricity and Constellation Energy Group, Inc. and Subsidiaries

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gas sales in our Consolidated Balance Sheets. When amounts through future rates (net)" regulators' asset (described later are paid tinder the agreements, we report the payments as gas in this note) during the year.

costs in our Consolidated Statements of Income. We report the changes in fair value for the shareholders' portion of off-system Investment Tax Credits gas sales in earnings as a component of gas costs. \We have deferred the investment tax credit associated with our regulated utility" business and assets previously held by our Credit Risk regulated utility business in our Consolidated Balance Sheets.

Credit risk is the loss that may result from counterpartv non The investment tax credit is amortized evenly to income over performance. We are exposed to credit risk, primarily through the life of each property. We reduce income tax expense in our Constellation Power Source. Constellation Power Source uses Consolidated Statements of Income for the investment tax credit policies to manage its credit risk, including utilizing an credit and other tax credits associated with our no'nregulated established credit approval process, monitoring counterparty businesses, other than leveraged leases.

limits, employing credit mitigation measures such as margin, collateral or prepayment arrangements, and using master DeferredIncome Tax Assets and Liabilities netting agreements. Constellation Power Source measures credit We must report some of our revenues and expenses differently risk as the replacement cost for open energy commodity and for our financial statements than for income tax return derivative positions plus amounts owed from counterparties for purposes. The tax effects of the differences in these items are settled transactions. The replacement cost of open positions reported as deferred income tax assets or liabilities in our represents unrealized gains, net of any unrealized losses, where Consolidated Balance Sheets. We measure the deferred income we have a legally enforceable right of setoff. tax assets and liabilities using income tax rates that are currently Due to the possibility of extreme volatility in the prices of in effect.

energy commodities and derivatives, the market value of A portion of our total deferred income tax liabilitys relates to contractual positions with individual counterparties could our regulated utility business, but has nor been ref.ected in the exceed established credit limits or collateral provided by' those rates we charge our customers. We refer to this portion of the counterparties. If such a counterparty were then to fail to liabilitys as "Income taxes recoverable through future rates (net)."

perform its obligations under its contract (for example, fail to \We have recorded that portion of the net liability as a regulatory deliver the electricity the power marketing operation had asset in our Consolidated Balance Sheets. We discuss this contracted for), we could sustain a loss that could have a further in Note 6 on page 71.

material impact on our financial results.

Electric and gas utilities, cooperatives, and energy marketers State and Local Taxes comprise the majority of counterparties underlying our assets As discussed in Note 5 on page 69, tax legislation has made from power marketing and risk management activities. We held comprehensive changes to the state and local taxation of electric cash collateral from counterparties totaling S3.5 million as of and gas utilities. State and local income taxes are included in December 31, 2001 and S 103.3 million as of December 31, "Income taxes" in our Consolidated Statements of Income.

2000. These amounts are included in "Other deferred credits Through December 31, 1999, we paid Maryland public and other liabilities" in our Consolidated Balance Sheets. ser'ice company franchise tax on our utility revenue from sales in Maryland instead of state income tax. \We include the Taxes franchise tax in "Taxes other than income taxes" in our WXe summarize our income taxes in our Consolidated Consolidated Statements of Income.

Statements of Income Taxes on page 56. As you read this section, it may be helpful to refer to those statements. Cash and Cash Equivalents All highly liquid investments with original maturities of three Income Tax Expense months or less are considered cash equivalents.

We have two categories of income taxes in our Consolidated At December 31, 2000, $112.5 million of the cash balance Statements of Income laxes-current and deferred. We describe included in our Consolidated Balance Sheets was restricted each of these below: tinder certain collateral arrangements for our power marketing

"*Current income tax expense consists solely of regular tax operation.

less applicable tax credits, and

"*deferred income tax expense is equal to the changes in the Inventory net deferred income tax liability, excluding amounts We record our fuel stocks and materials and supplies at the charged or credited to accumulated other comprehensive lower of cost or market. We determine cost using the average income. Our deferred income tax expense is increased or cost method.

reduced for changes to the "Income taxes recoverable (ConstelitionEkneurzl (ioup, Inc. and Sdbsidiaries I I

/61 Real Estate Projects and Investments Evaluation of Assets for Impairment and Other Than In Note 4 on page 68, we summarize the real estate projects and Temporary Decline in Value investments that are in our Consolidated Balance Sheets. The SFAS No. 121, Accountingfor the Impairment of Long-Lived projects and investments primarily consist of: Assets andfor Long-Lived Assets to Be Disposed Of requires us to 0 approximately 1,600 acres of land holdings in various evaluate certain assets that have long lives (generating property stages of development located at 11 sites in the central and equipment and real estate) to determine if they are Maryland region, impaired if certain conditions exist. We determine if long-lived ma 4,500 unit mixed-use planned unit development located assets are impaired by comparing their undiscounted expected in Anne Arundel County, Maryland of which 1,300 future cash flows to their carrying amount in our accounting residential units and 11 acres for commercial development records. We would record an impairment loss if the undis remain, counted expected future cash flows from an asset were less than E an operating waste water treatment plant located in Anne the carrying amount of the asset. Additionally, we evaluate our Arundel County' Maryland, and equity-method investments to determine whether they have 0 an equity interest in Corporate Office Properties Trust, a experienced a loss in value that is considered other than a real estate investment trust. temporary decline in value.

The costs incurred to acquire and develop properties are We use our best estimates in making these evaluations and included as part of the cost of the properties. consider various factors, including forward price curves for energy, fuel costs, and operating costs. However, actual future Financial Investments and Trading Securities market prices and project costs could vary from those used in In Note 4 on page 68, we summarize the financial investments our impairment evaluations, and the impact of such variations that are in our Consolidated Balance Sheets. could be material.

SFAS No. 115, Accountingfor Certain Investments in Debt and Equity Securities, applies particular requirements to some of Property, Plant and Equipment, Depreciation, our investments in debt and equity securities. We report those Amortization, and Decommissioning investments at fair value, and we use either specific identifi We report our property, plant and equipment at its original cation or average cost to determine their cost for computing cost, unless impaired under the provisions of SEAS No. 121.

realized gains or losses. We classify these investments as either Our original costs include:

trading securities or available-for-sale securities, which we 0 material and labor, describe separately below. We report investments that are not m contractor costs, and covered by SFAS No. 115 at their cost. m construction overhead costs and financing costs (where applicable).

Trading Securities We own an undivided interest in the Keystone and Our other nonregulated businesses classify some of their invest Conemaugh electric generating plants in Western Pennsylvania, ments in marketable equity securities and financial limited as well as in the transmission line that transports the plants' partnerships as trading securities. We include any unrealized output to the joint owners' service territories. Our ownership gains or losses on these securities in "Nonregulated revenues" in interests in these plants are 20.99% in Keystone and 10.56% in our Consolidated Statements of Income. Conemaugh. These ownership interests represented a net investment of $150 million at December 31, 2001 and $143 Available-for-Sale Securities million at December 31, 2000.

We classif, our investments in the nuclear decommissioning The "Nonregulated generation property, plant and trust funds as available-for-sale securities. We describe the equipment" in our Consolidated Balance Sheets includes nuclear decommissioning trusts and the reserves under the nonregulated generation construction work in progress of heading "Nuclear Decommissioning" later in this note. $1,158.6 million at December 31, 2001 and $908.7 million at In addition, our other nonregulated businesses classify, some December 31, 2000.

of their investments in marketable equity securities as available When we retire or dispose of property, plant and equipment, for-sale securities, including the investment in Orion Power we remove the asset's cost from our Consolidated Balance Holdings, Inc. (Orion) effective June 1, 2001. We discuss the Sheets. We charge this cost to accumulated depreciation for accounting for the investment in Orion in more detail in Note assets that were depreciated under the composite, straight-line 4 on page 68. method. This includes regulated utility property, plant and We include any unrealized gains or losses on our available equipment and nonregulated generating assets previously owned for-sale securities in "Accumulated other comprehensive income" by the regulated utility. For all other assets, we remove the in our Consolidated Statements of Common Shareholders' accumulated depreciation and amortization amounts from our Equity and Consolidated Statements of Capitalization. Consolidated Balance Sheets and record any gain or loss in our Consolidated Statements of Income.

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The costs of maintenance and certain replacements are 1993 dollars, adjusted for inflation, to decommission Calvert charged to "Operating expenses" in our Consolidated Cliffs. BGE is collecting this amount on behalf of and passing it Statements of Income as incurred. to Calvert Cliffs Nuclear Power Plant, Inc. Calvert Cliffs Nuclear Power Plant, Inc. is responsible for any difference between this Depreciation Expense amount and the actual costs to decommission the plant.

We compute depreciation for our generating, electric trans We recorded a reserve for the costs expected to be incurred mission and distribution, and gas facilities over the estimated in the future to decommission the radioactive portion of Nine useful lives of depreciable property using either the: Mile Point under the discounted future cash flows method

"*composite, straight-line rates (approved by the Maryland ology. The total reserve was $224.4 million at December 31, PSC for our regulated utility business) applied to the 2001. We have determined that the decommissioning trust average investment in classes of depreciable property based funds established for Nine Mile Point are adequately funded to on an average rate of approximately three percent per year, cover the future costs to decommission the radioactive portions or of the plant and as such, no contributions were made to the

"*units of production method. trust funds during the year ended December 31, 2001.

Other assets are depreciated using the straight-line method In accordance with Nuclear Regulatory Commission (NRC) and the following estimated useful lives: regulations, we maintain external decommissioning trusts to Asset Estimated Useful Lives fund the costs expected to be incurred to decommission Calvert Cliffs and Nine Mile Point. The assets in the trusts are reported Building and improvements 20 - 50 years in "Nuclear decommissioning trust funds" in our Consolidated Transportation equipment 5 - 15 years Balance Sheets. The NRC requires utilities to provide financial Office equipment and computer software 3 - 20 years assurance that they will accumulate sufficient funds to pay for the cost of nuclear decommissioning based upon either a generic Amortization Expense NRC formula or a facility-specific decommissioning cost Amortization is an accounting process of reducing an amount estimate. We use the facility-specific cost estimate for funding in our Consolidated Balance Sheets evenly over a period of time these costs and providing the required financial assurance.

that approximates the useful life of the related item. When we We classifv the investments in the nuclear decommissioning reduce amounts in our Consolidated Balance Sheets, we trust funds as available-for-sale securities, and we report these increase amortization expense in our Consolidated Statements investments at fair value in our Consolidated Balance Sheets as of Income. An amount is considered fully amortized when it previously discussed in this note.

has been reduced to zero.

As owners of Calvert Cliffs Nuclear Power Plant, we are required, along with other domestic utilities, by the Energy Nuclear Fuel Policy Act of 1992 to make contributions to a fund for decom We amortize nuclear fuel based on the energy produced over missioning and decontaminating the Department of Energy's the life of the fuel including the quarterly fees we pay to the uranium enrichment facilities. The contributions are generally Department of Energy for the future disposal of spent nuclear payable over 15 years with escalation for inflation and are based fuel. These fees are based on the kilowatt-hours of electricity upon the proportionate amount of uranium enriched by the sold. We report the amortization expense for nuclear fuel in Department of Energy for each utility. We amortize the "Operating expenses" in our Consolidated Statements of deferred costs of decommissioning and decontaminating the Income.

Department of Energy's uranium enrichment facilities. The previous owners retained the obligation for Nine Mile Point.

Nuclear Decommissioning We record an expense and a reserve for the costs expected to be Capitalized Interest and Allowance incurred in the future to decommission the radioactive portion for Funds Used During Construction of Calvert Cliffs based on a sinking fund methodology. The CapitalizedInterest accumulated decommissioning reserve is recorded in With the issuance of the Restructuring Order, we ceased "Accumulated depreciation" in our Consolidated Balance Sheets.

accruing AFC (discussed on the next page) for electric The total reserve was $304.6 million at December 31, 2001 and generation-related construction projects.

$275.4 million at December 31, 2000. Our contributions to the Our nonregulated businesses capitalize interest costs under nuclear decommissioning trust funds were $22.0 million for SFAS No. 34, CapitalizingInterest Costs, for costs incurred to 2001, $13.2 million for 2000, and $17.6 million for 1999.

finance our power plant construction projects and real estate Under the Maryland PSC's order deregulating electric gener developed for internal use.

ation, BGE's customers must pay a total of $520 million in Constellation Energy Group, Inc. and Subsidiaries I I

/63 Allowance for Funds Used During Construction (AFC) and risk management activities and to hedge the risk of varia We finance regulated utility construction projects with borrowed tions in future cash flows from forecasted purchases and sales of funds and equity funds. We are allowed by the Maryland PSC to electricity and gas in our electric generation operations as more record the costs of these funds as part of the cost of construction fully described in the Risk Management section on page 59.

projects in our Consolidated Balance Sheets. We do this through Under SFAS No. 133, changes in the value of derivatives desig the AFC, which we calculate using a rate authorized by the nated as hedges that are effective in offsetting the variability in Maryland PSC. We bill our customers for the AFC plus a return cash flows of forecasted transactions are recognized in other after the utility property is placed in service. comprehensive income until the forecasted transactions occur.

The AFC rates are 9.4% for electric plant, 8.6% for gas plant, The ineffective portion of changes in fair value of derivatives and 9.2% for common plant. We compound AFC annually. used as cash-flow hedges is immediately recognized in earnings.

In accordance with the transition provisions of SFAS No.

Long-Term Debt 133, we recorded the following at January 1, 2001:

We defer all costs related to the issuance of long-term debt. "*an $8.5 million after-tax cumulative effect adjustment that These costs include underwriters' commissions, discounts or increased earnings, and premiums, other costs such as legal, accounting, and regulatory "*a $35.5 million after-tax cumulative effect adjustment that fees, and printing costs. We amortize these costs to expense over reduced other comprehensive income.

the life of the debt. The cumulative effect adjustment recorded in earnings repre "Whenwe incur gains or losses on debt that we retire prior to sents the fair value as of January 1, 2001 of a warrant for 705,900 maturity in our regulated utility business, we amortize those shares of common stock of Orion. The warrant had an exercise gains or losses over the remaining original life of the debt. price of $10 per share and was received in conjunction with our investment in Orion. As part of the sale of Orion to Reliant Use of Accounting Estimates Resources, Inc., we received cash equal to the difference between Management makes estimates and assumptions when preparing Reliant's purchase price of $26.80 per share and the exercise price financial statements under accounting principles generally multiplied by the number of shares subject to the warrant.

accepted in the United States of America. These estimates and The cumulative effect adjustment recorded in other compre assumptions affect various matters, including: hensive income represents certain forward sales of electricity i our reported amounts of assets and liabilities in our that we designated as cash-flow hedges of forecasted transactions Consolidated Balance Sheets at the dates of the financial primarily through our merchant energy business.

statements,

"*our disclosure of contingent assets and liabilities at the Recently Issued Accounting Standards dates of the financial statements, and In 2001, the FASB issued SEAS No. 141, Business

"*our reported amounts of revenues and expenses in our Combinations, SEAS No. 142, Goodwill and Other Intangible Consolidated Statements of Income during the Assets, SFAS No. 143, Accounting for ObligationsAssociated with reporting periods. the Retirement of Long-Lived Assets, and SFAS No. 144, These estimates involve judgments with respect to, among Accountingfor the Impairment or Disposal of Long-Lived Assets.

other things, future economic factors that are difficult to predict SFAS No. 141 requires all business combinations to be and are beyond management's control. As a result, actual accounted for under the purchase method. Use of the pooling amounts could differ from these estimates. of-interests method is prohibited for business combinations initiated after June 30, 2001. This statement also establishes Reclassifications criteria for the separate recognition of intangible assets acquired We have reclassified certain prior-year amounts for comparative in a business combination. We do not expect the adoption of purposes. These reclassifications did not affect consolidated net this statement to have a material impact on our financial results.

income for the years presented. SFAS No. 142 requires that goodwill no longer be amortized to earnings, but instead be subject to periodic testing for Accounting Standards Adopted impairment. This statement is effective for fiscal years beginning On January 1, 2001, we adopted SFAS No. 133, as amended after December 15, 2001, with earlier application permitted only by SFAS No. 138, Accounting for Certain Derivative Instruments in specified circumstances. We do not expect the adoption of and CertainHedging Activities. this statement to have a material impact on our financial results.

These statements require that we recognize all derivatives on SFAS No. 143 provides the accounting requirements for the balance sheet at fair value. Changes in the value of deriva asset retirement obligations associated with tangible long-lived tives that are not hedges must be recorded in earnings. assets. This statement is effective for fiscal years beginning after We use derivatives in connection with our power marketing June 15, 2002, and early adoption is permitted. Currently, we Constellation Energy Group, Inc. and Subsidiaries

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are evaluating this statement and have not determined its December 15, 2001, and interim periods within those fiscal impact on our financial results, however, it could be material. years, with early application encouraged. We do not expect the SEAS No. 144 replaces FASB Statement No. 121, adoption of this statement to have a material impact on our Accountingfor the JmpairmentofLong-Lived Assets andfor Long financial results. However, we expect to reclassifV our senior Lived Assets to Be Disposed Of SEAS No. 144 addresses financial living facilities business as a discontinued operation in the first reporting for the impairment or disposal of long-lived assets. quarter of 2002 as required under this standard.

This statement is effective for fiscal years beginning after Note 2. Contract Termination, Workforce Reduction, and Other Special Costs 2001 Events BGE also recorded S 13.7 million on its balance shcer as a Pre- After regulatory asset related to its gas business as discussed in Note 6 "Tax Tax on page 71.

(In mtillion,)

Workforce reduction costs: Settlement and CurtailmentCharges Voluntary termination benefits-VSERP S 70.1 S 42.5 In connection with the age 55 or older VSERP, a significant Settlement and curtailment charges 16.3 9.9 number of the participants in our nonqualified pension plans Involuntarv severance accrual 19.3 11.7 are retiring. As a result, we recognized a settlement loss of lotal workforce reduction costs 105.7 64.1 approximately $10.5 million and a curtailment loss of approxi mately $5.8 million for those plans in accordance with SEAS Contract termination related costs 224.8 139.6 No. 88, Employers'Accountingfor Settlements and Curtailments of Defined Benefit Pension Plans andfor Tennination Benefits. BGE Impairment losses and other costs: recorded $6.6 million of this amount. Additional details on the loss on sale of Guatemalan operation 43.3 28.1 VSERP and their impact on our pension and postretirement Impairments of real estate, senior-living, benefit plans are discussed in Note 7 on page 72.

and international investments 107.3 69.7 Cancellation of domestic power projects 46.9 30.5 Involuntary Severance Accrual Reduction of financial investment 4.6 2.8 The voluntary programs were designed, offered, and timed to "Iotal impairment losses and other costs 202.1 131.1 minimize the number of employees who will be involuntarily severed under our overall workforce reduction plan. Our Fotal special costs $532.6 $334.8 workforce reduction plan identified 435 jobs to be eliminated over and above position reductions expected to be satisfied through the age 55 and over VSERP and was specific as to Workforce Reduction Costs company, organizational unit, and position. However, the Voluntary Special Early Retirement Programs- VSERP number of employees that will elect to voluntarily retire under In the fourth quarter of 2001, we undertook several measures to the age 50 to 54 VSERP and how many will thereafter be reduce our workforce through both voluntary and involuntary involuntarily severed is unknown until after the election period means. The purpose of these programs was to reduce our of the VSERP ends in February 2002.

operating costs to become more competitive. We offered several In accordance with EITF 94-3, Liability Recognition/or Voluntary Special Early Retirement Programs (VSERP) to Certain Employee Termination Benefits and Other Costs to Evit an employees of Constellation Energy and certain subsidiaries. The Activity (including Certain Costs Incurred in a Restructuring), the first group of these programs offered enhanced early retirement Company recognized a liability of $25.1 million at December benefits to employees age 55 or older with 10 or more years of 31, 2001 for the targeted number of involuntary terminations service. The second group of these programs offered enhanced that will result if no employees elect the age 50 to 54 VSERP early retirement benefits to employees age 50 to 54 with 20 or The $19.3 million in the table above represents involuntary more years of service. severance charged to expense in 2001 in connection with our Since employees electing to participate in the age 55 or older workforce reduction programs. BGE recorded $12.5 million of VSERP had to make their elections by the end of 2001, the this amount. BGE also recorded $5.8 million on its balance cost of that program was reflected in 2001. The $70.1 million sheet as a regulatory asset related to its gas business as discussed in the above table reflects the portion of the total cost of that in Note 6 on page 71. We will record any additional cost in program charged to expense for the 507 employees that elected excess of the 2001 involuntary severance accrual for those to participate. BGE recorded $37.9 million of this amount. eligible participants that elect the 50 to 54 VSERP in 2002.

Constellation Energy Group. inc. and ,Subsidiaries I I

/ 65 Contract Termination Related Costs estate projects that we will continue to hold and own over On October 26, 2001, we announced the decision to remain a the next several years. The real estate projects include single company and canceled prior plans to separate our approximately 1,300 acres of land holdings in various merchant energy business from our remaining businesses. stages of development located in seven sites in the central We also announced the termination of our power business Maryland region and an operating waste water treatment services agreement with Goldman Sachs. We paid Goldman plant located in Anne Arundel County, Maryland.

Sachs a total of S355 million, representing $196.7 million to "*We decided to accelerate the exit strategy for our interest terminate the power business services agreement with our power in a Panamanian electric distribution company. As a non marketing operation and $159 million previously recognized as core asset, management has decided to reduce the cost and a payable for services rendered under the agreement. Goldman risk of holding this asset indefinitely and intends to Sachs also will not make an equity investment in our merchant dispose of this asset. We believe a sale of this investment energy business as previously announced. can be completed by mid-to-late 2003.

In addition, we terminated a software agreement we had "*We incurred an other than temporary decline in our whereby Goldman Sachs would provide maintenance, support, equity method investment in the Bolivian Generating and minor upgrades to our risk management and trading Group, which owns an interest in an electric generation system. We recognized $17.6 million in expense in the fourth concession in Bolivia. This decline in value resulted from a quarter of 2001 representing the unamortized prepaid costs deterioration of our investment's position in the dispatch related to this agreement. Finally, we incurred approximately curve of its capacity market. As a result, we recorded the

$10.5 million in employee-related expenses and advisory costs impairment in accordance with the provisions of from investment bankers and legal counsel. In total, we recog Accounting Principles Board Opinion No. 18, The Equity nized expenses of approximately $224.8 million in the fourth Method ofAccountingfor Investments in Common Stock.

quarter of 2001 relating to the termination of our relationship The impairments of our real estate, senior-living facilities, with Goldman Sachs and our decision not to separate. and Panama investments were recorded in accordance with the provisions of SFAS No. 121. These impairments resulted from Impairment Losses and Other Costs our change from an intent to hold to an intent to sell certain of Sale of Guatemalan Operation these non-core assets in 2002, and our decision to limit future On November 8, 2001, we sold our Guatemalan power plant costs and risks by accelerating the exit strategies for certain operations to an affiliate of Duke Energy International, LLC, assets that cannot be sold by the end of 2002. Previously, our the international business unit of Duke Energy. Through this strategy for these investments was to hold them until we could sale, Duke Energy acquired Grupo Generador de Guatemala y obtain reasonable value. Under that strategy, the expected cash Cia., S.C.A., which owns two generating plants at Esquintla flows were greater than our investment and no impairment was and 1*ake Amatitlan in Guatemala. The combined capacity of recognized.

the plants is 167 megawatts. We decided to sell our Guatemalan operations to focus our efforts on our core energy businesses. As Impairment ofDomestic Power Projects a result of this transaction, we are no longer committed to In the fourth quarter of 2001, our merchant energy, business making significant future capital investments in a non-core recorded impairments of $46.9 million primarily due to $40.8 operation. We recorded a $43.3 million loss on this sale. million in impairments under SFAS No. 121 associated with the termination of our planned development projects in Texas, Impairments of Real Estate, Senior-Living,and California, Florida, and Massachusetts that are not currently Other InternationalInvestments under construction. The impairments include amounts paid for In the fourth quarter of 2001, our other nonregulated the purchase of four turbines related to these development businesses recorded $107.3 million in impairments of certain projects. We decided to terminate our development projects due real estate projects, senior-living facilities, and international to the expected excess generation capacity in most domestic assets to reflect the fair value of these investments. These invest markets and the significant decline in the forward market prices ments represent non-core assets with a book value of of electricity. In accordance with the provisions of APB No. 18, approximately S140.6 million after these impairments. As part we recognized $6.1 million for an other than temporary decline of our focus on capital and cash requirements and on our core in the value of our investment in a waste burning power plant energy businesses, the following occurred: in Michigan where operating cash flows are not sufficient to pay m We decided to sell six real estate projects without further existing debt service and we are not likely to recover our equity development and all of our 18 senior-living facilities in interest in this investment.

2002 and accelerate the exit strategies for two other real Constelation Energy, Group, Inc. and Subsidiaries

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Reduction ofFinancialInvestment inability to restructure certain project agreements. For the Our financial investments business recorded a $4.6 million second project, we experienced a declining water temperature of reduction of its investment in a leased aircraft due to the other the geothermal resource used by one of the plants for than temporary decline in the estimated residual value of used production.

airplanes as a result of the September 11, 2001 terrorist attacks Our Latin American operation recorded a $7.1 million pre and the general downturn in the aviation industry. This tax, or $4.5 million after-tax, impairment to reflect the fair investment is accounted for as a leveraged lease under SEAS No. value of our investment in a generating company in Bolivia as a 13, Accounting for Leases. result of our international exit strategy at that time to focus on our core businesses.

2000 Events Our financial investments exchanged its shares of common In 2000, BGE offered a targeted VSERP to employees ages 55 stock in Capital Re, an insurance company, for common stock or older with 10 or more years of service in targeted positions of ACE Limited (ACE) as part of a business combination that elected to retire on June 1, 2000 to reduce our operating whereby ACE acquired all of the outstanding capital stock of costs to become more competitive. BGE recorded approxi Capital Re. As a result, our financial investments operation mately $10.0 million pre-tax for employees that elected to wrote-down its $94.2 million investment in Capital Re stock by participate in the program. Of this amount, BGE recorded $26.2 million pre-tax, or $16.0 million after-tax, to reflect the approximately $3.0 million on its balance sheet as a regulatory closing price of the business combination.

asset of its gas business. BGE is amortizing this regulatory asset Our real estate and senior-living facilities operations entered over a 5-year period as provided by the June 2000 Maryland into an agreement to sell all but one of its senior-living facilities PSC gas base rate order as discussed in Note 6 on page 71. The to Sunrise Assisted Living, Inc. Under the terms of the remaining $7.0 million, or $4.2 million after-tax, related to agreement, Sunrise was to acquire twelve of our existing senior BGE's electric business and was charged to expense. living facilities, three facilities under construction, and several sites under development for $72.2 million in cash and $16.0 1999 Events million in debt assumption. We could not reach an agreement Our generation operation recorded a $21.4 million pre-tax, or on financing issues that subsequently arose, and the agreement

$14.2 million after-tax, impairment of two geothermal power was terminated in November 1999. However, our real estate projects. These impairments occurred because the expected and senior-living operations recorded a $9.6 million pre-tax, or future cash flows from the projects are less than the investment $5.8 million after-tax, impairment related to the proposed sale in the projects. For the first project, this resulted from the of these facilities.

Note 3. Information by Operating Segment Our reportable operating segments are-Merchant Energy, Our remaining nonregulated businesses:

Regulated Electric, and Regulated Gas: "*provide energy products and services,

"*Our nonregulated merchant energy business in North "*sell and service electric and gas appliances, and heating and America: air conditioning systems, engage in home improvements,

• provides power marketing, origination transactions, and and sell electricity and natural gas through mass marketing risk management services, efforts,

• develops, owns, and operates generating facilities and/or "*provide cooling services, power projects in North America, and "*engage in financial investments,

• provides nuclear consulting services. i develop, own, and manage real estate and senior-living

"*Our regulated electric business purchases, distributes, and facilities, and sells electricity in Maryland. m own interests in Latin American power generation and

"*Our regulated gas business purchases, transports, and sells distribution projects and investments.

natural gas in Maryland. These reportable segments are strategic businesses based We have restated certain prior-period information for compar principally upon regulations, products, and services that require ative purposes based on our reportable operating segments. different technology and marketing strategies. We evaluate the Effective July 1, 2000, the financial results of the electric performance of these segments based on net income. We generation portion of our business are included in the merchant account for intersegment revenues using market prices. A energy business segment. Prior to that date, the financial results summary of information by operating segment is shown on the of electric generation are included in our regulated electric next page.

business.

Constellation Energy Group, Inc. and Subsidiaries I I

/ 67 Unallocated Merchant Regulated Regulated Other Corporate Energp Electric Gas Nonregulated Items and Business Business Business Businesses Eliminations Consolidated (In millions) 2001 Unaffiliated revenues $ 614.3 $2,039.6 $ 674.3 $ 600.1 $ - $3,928.3 Intersegment revenues 1,151.2 0.4 6.4 2.0 (1,160.0)

Total revenues 1,765.5 2,040.0 680.7 602.1 (1,160.0) 3,928.3 Depreciation and amortization 174.9 173.3 47.7 23.2 - 419.1 Fixed charges 25.8 135.8 28.5 48.7 - 238.8 Income tax expense (benefit) 25.2 36.8 25.7 (49.8) - 37.9 Cumulative effect of change in accounting principle - - - 8.5 - 8.5 Net income (loss) (a) 93.1 50.9 37.5 (90.6) - 90.9 Segment assets 8,134.3 3,764.9 1,104.2 1,314.0 (239.8) 14,077.6 Capital expenditures 1,815.0 180.3 58.7 35.0 - 2,089.0 2000 Unaffiliated revenues $ 421.1 $2,134.7 S 603.8 $ 692.9 $ $3,852.5 Intersegment revenues 604.6 0.5 7.8 20.4 (633.3)

Total revenues 1,025.7 2,135.2 611.6 713.3 (633.3) 3,852.5 Depreciation and amortization 83.6 319.9 46.2 20.3 470.0 Equity in income of equity-method investees (b) - 2.4 - - 2.4 Fixed charges 18.3 168.4 27.3 65.8 (8.4) 271.4 Income tax expense 118.5 72.2 21.9 17.5 230.1 Net income (c) 198.6 102.3 30.6 13.8 345.3 Segment assets 7,295.5 3,392.3 1,089.9 1,491.5 (329.9) 12,939.3 Capital expenditures 699.0 290.3 59.7 131.5 1,180.5 1999 Unaffiliated revenues $ 277.3 $2,258.8 $ 476.5 $ 828.3 $ $3,840.9 Intersegment revenues - 1.2 11.6 20.1 (32.9)

Total revenues 277.3 2,260.0 488.1 848.4 (32.9) 3,840.9 Deoreciation and amortization 7.5 376.4 44.9 21.0 449.8 Equity in income of equity-method investees (b) 5.1 5.1 Fixed charges 174.2 26.1 56.1 (1.4) 255.0 Income tax expense (benefit) 29.2 149.2 18.1 (10.1) 186.4 Extraordinary loss 66.3 66.3 Net income (loss) (d) 52.4 198.8 33.0 (24.1) - 260.1 Segment assets 1,259.0 6,312.6 915.3 1,239.7 18.5 9,745.1 Capital expenditures 163.0 366.8 69.2 115.2 - 714.2 (a) Our merchant energy business, our regulatedelectric business, our regulatedgas business, and our other nonregulatedbusinesses recognized$198.1 million.

$33.6 million, $0.8 million, and $102.3 million, respectively for workforce reduction costs, contract termination relatedcosts, and impairmentlosses and other costs as describedmore fully in Note 2 (b) Our merchantenergy business records its equity in the income of equity method investees in unaffiliated revenues.

(c) Our regulatedelectric business recordedexpense of $4.2 million related to employees that elected to participatein a Voluntary Special Early Retirement Program. In addition, our merchant energy business recordeda $15.0 million deregulation transition cost incurred by our power marketing operation.

(d) Our regulatedelectric business recorded expense of$4.9 million relatedto HurricaneFloyd. Our merchant energy business recorded $14.2 million for the impairment oftwo geothermialpower plants. Our Latin American operation recorded$4.5 million for the impairment to reflect the fair value ofour investment in a power project in Bolivia. Our financialinvestments operation recorded$16.0 million for the reduction ofits investment in CapitalRe stock to reflect the market value of this investment. Our real estate and senior-livingfacilities operation recorded $5.8 millionfor the impairmentof certainsenior-livingfacilties.

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Note 4. Investments Real Estate Projects and Investments Investments Classified as Available-for-Sale Real estate projects and investments held by Constellation Real We classify the following investments as available-for-sale:

Estate Group (CREG), consist of the following: "*nuclear decommissioning trust funds, 2001 2000 "*our other nonregulated businesses' marketablc equity (In millions) securities (shown above), and Properties under development $100.5 $165.1

"*Orion.

Operating properties This means we do not expect to hold them to maturity, and (net of accumulated depreciation) 0.9 12.7 we do not consider them trading securities.

Equity interest in real estate investments 109.3 112.5 Effective June 1, 2001, we changed our accounting for the Total real estate projects and investments $210.7 $290.3 investment in Orion from the equity method to the cost method. This change resulted from no longer having significant See Note 2 on page 65 for a discussion of impairments influence as required under equity method accounting due to a in 2001. reduction in our ownership percentage. Our ownei ship percentage decreased due to Orion's issuance of 13 million Power Projects shares of common stock that were sold in a public offering and Investments in power projects held by our merchant energy due to our sale of one million shares as part of the offering. At business consist of the following: December 31, 2001, the unrealized gain on our investment in Orion was $244.0 million. In addition, at December 31, 2001, At December 31, 2001 2000 we owned a warrant for 705,900 shares of common stock in (In millions)

Orion with a fair market value of $11.8 million. These warrants Equity Method $480.3 $488.4 are accounted for under SFAS No. 133 as discussed in Note 1 Cost Method 10.7 10.8 on page 63.

Total power projects $491.0 $499.2 We show the fair values, gross unrealized gains and losses, and amortized cost bases for all of our available-for-sale Our percentage voting interest in power projects accounted securities, in the following tables. We use specific identification for under the equity method ranges from 16% to 50%. Equity to determine cost in computing realized gains and losses, except in earnings of these power projects were $24.2 million in 2001, we use average cost basis for our investment in Orion.

$50.2 million in 2000, and $49.7 million in 1999.

Our power projects accounted for under the equity method Amortized Unrealized Unrealized Fair include investments of $296.4 million in 2001 and $297.9 At December 31, 2001 Cost Basis Gains Losses \Value million in 2000 that sell electricity in California under power  :,In millions) purchase agreements called "Interim Standard Offer No. 4" Marketable equity securities $773.9 $270.6 $(10.3) $1,034.2 agreements. We discuss these projects further in Note 11 on Corporate debt and page 83. U.S. Government agency 47.7 1.5 - 49.2 Our Latin American operation held power projects of State municipal bonds 38.4 3.3 (0.2) 41.5

$8.1 million at December 31, 2001 and $11.4 million at "4otals $860.0 $275.4 $(10.5) $1,124.9 December 31, 2000.

See Note 2 on page 65 for a discussion of impairments recorded in 2001. AmortiLed Unrcalized Unre, izied Fair At December 31, 2000 Cost Basis Gains losses Value lIn millions)

Orion and Financial Investments Marketable equity securities $171.8 S68.9 $(2.2) S238.5 Financial investments consist of the following: Corporate debt and At December 31, 2001 2000 U.S. Government agency 26.1 0.1 (0.1) 26.1 (In millions) State municipal bonds 61.3 2.3 (0.4) 63.2 Orion $442.5 $192.0 Totals $259.2 S71.3 $(2.7) $327.8 Marketable equity securities 20.2 105.9 Financial limited partnerships 25.8 32.7 In addition to the above securities, the nuclear decommis Leveraged leases 14.7 22.4 sioning trust funds included $7.7 million at December 31, Total financial investments $503.2 $353.0 2001 and $6.8 million at December 31, 2000 of cash and cash equivalents.

Constellation Energy Group, Inc. andSubsidiaries I I

/69 The preceding tables include $21.0 million in 2001 and The corporate debt securities, U.S. Government agency

$34.7 million in 2000 of unrealized net gains associated with obligations, and state municipal bonds mature on the following the nuclear decommissioning trust funds that are reflected as a schedule:

change in the nuclear decommissioning trust funds in our At December 31, 2001 Amount Consolidated Balance Sheets. (In millions)

Gross and net realized gains and losses on available-for-sale Less than 1 year $ 8.4 securities were as follows:

1-5 years 34.3 5-10 years 22.2 2001 2000 1999 More than 10 years 25.8 (In millions)

Total maturities of debt securities $90.7 Gross realized gains $47.6 $54.5 $ 11.7 Gross realized losses (7.9) (8.0) (38.8)

Net realized gains (losses) $39.7 $46.5 $(27.1)

Note 5. Rate Matters and Accounting Impacts of Deregulation On April 8, 1999, Maryland enacted the Electric Customer electricity to all customers in areas traditionally served Choice and Competition Act of 1999 (the "Act") and accompa by BGE.

nying tax legislation that significantly restructured Maryland's m BGE reduced residential base rates by approximately electric utility industry and modified the industry's tax 6.5%, on average about $54 million a year, beginning July structure. In the Restructuring Order discussed below, the 1, 2000. These rates will not change before July 2006.

Maryland PSC addressed the major provisions of the Act. n Commercial and industrial customers have up to four The tax legislation made comprehensive changes to the state service options that will fix electric energy rates and and local taxation of electric and gas utilities. Effective January transition charges for a period that ends in 2004 to 2006.

1, 2000, the Maryland public service franchise tax was altered w BGE's electric fuel rate clause was discontinued effective to generally include a tax equal to .062 cents on each kilowatt July 1, 2000.

hour of electricity and .402 cents on each therm of natural gas m Electric delivery service rates are frozen through June 2004 delivered for final consumption in Maryland. The Maryland for commercial and industrial customers. The generation 2% franchise tax on electric and natural gas utilities continues and transmission components of rates are frozen for to apply to transmission and distribution revenue. Additionally, different time periods depending on the service options all electric and natural gas utility results are subject to the selected by those customers.

Maryland corporate income tax. m BGE collects $528 million after-tax of its potentially Beginning July 1, 2000, the tax legislation also provided for stranded investments and utility restructuring costs through a two-year phase-in of a 50% reduction in the local personal a competitive transition charge on its customers' bills.

property taxes on machinery and equipment used to generate Residential customers will pay this charge through 2006.

electricity for resale and a 60% corporate income tax credit for Commercial and industrial customers will pay in a lump real property taxes paid on those facilities. sum or over a period ending in 2004 to 2006, depending On November 10, 1999, the Maryland PSC issued a on the service option selected by each customer.

Restructuring Order that resolved the major issues surrounding m Generation-related regulatory assets and nuclear decom electric restructuring, accelerated the timetable for customer missioning costs are included in delivery service rates choice, and addressed the major provisions of the Act. The effective July 1, 2000 and will be recovered on a basis Restructuring Order also resolved the electric restructuring approximating their amortization schedules prior to proceeding (transition costs, customer price protections, and July 1, 2000.

unbundled rates for electric services) and a petition filed in m Effective July 1, 2000, BGE unbundled rates to show September 1998 by the Office of People's Counsel (OPC) to separate components for delivery service, competitive lower our electric base rates. The major provisions of the transition charges, standard offer services (generation),

Restructuring Order are: transmission, universal service, and taxes.

mAll customers can choose their electric energy supplier 0 Effective July 1, 2000, BGE transferred, at book value, its beginning July 1, 2000. BGE will provide a standard offer ten Maryland-based fossil and nuclear power plants and its service for customers that do not select an alternative partial ownership interest in two coal plants and a hydro supplier. In either case, BGE will continue to deliver electric plant in Pennsylvania to nonregulated subsidiaries of Constellation Energy.

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"*BGE reduced its generation assets by $150 million pre-tax extent that the net book value of each impaired electric gener during the period July 1, 1999 - June 30, 2000 to mitigate ation plant exceeded its fair value, we reduced its book value.

a portion of BGE's potentially stranded investments. Under the Restructuring Order, BGE will recover $528

"*Universal service is being provided for low-income million after-tax of its potentially stranded investments and customers without increasing their bills. BGE will provide utility restructuring costs through the competitive transition its share of a statewide fund totaling $34 million annually. charge component of its customer rates beginning July 1, 2000.

As discussed in Note 1 on page 57, EITF 97-4 requires that This recovery mostly relates to the stranded costs associated a company should cease applying SFAS No. 71 when either with the Calvert Cliffs Nuclear Power Plant, whose book value legislation is passed or a regulatory body issues an order that was substantially higher than its estimated fair value. However, contains sufficient detail to determine how the transition plan Calvert Cliffs was not considered impaired under the provisions will affect the deregulated portion of the business. Additionally, of SFAS No. 121 since its estimated future undiscounted cash a company would continue to recognize regulatory assets and flows exceeded its book value. Accordingly, BGE did not record liabilities in the Consolidated Balance Sheets to the extent that any impairment related to Calvert Cliffs. However, BGE recog the transition plan provides for their recovery. nized after-tax impairment losses totaling $115.8 million We believe that the Restructuring Order provided sufficient associated with certain of its fossil plants under the provisions of details of the transition plan to competition for BGE's electric SFAS No. 121.

generation business to require BGE to discontinue the appli BGE had contracts to purchase electric capacity and energy cation of SFAS No. 71 for that portion of its business. that became uneconomic upon the deregulation of electric gener Accordingly, in the fourth quarter of 1999, we adopted the ation. Therefore, BGE recorded a $34.2 million after-tax charge provisions of SIAS No. 101 and EITF 97-4 for BGE's electric based on the net present value of the excess of estimated contract generation business. costs over the market-based revenues to recover these costs over SFAS No. 101 requires the elimination of the effects of rate the remaining terms of the contracts. In addition, BGE had regulation that have been recognized as regulatory assets and deferred certain energy conservation expenditures that would not liabilities pursuant to SIAS No. 71. However, EITF 97-4 be recovered through its transmission and distribution business requires that regulatory assets and liabilities that will be under the Restructuring Order. Accordingly, BGE recorded a recovered in the regulated portion of the business continue to $10.3 million after-tax charge to eliminate the regulatory asset be classified as regulatory assets and liabilities. The previously established for these deferred expenditures.

Restructuring Order provided for the creation of a single, new At December 31, 1999, the total charge for BGE's electric generation-related regulatory asset to be recovered through generating plants that were impaired, losses on uneconomic BGE's regulated transmission and distribution business. We purchased capacity and energy contracts, and deferred energy discuss this further in Note 6 on page 71. conservation expenditures was approximately $160.3 million Pursuant to SFAS No. 101, the book value of property, plant after-tax.

and equipment may not be adjusted unless those assets are BGE recorded approximately $94.0 million of the $160.3 impaired under the provisions of SEAS No. 121. The process million on its balance sheet. This consisted of a $150.0 million we used in evaluating and measuring impairment under the regulatory asset of its regulated transmission and distribution provisions of SFAS No. 121 involved two steps. First, we business, net of approximately $56.0 million of associated compared the net book value of each generating plant to the deferred income taxes. The regulatory asset was amortized as it estimated undiscounted future net operating cash flows from was recovered from ratepayers through June 30, 2000. This that plant. An electric generating plant was considered impaired accomplished the $150 million reduction of its generation when its undiscounted future net operating cash flows were less plants required by the Restructuring Order.

than its net book value. Second, we computed the fair value of BGE recorded an after-tax, extraordinary charge against each plant that is determined to be impaired based on the earnings for approximately $66.3 million related to the present value of that plant's estimated future net operating cash remaining portion of the $160.3 million described above that flows discounted using an interest rate that considers the risk of was not recovered under the Restructuring Order.

operating that facility in a competitive environment. To the Constellation Energy Group, Inc. and Subsidiaries I I

/71 Note 6. Regulatory Assets (net)

As discussed in Note 1 on page 57, the Maryland PSC provides and deferred taxes on deferred investment tax credits. We the final determination of the rates we charge our customers for amortize these amounts as the temporary differences reverse.

our regulated businesses. Generally, we use the same accounting policies and practices used by nonregulated companies for Deferred Postretirement and financial reporting under accounting principles generally Postemployment Benefit Costs accepted in the United States of America. However, sometimes Deferred postretirement and postemployment benefit costs are the Maryland PSC orders an accounting treatment different the costs we recorded under SFAS No. 106 (for postretirement from that used by nonregulated companies to determine the benefits) and No. 112 (for postemployment benefits) in excess rates we charge our customers. When this happens, we must of the costs we included in the rates we charge our customers.

defer certain utility expenses and income in our Consolidated We began amortizing these costs over a 15-year period in 1998.

Balance Sheets as regulatory assets and liabilities. We then We discuss these costs further in Note 7 on page 72.

record them in our Consolidated Statements of Income (using amortization) when we include them in the rates we charge our Deferred Environmental Costs customers. Deferred environmental costs are the estimated costs of investi We summarize regulatory assets and liabilities in the gating and cleaning up contaminated sites we own. We discuss following table, and we discuss each of them separately below. this further in Note 11 on page 80. We are amortizing $21.6 At December 31, 2001 2000 million of these costs (the amount we had incurred through (In millions) October 1995) and $6.4 million of these costs (the amount we incurred from November 1995 through June 2000) over 10 Electric generation-related regulatory asset $249.0 $267.8 Income taxes recoverable through future rates (net) 95.6 101.2 year periods in accordance with the Maryland PSC's orders.

Deferred postretirement and postemployment benefit costs 35.5 38.7 Deferred Fuel Costs Deferred environmental costs 26.0 28.8 As described in Note 1 on page 58, deferred fuel costs are the Deferred fuel costs (net) 33.5 71.1 difference between our actual costs of electric fuel, net purchases Workforce reduction costs 21.6 2.8 and sales of electricity, and natural gas, and our fuel rate Other (net) 2.6 4.5 revenues collected from customers. We reduce deferred fuel Total regulatory assets (net) $463.8 $514.9 costs as we collect them from or refund them to our customers.

We show our deferred fuel costs in the following table.

Electric Generation-Related Regulatory Asset At December 31, 2001 2000 With the issuance of the Restructuring Order, BGE no longer (In millions) met the requirements for the application of SFAS No. 71 for Electric $ - $42.3 the electric generation portion of its business. In accordance Gas 33.5 28.8 with SFAS No. 101 and EITF 97-4, all individual generation Deferred fuel costs (net) $33.5 $71.1 related regulatory assets and liabilities must be eliminated from our balance sheet unless these regulatory assets and liabilities Under the terms of the Restructuring Order, BGE's electric will be recovered in the regulated portion of the business.

fuel rate clause was discontinued effective July 1, 2000. In Pursuant to the Restructuring Order, BGE wrote-off all of its September 2000, the Maryland PSC approved the collection of individual, generation-related regulatory assets and liabilities.

the $54.6 million accumulated difference between our actual BGE established a single, new generation-related regulatory costs of fuel and energy and the amounts collected from asset for amounts to be collected through its regulated trans customers that were deferred under the electric fuel rate clause mission and distribution business. The new regulatory asset is through June 30, 2000. We collected this accumulated being amortized on a basis that approximates the pre-existing difference from customers over the twelve-month period ending individual regulatory asset amortization schedules.

October 2001.

Income Taxes Recoverable Through Future Rates (net)

Workforce Reduction Costs As described in Note 1 on page 60, income taxes recoverable The portions of the workforce reduction costs associated with through future rates are the portion of our net deferred income the VSERP and involuntary severance programs we announced tax liability that is applicable to our regulated utility business, in 2001 and 2000 that relate to BGE's gas business are deferred but has not been reflected in the rates we charge our customers.

as regulatory assets in accordance with the Maryland PSC's These income taxes represent the tax effect of temporary differ orders in prior rate cases. These costs are amortized over 5-year ences in depreciation and the allowance for equity funds used periods. See Note 2 on page 64 and Note 7 on page 72.

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Note 7. Pension, Postretirement, Other Postemployment, and Employee Savings Plan Benefits We offer pension, postretirement, other postemployment, and Contributions for employees who retire after June 30, 1992 employee savings plan benefits. We describe each of these are calculated based on age and years of service. The amount of separately below. Nine Mile Point offers its own pension, retiree contributions increases based on expected increases in postretirement, other postemployment, and employee savings medical costs. For the life insurance plan, retirees do not make plan benefits to its employees. The benefits for Nine Mile Point contributions to cover a portion of the plan costs.

are included in the tables beginning on the next page. Effective January 1, 1993, we adopted SFAS No. 106, Employers'Accountingfor PostretirementBenefits Other Than Pension Benefits Pensions.The adoption of that statement caused:

We sponsor several defined benefit pension plans for our "*a transition obligation, which we are amortizing over 20 employees. These include the basic, qualified plan that most years, and employees participate in and several nonqualified plans that are "*an increase in annual postretirement benefit costs.

available only to certain employees. A defined benefit plan For our nonregulated businesses, we expense all postre specifies the amount of benefits a plan participant is to receive tirement benefit costs. For our regulated utility business, we using information about the participant. Employees do not accounted for the increase in annual postretirement benefit contribute to these plans. Generally, we calculate the benefits costs under two Maryland PSC rate orders:

under these plans based on age, years of service, and pay. I in an April 1993 rate order, the Maryland PSC allowed us Sometimes we amend the plans retroactively. These to expense one-half and defer, as a regulatory asset (see retroactive plan amendments require us to recalculate benefits Note 6 on page 71), the other half of the increase in related to participants' past service. We amortize the change in annual postretirement benefit costs related to our regulated the benefit costs from these plan amendments on a straight-line electric and gas businesses, and basis over the average remaining service period of active m in a November 1995 rate order, the Maryland PSC employees. allowed us to expense all of the increase in annual postre We fund the plans by contributing at least the minimum tirement benefit costs related to our regulated gas business.

amount required under Internal Revenue Service regulations. Beginning in 1998, the Maryland PSC authorized us to:

We calculate the amount of funding using an actuarial method "*expense all of the increase in annual postretirement benefit called the projected unit credit cost method. The assets in all of costs related to our regulated electric business, and the plans at December 31, 2001 were mostly marketable equity "*amortize the regulatory asset for postretirement benefit and fixed income securities. costs related to our regulated electric and gas businesses In 1999, we made the following amendments: over 15 years.

"*eligible participants were allowed to choose between an enhanced version of the current benefit formula and a new VSERP pension equity plan (PEP) formula. Pension benefits for In 200"1, our Board of Directors approved several voluntary eligible employees hired after December 31, 1999 are retirement programs for Constellation Energy and certain based on a PEP formula, and subsidiaries. The first group of these programs offered enhanced

"*pension and survivor benefits were increased for partici early retirement benefits to employees age 55 or older with 10 pants who retired prior to January 1, 1994 and for their or more years of service. The second group of these programs surviving spouses. offered enhanced early retirement benefits to employees age 50 The financial impacts of the amendments are included in to 54 with 20 or more years of service.

the tables beginning on the next page. Since employees electing to participate in the age 55 or older VSERP had to make their elections by the end of 2001, the cost Postretrement Benefits of that program was reflected in 2001. The total cost of that We sponsor defined benefit postretirement health care and life program was approximately $83.8 million ($63.5 million in insurance plans that cover substantially all of our employees. pension termination benefits, $18.5 million in postretirement Generally, we calculate the benefits under these plans based on benefit costs, and $1.8 million in education and outplacement age, years of service, and pension benefit levels. We do not fund assistance costs). Of this amount, BGE recorded approximately these plans. $13.7 million on its balance sheet as a regulatory asset of its gas For nearly all of the health care plans, retirees make contri business. This amount will be amortized over a 5-year period as butions to cover a portion of the plan costs. provided for in prior Maryland PSC rate orders.

ConstellationEnergy Group, Inc. and Subsidiaries I I

/ 73 In connection with the retirement of a significant number of Pension Postretirement Benefits Benefits the participants in the nonqualified pension plans we recog 2001 2000 2001 2000 nized a settlement loss of approximately $10.5 million and a (In millions) curtailment loss of approximately $5.8 million for those plans Change in benefit obligation in accordance with SFAS No. 88. Benefit obligation Since the age 50 to 54 programs allow employees to make at January 1 $1, 045.1 $1,016.7 $375.9 $358.7 their elections beginning in January through February 2002, the Service cost 25.8 25.4 8.4 7.7 cost of that program will be reflected in 2002. Interest cost 76.1 73.1 29.2 26.6 We recorded a $133.0 million additional minimum pension Plan participants' liability adjustment as a result of the combination of decreases contributions - 3.0 2.8 Actuarial loss 42.6 0.8 49.1 40.9 in the fair value of plan assets due to a declining equity market Plan amendments 6.7 (41.1) in 2001 and an increased pension liability primarily due to the VSERP charge 63.5 7.6 18.5 2.4 VSERP. We charged $59.0 million of this adjustment to an Curtailment 9.7 intangible asset included in "Other deferred charges" in our (23.0)

Settlement Consolidated Balance Sheets. The remaining $74.0 million, or Nine Mile Point acquisition 91.8 15.0

$44.7 million after-tax, of this adjustment was included in Benefits paid (72.4) (85.2) (23.9) (22.1)

"Accumulated other comprehensive income" in our Benefit obligation at Consolidated Statements of Common Shareholders' Equity and December 31 $1,259.2 $1,045.1 $475.2 $375.9 Consolidated Statements of Capitalization.

In 2000, we offered a targeted VSERP to provide enhanced early retirement benefits to certain eligible participants in Pension Postretirement targeted jobs at BGE that elected to retire on June 1, 2000. Benefits Benefits BGE recorded approximately $10.0 million ($7.6 million for 2001 2000 2001 2000 pension termination benefits and $2.4 million for postre (In millions)

Change in plan assets tirement benefit costs) for employees that elected to participate Fair value of plan assets in the program. Of this amount, BGE recorded approximately at January 1 $1,030.1 $1,084.9 $- $

$3.0 million on its balance sheet as a regulatory asset of its gas Actual return on business. We amortize this regulatory asset over a 5-year period. plan assets (42.7) 3.7 -

The remaining $7.0 million related to BGE's electric business Employer contribution 39.4 26.7 20.9 19.3 was charged to expense. Plan participants' The cost of the 2001 and 2000 voluntary retirement contributions - - 3.0 2.8 programs and the settlement or curtailment losses are not Benefits paid (72.4) (85.2) (23.9) (22.1) included in the tables of net periodic pension and postre Fair value of plan assets tirement benefit costs. at December 31 $ 954.4 $1,030.1 $- $

Obligations, Assets, and Funded Status We show the change in the benefit obligations, plan assets, and Pension Postretirement Benefits Benefits funded status of the pension and postretirement benefit plans 2001 2000 2001 2000 including the effect of the Nine Mile Point acquisition, in the (In millions) following tables. Funded Status Funded Status at December 31 $(304.8) $(15.0) $(475.2) $(375.9)

Unrecognized net actuarial loss 207.8 49.2 107.8 61.4 Unrecognized prior service cost 56.7 59.2 (0.4) (0.4)

Unrecognized transition obligation - - 86.9 94.8 Unamortized net asset from adoption of SFAS No. 87 - (0.2) -

Pension liability adjustment (133.0) -

(Accrued) prepaid benefit cost $(173.3) $93.2 $(280.9) $(220.1)

Constellation Energy Group, Inc. and Subsidiaries

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Net Periodic Benefit Cost million as of December 31, 2001 and would increase the We show the components of net periodic pension benefit cost combined service and interest costs of the postretirement in the following table: benefit cost by approximately $5.9 million annually.

Year Ended December 31, 2001 2000 1999 A one-percent decrease in the health care inflation rate from (In millions) the assumed rates would decrease the accumulated postre Components of net periodic tirement benefit obligation by approximately $51.1 million as pension benefit cost of December 31, 2001 and would decrease the combined Service cost $25.8 $25.4 S26.1 service and interest costs of the postretirement benefit cost by Interest cost 76.1 73.1 65.3 approximately $4.7 million annually.

Expected return on plan assets (87.5) (83.6) (76.6)

Amortization of transition obligation (0.2) (0.2) (0.2) Other Postemployment Benefits Amortization of prior service cost 6.5 6.5 2.5 We provide the following postemployment benefits:

Recognized net actuarial loss 2.8 2.6 10.1 "*health and life insurance benefits to eligible employees Amount capitalized as construction cost (2.5) (3.4) (4.2) who are found to be disabled under our Disability Net periodic pension benefit cost $21.0 $20.4 $23.0 Insurance Plan, and

"*income replacement payments for employees found to be We show the components of net periodic postretirement disabled before November 1995 (payments for employees benefit cost in the following table: found to be disabled after that date are paid by an Year Ended December 31, 2001 2000 1999 insurance company, and the cost is paid by employees).

(In millions) The liability for these benefits totaled $48.7 million as of Components of net periodic December 31, 2001 and $46.7 million as of December 31, 2000.

postretirement benefit cost Effective December 31, 1993, we adopted SFAS No. 112, Service cost $ 8.4 $ 7.7 $ 8.6 Employers'Accountingfor Postemployment Benefits. We deferred, Interest cost 29.2 26.6 24.4 as a regulatory asset (see Note 6 on page 71), the postem Amortization of transition obligation 7.9 7.9 11.0 ployment benefit liability attributable to our regulated utility Recognized net actuarial loss 3.3 3.1 1.9 business as of December 31, 1993, consistent with the Amount capitalized as construction cost (14.5) (10.8) (9.4) Maryland PSC's orders for postretirement benefits (described Net periodic postretirement benefit cost $34.3 $34.5 $36.5 earlier in this note).

We began to amortize the regulatory asset over 15 years Assumptions beginning in 1998. The Maryland PSC authorized us to reflect We made the assumptions below to calculate our pension and this change in our regulated electric and gas base rates to recover postretirement benefit obligations. the higher costs in 1998.

Pension Postretirement We assumed the discount rate for other postemployment Benefits Benefits benefits to be 5.0% in 2001 and 5.5% in 2000.

At December 31, 2001 2000 2001 2000 Discount rate 7.25% 7.50% 7.25% 7.50% Employee Savings Plan Benefits Expected return on We, along with several of our subsidiaries, sponsor defined plan assets 9.00 9.00 N/A N/A contribution savings plans that are offered to all eligible Rate of compensation increase 4.00 4.00 4.00 4.00 employees of Constellation Energy and certain employees of our subsidiaries. The Savings Plans are qualified 401 (k) plans We assumed the health care inflation rates to be: under the Internal Revenue Code. In a defined contribution

"*in 2001, 5.7% for Medicare-eligible retirees and 9.5% for plan, the benefits a participant is to receive result from regular retirees not covered by Medicare, and contributions to a participant account. Matching contributions

"*in 2002, 11.0% for both Medicare-eligible retirees and to participant accounts are made under these plans. Matching retirees not covered by Medicare. contributions to these plans were:

After 2002, we assumed inflation rates will decrease to 7.0% * $12.2 million in 2001, in 2003, 6.5% in 2004, 6.0% in 2005, and 5.5% annually after * $10.8 million in 2000, and 2005. * $10.4 million in 1999.

A one-percent increase in the health care inflation rate from the assumed rates would increase the accumulated postretirement benefit obligation by approximately $63.8 Constellation Enerky Group, Inc. and Subsidiaries I I

/ 75 Note 8. Short-Term Borrowings Our short-term borrowings may include bank loans, $297.2 million at December 31, 2000. Constellation Energy commercial paper, and bank lines of credit. Short-term had commercial paper outstanding of $954.9 million at borrowings mature within one year from the date of issuance. December 31, 2001 and $198.7 million at December 31, 2000.

We pay commitment fees to banks for providing us lines of The weighted-average effective interest rates for credit. When we borrow under the lines of credit, we pay Constellation Energy's commercial paper were 3.73% for the market interest rates. year ended December 31, 2001 and 6.3 1% for 2000.

Constellation Energy BGE In anticipation of separating our merchant energy business from BGE had no commercial paper outstanding at December 31, our other businesses and to fund working capital requirements 2001 and $32.1 million at December 31, 2000.

and capital expenditures, in June 2001, Constellation Energy At December 31, 2001, BGE had unused committed bank arranged a $2.5 billion, 364-day revolving credit facility. lines of credit totaling $243.0 million supporting the However, since we canceled prior plans to separate, we used this commercial paper program compared to $218.0 million at facility primarily to fund capital expenditures, and working December 31, 2000. BGE has a $25 million revolving credit capital requirements, including commercial paper support, for agreement that is available through 2003. At December 31, the merchant energy business. 2001 and 2000, BGE did not have any borrowings under the In June 2001, Constellation Energy also arranged a $380 revolving credit agreement. This agreement also supports BGE's million, 364-day revolving credit facility to be used primarily to commercial paper program.

support letters of credit and for other short-term financing The weighted-average effective interest rates for BGE's needs, including commercial paper support. Constellation commercial paper were 2.53% for the year ended December Energy also has an existing $188.5 million, multi-year revolving 31, 2001 and 6.36% for 2000.

credit facility available for short-term and long-term needs, including support for the issuance of letters of credit. Other Nonregulated Businesses Constellation Energy had committed bank lines of credit as Our other nonregulated businesses had short-term borrowings described above of $3.1 billion at December 31, 2001 and outstanding of $20.1 million at December 31, 2001 and $12.8

$565.0 million at December 31, 2000 for short-term financial million at December 31, 2000. The weighted-average effective needs, including support for the issuance of letters of credit. interest rates for our other nonregulated businesses' short-term These agreements also support Constellation Energy's borrowings were 4.20% for the year ended December 31, 2001 commercial paper program. Letters of credit issued under all of and 8.59% for 2000.

our facilities totaled $245.8 million at December 31, 2001 and Note 9. Long-Term Debt Long-term debt matures in one year or more from the date of BGE issuance. We summarize our long-term debt in the BGE's FirstRefunding Mortgage Bonds Consolidated Statements of Capitalization. As you read this BGE's first refunding mortgage bonds are secured by a section, it may be helpful to refer to those statements. mortgage lien on all of its assets. The generating assets BGE transferred to subsidiaries of Constellation Energy also remain Constellation Energy subject to the lien of BGE's mortgage, along with the stock of On January 17, 2001, we issued $400.0 million of Safe Harbor Water Power Corporation and Constellation Mandatorily Redeemable Floating Rate Notes that matured on Enterprises, Inc.

January' 17, 2002. BGE is required to make an annual sinking fund payment On April 11, 2001, we issued $235.0 million of each August 1 to the mortgage trustee. The amount of the Mandatorily Redeemable Floating Rate Notes that matured on payment is equal to 1% of the highest principal amount of January 17, 2002. bonds outstanding during the preceding 12 months. The In 2001, we redeemed several Notes that totaled $700.0 trustee uses these funds to retire bonds from any series through million prior to their maturity for a purchase price equal to repurchases or calls for early redemption. However, the trustee 100% of their principal amount, plus accrued interest. cannot call the following bonds for early redemption:

"*7Y4% Series, due 2002

• 5X% Series, due 2004

"*6X% Series, due 2003

• 7X*% Series, due 2007

"*6X% Series, due 2003 E 6X% Series, due 2008 Constellation Energy Group, Inc. and Subsidiaries

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Holders of the Remarketed Floating Rate Series due BGE ObligatedMandatorily Redeemable September 1, 2006 have the option to require BGE to repur Trust PreferredSecurities chase their bonds at face value on September 1 of each year. On June 15, 1998, BGE Capital Trust I (Trust), a Delaware BGE is required to repurchase and retire at par any bonds that business trust established by BGE, issued 10,000,000 Trust are not remarketed or purchased by the remarketing agent. Originated Preferred Securities (TOPrS) for $250 million ($25 BGE also has the option to redeem all or some of these bonds liquidation amount per preferred security) with a distribution at face value each September 1. rate of 7.16%.

The Trust used the net proceeds from the issuance of the BGEM Other Long- Term Debt common securities and the preferred securities to purchase a series On May 11, 2001, BGE issued $200.0 million of Floating Rate of 7.16% Deferrable Interest Subordinated Debentures due June Reset Notes that matured on February 5, 2002. 30, 2038 (debentures) from BGE in the aggregate principal Also on May 11, 2001, BGE redeemed $200.0 million of amount of $257.7 million with the same terms as the TOPrS.

Floating Rate Notes. The Trust must redeem the TOPrS at $25 per preferred security On December 11, 2001, BGE issued $300.0 million 5.25% plus accrued but unpaid distributions when the debentures are Notes, due December 15, 2006. paid at maturity or upon any earlier redemption. BCE has the On July 1, 2000, BGE transferred $278.0 million of tax option to redeem the debentures at any time on or after June 15, exempt debt to our merchant energy business related to the 2003 or at any time when certain tax or other events occur.

transferred assets. At December 31, 2001, BGE remains contin The interest paid on the debentures, which the Trust will use gently liable for the $276.5 million outstanding balance of this to make distributions on the TOPrS, is included in "Interest debt. expense" in our Consolidated Statements of Income and is On December 20, 2000, BGE issued $173.0 million of deductible for income tax purposes.

6.75% Remarketable and Redeemable Securities (ROARS) due BGE filly and unconditionally guarantees the TOPrS based December 15, 2012. The ROARS contain an option for the on its various obligations relating to the trust agreement, inden underwriters to remarket the ROARS on December 15, 2002. tures, debentures, and the preferred security guarantee agreement.

If the underwriters do not elect to remarket the ROARS on that The debentures are the only assets of the Trust. The Trust is date, then BGE must redeem the ROARS at 100% of the wholly owned by BGE because it owns all the common principal amount on December 15, 2002. securities of the Trust that have general voting power.

We show the weighted-average interest rates and maturity For the payment of dividends and in the event of liquidation dates for BGE's fixed-rate medium-term notes outstanding at of BGE, the debentures are ranked prior to preference stock and December 31, 2001 in the following table. common stock.

Weighted-Average Maturity Series Interest Rate Dates Other Nonregulated Businesses B 8.77% 2002-2006 Revolving CreditAgreement C 7.97 2003 ComfortLink has a $50 million unsecured revolving credit D 6.67 2004-2006 agreement that matures September 26, 2002. Under the terms E 6.66 2006-2012 of the agreement, ComfortLink has the option to obtain loans G 6.08 2008 at various rates for terms up to nine months. ComfortLink pays a facility fee on the total amount of the commitment. Under Some of the medium-term notes include a "put option." this agreement, ComfortLink had outstanding $46.0 million at These put options allow the holders to sell their notes back to December 31, 2001 and $34.0 million at December 31, 2000.

BGE on the put option dates at a price equal to 100% of the On December 18, 2001, ComfortLink entered into a $25.0 principal amount. The following is a summary of medium-term million loan agreement with the Maryland Energy Financing notes with put options. Administration (MEFA). The terms of the loan exactly match Series E Notes Principal Put Option Dates the terms of variable rate, tax exempt bonds due December 1, (In millions) 2031 issued by MEFA for ComfortLink to finance the cost of 6.75%, due 2012 building a chilled water distribution system. The interest rate on

$60.0 June 2002 and 2007 6

.75%, due 2012 $25.0 June 2004 and 2007 6

.73%, due 2012 $25.0 June 2004 and 2007 Constellation Energy Group, Inc. and Subsidiaries I I

/77 this debt resets weekly. These bonds, and the corresponding At December 31, 2001, BGE had long-term loans totaling loan, can be redeemed at any time at par plus accrued interest $221.5 million that mature after 2002 (including $110.0 while under variable rates. The bonds can also be converted to a million of medium-term notes discussed in this Note under fixed rate at ComfortLink's option. "BGE's Other Long-Term Debt") which contain certain put options under which lenders could potentially require us to Mortgage and Construction Loans repay the debt prior to maturity. Of this amount, $171.5 Our nonregulated businesses' mortgage and construction loans million could be repaid in 2002 and $50.0 million in 2004. At have varying terms. The following mortgage notes require December 31, 2001, $146.5 million is classified as current monthly principal and interest payments: portion of long-term debt as a result of these provisions.

"*4.25%, due in 2009 At December 31, 2001, our other nonregulated businesses

"*9.65%, due in 2028 had long-term loans totaling $20.0 million that mature after

"*8.00%, due in 2033 2003 that lenders could potentially require us to repay early.

The variable rate mortgage notes and construction loans This amount is classified as current portion of long-term debt as require periodic payment of principal and interest. a result of these repayment provisions.

Maturities of Long-Term Debt Weighted-Average Interest Rates for Variable Rate Debt All of our long-term borrowings mature on the following Our weighted-average interest rates for variable rate debt were:

schedule (includes sinking fund requirements): Year ended December 31, 2001 2000 Constellation Nonregulated Nornglated Businesses Year Energy Business BGE (including Constellation Energy)

(In millions) Floating rate notes 4.95% 6.98%

2002 $635.0 $ 85.4 $ 519.8 Loans under credit agreements 4.60 6.64 2003 - 86.1 285.6 Mortgage and construction loans 4.39 7.78 2004 - 83.7 155.4 Tax-exempt debt transferred from BGE 3.12 4.26 2005 300.0 78.4 46.9 Other tax-exempt debt 1.75 -

2006 - 78.4 464.9 BGE Thereafter - 357.1 947.7 Remarketed floating rate series Total long-term debt at mortgage bonds 4.49% 6.59%

December 31, 2001 $935.0 $769.1 $2,420.3 Floating rate reset notes 4.14 7.27 Medium-term notes, Series G 6.58 Medium-term notes, Series H 6.58 Nofte 10. LAeases At December 31, 2001, we owed future minimum payments There are two types of leases-operating and capital. Capital leases qualify as sales or purchases of property and are reported in for long-term, noncancelable, operating leases as follows:

our Consolidated Balance Sheets. Capital leases are not material Year in amount. All other leases are operating leases and are reported (In millions) in our Consolidated Statements of Income. We expense all lease 2002 S 9.1 payments associated with our regulated utility operations. We 2003 24.1 present information about our operating leases below. 2004 39.2 2005 37.9 2006 13.3 Outgoing Lease Payments Thereafter 145.8 We, as lessee, lease some facilities and equipment. The lease Total future minimum lease payments $269.4 agreements expire on various dates and have various renewal options.

Lease expense was: The above table includes the operating lease payments for 0 $11.7 million in 2001, the High Desert project in California through 2006. We are 0 $11.3 million in 2000, and currently leasing and supervising the construction of the High m $12.2 million in 1999. Desert project, a 750 megawatt generating facility in California.

The High Desert project uses an off-balance sheet financing Constellation Energy Group, Inc. and Subsidiaries

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structure through a special-purpose entity (SPE) that qualifies as At the conclusion of the lease term in 2006, we have the an operating lease. The project is scheduled for completion in following options:

the summer of 2003. "*renew the lease upon approval of the lessors, Under the terms of the lease, we are required to make "*elect to purchase the property for a price equal to the lease payments that represent all or a portion of the lease balance if balance at the end of the term, or one of the following events occurs: termination of construction "*request the lessor to sell the property.

prior to completion or our default under the lease. If we request the lessor to sell the property, we guarantee the In addition, we may be required to either post cash collateral sale proceeds up to approximately 83% of the lease balance.

equal to the outstanding lease balance or we may elect to The lease balance at the end of the term is currently estimated purchase the property for the outstanding lease balance. At any to be $600 million, which represents the estimated cost of the time during the term of the lease we have the right to pay off project; however, this may vary based on the ultimate cost of the lease and acquire the asset from the lessor. At December 31, construction and interest incurred during the construction 2001, the outstanding lease balance plus other committed period.

expenses was $271.2 million.

Note 11. Commitments, Guarantees, and Contingencies Commitments Our merchant energy business enters into various long-term We have made substantial commitments in connection with contracts for the procurement and delivery of fuels to supply our merchant energy, regulated gas, and other nonregulated our generating plant requirements. In most cases, our contracts business. These commitments relate to: contain provisions for price escalations, minimum purchase

"*purchase of electric generating capacity and energy, levels, and other financial commitments. These contracts expire

"*procurement and delivery of fuels, and in various years between 2002 and 2006. In addition, our

"*capital for construction programs and loans. merchant energy business enters into long-term contracts for Our merchant energy business has a long-term contract for the capacity and transmission rights for the delivery of energy to the purchase of electric generating capacity and energy that meet our physical obligations to our customers. These contracts expires in 2013. Portions of this contract became uneconomical expire in various years between 2002 and 2021.

upon the deregulation of electric generation. Therefore, we Our merchant energy business also has committed to recorded a charge and accrued a corresponding liability based contribute additional capital for our construction program and on the net present value of the excess of estimated contract costs to make additional loans to some affiliates, joint ventures, and over the market-based revenues to recover these costs over the partnerships in which they have an interest.

remaining term of the contract as discussed in Note 5 on At December 31, 2001, we estimate the future obligations of page 70. At December 31, 2001, the accrued portion of this our merchant energy business in the following table:

contract was $10.6 million.

2002 2003 2004 2005 2006 Thereafter Total (In millions)

Purchased capacity and energy $ 16.4 $ 16.0 $ 15.5 $15.1 $15.0 $ 98.5 $ 176.5 Fuel and transportation 318.1 228.3 99.5 49.1 48.8 17.7 761.5 Capital and loans 81.5 0.8 -.- 82.3 Total future obligations $416.0 $245.1 $115.0 $64.2 $63.8 $116.2 $1,020.3 Our regulated gas business enters into various long-term Sale of Receivables contracts for the procurement, transportation, and storage of BGE and BGE Home Products & Services have agreements to gas. These contracts are recoverable under BGE's gas cost sell on an ongoing basis an undivided interest in a designated adjustment clause discussed in Note I on page 58. pool of customer receivables. Under the agreements, BGE can BGE Home Products & Services has gas purchase commit sell up to a total of $25 million, and BGE Home Products &

ments of $35.0 million in 2002 and $2.2 million in 2003 Services can sell up to a total of $50 million. Under the terms related to its gas program. of the agreements, the buyer of the receivables has limited recourse against these entities. BGE and BGE Home Products Constellation Energy Group, Inc. and Subsidiaries I I

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& Services have recorded reserves for credit losses. At December Our activities require complex and often lengthy processes to 31, 2001, BGE had sold $8.1 million and BGE Home obtain approvals, permits, or licenses for new, existing, or Products & Services had sold $42.5 million of receivables under modified facilities. Additionally, the use and handling of various these agreements. chemicals or hazardous materials (including wastes) requires preparation of release prevention plans and emergency response Guarantees procedures. As new laws or regulations are promulgated, we At December 31, 2001, Constellation Energy issued guarantees assess their applicability and implement the necessary modifica in an amount up to $1,682.4 million related to credit facilities tions to our facilities or their operation, as required.

and contractual performance of certain of its nonregulated We discuss the significant matters below.

subsidiaries, including $600 million relating to the High Desert project. The actual subsidiary liabilities related to these Clean Air Act guarantees totaled $369.9 million at December 31, 2001. The Clean Air Act affects both existing generating facilities and At December 31, 2001, Constellation Nuclear guaranteed new projects. The Clean Air Act and many state laws require the $388.1 million sellers' note that financed the acquisition of significant reductions in S02 (sulfur dioxide) and NOx Nine Mile Point. This guarantee contains covenant provisions (nitrogen oxide) emissions that result from burning fossil fuels.

that require Constellation Nuclear to maintain a net worth of at The Clean Air Act also contains other provisions that could least $500 million and a ratio of current assets to current liabil materially affect some of our projects. Various provisions may ities of at least 1.1. require permits, inspections, or installation of additional At December 31, 2001, our merchant energy business had pollution control technology. Certain of these provisions are other guaranteed outstanding loans and letters of credit of described in more detail below. Since our generation portfolio is certain power projects totaling $26.7 million. diverse, both in the mix of fuels used to generate electricity, as At December 31, 2001, our other nonregulated businesses well as in the age of various facilities, the Clean Air Act require had guaranteed outstanding loans and letters of credit of real ments have different impacts in terms of compliance costs for estate projects totaling $15.9 million. each of our projects. Many of these compliance costs may be BGE guarantees two-thirds of certain debt of Safe Harbor substantial, as described in more detail below. In addition, the Water Power Corporation. At December 31, 2001, Safe Harbor Clean Air Act contains many enforcement tools, ranging from Water Power Corporation had outstanding debt of $20 million. broad investigatory powers to civil, criminal, and administrative The maximum amount of BGE's guarantee is $13.3 million. penalties and citizen suits. These enforcement provisions also Additionally at December 31, 2001, BGE guaranteed the include enhanced monitoring, recordkeeping, and reporting TOPrS of $250.0 million as discussed in Note 9 on page 76. requirements for both existing and new facilities.

We assess the risk of loss from these guarantees to be minimal. The Clean Air Act creates a marketable commodity called an SO2 "allowance." All non-exempt facilities over 25 megawatts Environmental Matters that emit S02 must obtain allowances in order to operate after We are subject to regulation by various federal, state, and local 1999. Each allowance gives the owner the right to emit one ton authorities with regard to: of S02. All non-exempt existing facilities have been allocated Mair quality, allowances based on a facility's past production and the m water quality, statutory emission reduction goals. If additional allowances are m chemical and waste management and disposal, and needed for new facilities, they can be purchased from facilities m other environmental matters. having excess allowances or from S02 allowance banks. Our The development (involving site selection, environmental projects comply with the S02 allowance caps through the assessments, and permitting), construction, acquisition, and purchase of allowances, use of emission control devices, or by operation of electric generating, transmission, and distribution qualifying for exemptions. We believe that the additional costs facilities are subject to extensive federal, state, and local environ of obtaining allowances needed for future generation projects mental and land use laws and regulations. From the beginning should not materially affect our ability to build, acquire, and phases of siting and developing, to the ongoing operation of operate them.

existing or new electric generating, transmission, and distri The Clean Air Act also requires states to impose annual bution facilities, our activities involve compliance with diverse operating permit fees. These fees are based on the tons of pollu laws and regulations that address emissions and impacts to air tants emitted from a generating facility and vary based on the and water, special, protected, and cultural resources (such as type of facility. For example, fees will typically be greater for wetlands, endangered species, and archeological/historical coal-fired plants than for natural gas-fired plants. Our portfolio resources), chemical and waste handling, and noise impacts. includes coal-fired plants and gas-fired plants, as well as plants Constellation Energy Group, Inc. and Subsidiaries

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using renewable energy sources such as solar and geothermal, In general, such standards can require the installation of which have far less emissions. The fees do not significantly additional air pollution control equipment upon the major increase our costs. modification of an existing plant. Although there have not The Ozone Transport Assessment Group, composed of state been any new source review-related suits filed against our facil and local air regulatory officials from the 37 Mid-Western and ities, there can be no assurance that any of them will not be the Eastern states, has recommended additional NOx emission target of an action in the future. Based on the levels of reductions that go beyond current federal standards. These emissions control that the EPA and/or states are seeking in these recommendations include reductions from utility and industrial new source review enforcement actions, we believe that material boilers during the summer ozone season. additional costs and penalties could be incurred, and/or planned As a result of the Ozone Transport Assessment Group's capital expenditures could be accelerated, if the EPA was recommendations, on October 27, 1998, the Environmental successful in any future actions regarding our facilities.

Protection Agency (EPA) issued a rule requiring 22 Eastern The Clean Air Act requires the EPA to evaluate the public states and the District of Columbia to reduce emissions of NOx health impacts of emissions of mercury, a hazardous air (a precursor of ozone). Among other things, the EPA's rule pollutant, from coal-fired plants. The EPA has decided to establishes an ozone season, which runs from May through control mercury emissions from coal-fired plants. Compliance September, and a NOx emission budget for each state, could be required by approximately 2007. Final regulations are including Maryland and Pennsylvania. The EPA rule requires expected to be issued in 2004 and would affect all coal-fired states to implement controls sufficient to meet their NOx boilers. The cost of compliance could be material.

budget by May 30, 2004. Coal-fired power plants are a Future initiatives regarding greenhouse gas emissions and principal target of NOx reductions under this initiative, global warming continue to be the subject of much debate. The however, some of our newer coal-fired plants may already meet related Kyoto Protocol was signed by the United States but has the EPA expectations and will not require the same amount of not yet been ratified by the U.S. Senate. Future initiatives on capital expenditures. this issue and the ultimate effects of the Kyoto Protocol on us Many of the generation facilities are subject to NOx are unknown at this time. As a result of our diverse fuel reduction requirements under the EPA rule including those portfolio, our contribution to greenhouse gases varies. Fossil located in Maryland and Pennsylvania. This regulation affects fuel-fired power plants, however, are significant sources of both new and existing facilities causing additional capital carbon dioxide emissions, a principal greenhouse gas. Therefore, investment. At the Brandon Shores facility we have installed our compliance costs with any mandated federal greenhouse gas and at our Wagner facility we are installing, emission reduction reductions in the future could be significant.

equipment by May 2002 to meet Maryland regulations issued pursuant to EPA's rule. The owners of the Keystone plant in Waste Disposal Pennsylvania are installing emissions reduction equipment by The EPA and several state agencies have notified us that we are 2003 to meet Pennsylvania regulations issued pursuant to EPA's considered a potentially responsible party with respect to the rule. We estimate that the equipment needed at these plants will cleanup of certain environmentally contaminated sites owned cost approximately $290 million. Through December 31, 2001, and operated by others. We cannot estimate the cleanup costs we have spent approximately $200 million. for all of these sites.

Over the past two years, the EPA and several states have filed We can, however, estimate that our current 15.47% share of suits against a number of coal-fired power plants in Mid the reasonably possible cleanup costs at one of these sites, Metal Western and Southern states alleging violations of the Bank of America, a metal reclaimer in Philadelphia, could be as deterioration prevention and non-attainment provisions of the much as $2.3 million higher than amounts we have recorded as Clean Air Act's new source review requirements. In 2000, using a liability on our Consolidated Balance Sheets. This estimate is its broad investigatory powers, the EPA requested information based on a Record of Decision issued by the EPA.

relating to modifications made to our Brandon Shores, Crane, Also, we are coordinating investigation of several sites where and Wagner plants in Baltimore, Maryland. The EPA also sent gas was manufactured in the past. The investigation of these similar, but narrower, information requests to two of our newer sites includes reviewing possible actions to remove coal tar. In Pennsylvania waste-coal burning plants. We have responded to late December 1996, we signed a consent order with the the EPA and are waiting to see if the EPA takes any further Maryland Department of the Environment (MDE) that action. This information is to determine compliance with the required us to implement remedial action plans for contami Clean Air Act and state implementation plan requirements, nation at and around the Spring Gardens site, located in including potential application of federal New Source Baltimore, Maryland. We submitted the required remedial Performance Standards. action plans and they were approved by the MDE. Based on the remedial action plans, the costs we consider to be probable Constellation Fnergy Group, Inc. and Subsidiaries I I

/81 to remedy the contamination are estimated to total $47 million. "premises liability," alleging that BGE knew of and exposed We have recorded these costs as a liability on our Consolidated individuals to an asbestos hazard. The actions relate to two Balance Sheets and have deferred these costs, net of accumu types of claims.

lated amortization and amounts we recovered from insurance The first type is direct claims by individuals exposed to companies, as a regulatory asset. Because of the results of studies asbestos. BGE is involved in these claims with approximately 70 at these sites, it is reasonably possible that these additional costs other defendants. Approximately 545 individuals that were could exceed the amount we recognized by approximately $14 never employees of BGE each claim $6 million in damages ($2 million. We discuss this further in Note 6 on page 71. Through million compensatory and $4 million punitive). These claims December 31, 2001, we have spent approximately $37 million were filed in the Circuit Court for Baltimore City, Maryland in for remediation at this site. the summer of 1993. BGE does not know the specific facts We do not expect the cleanup costs of the remaining sites to necessary to estimate its potential liability for these claims. The have a material effect on our financial results. specific facts BGE does not know include:

"*the identity of BGE's facilities at which the plaintiffs Litigation allegedly worked as contractors, In the normal course of business, we are involved in various "* the names of the plaintiffs employers, and legal proceedings. We discuss the significant matters below. "* the date on which the exposure allegedly occurred.

To date, 36 of these cases were settled for amounts that were California not significant.

Baldwin Associates, Inc. v. Gray Davis, Governor of California The second type is claims by one manufacturer-Pittsburgh and 22 other defendants (including ConstellationPower Corning Corp. (PCC)-against BGE and approximately eight Development, Inc., a subsidiaryof ConstellationPower, Inc.) others, as third-party defendants. On April 17, 2000, PCC This class action lawsuit was filed on October 5, 2001 in the declared bankruptcy, and BGE does not expect PCC to Superior Court, County of San Francisco. The action seeks prosecute these claims.

damages of $43 billion, recession and reformation of approxi These claims relate to approximately 1,500 individual plain mately 38 long-term power purchase contracts, and an tiffs and were filed in the Circuit Court for Baltimore City, injunction against improper spending by the state of California. Maryland in the fall of 1993. To date, about 375 cases have Constellation Power Development, Inc. is named as a defendant been resolved, all without any payment by BGE. BGE does not but does not have a power purchase agreement with the State of know the specific facts necessary to estimate its potential California. However, our High Desert Power Project does have liability for these claims. The specific facts we do not know a power purchase agreement with the California Department of include:

Water Resources. We believe this case is without merit. "* the identity of BGE facilities containing asbestos manufac However, we cannot predict the timing, or outcome, of it or its tured by the manufacturer, possible effect on our financial results. "*the relationship (if any) of each of the individual plaintiffs to BGE, Employment Discrimination "*the settlement amounts for any individual plaintiffs who Miller, et. al v. Baltimore Gas and Electric Company et al.- This are shown to have had a relationship to BGE, and action was filed on September 20, 2000 in the U.S. District "*the dates on which/places at which the exposure allegedly Court for the District of Maryland. Besides BGE, Constellation occurred.

Energy Group, Constellation Nuclear, and Calvert Cliffs Nuclear Until the relevant facts for both types of claims are deter Power Plant are also named defendants. The action seeks class mined, BGE is unable to estimate what its liability, if any, certification for approximately 150 past and present employees might be. Although insurance and hold harmless agreements and alleges racial discrimination at Calvert Cliffs Nuclear Power from contractors who employed the plaintiffs may cover a Plant. The amount of damages is unspecified, however the plain portion of any awards in the actions, the potential liability tiffs seek back and front pay, along with compensatory and could be material.

punitive damages. The Court scheduled a briefing process for the motion to certify the case as a class action suit for the Asset Transfer Order beginning of 2003. We believe this case is without merit. On July 6, 2000, the Mid-Atlantic Power Supply Association However, we cannot predict the timing, or outcome, of it or its (MAPSA) and Shell Energy LLC filed, in the Circuit Court for possible effect on our, or BGE's, financial results. Baltimore City, a petition for review and a delay of the Maryland PSC's order approving the transfer of BGE's gener Asbestos ation assets issued on June 19, 2000. The Court denied Since 1993, BGE has been involved in several actions MAPSA's request for a delay on August 4, 2000, and after a concerning asbestos. The actions are based upon the theory of hearing on the petition on August 23, 2000 issued an order on Constellation Energy Group, Inc. and Subsidiaries

82 /

September 29, 2000 upholding the Maryland PSC's order on insured by our insurance company within a 12-month period, the asset transfer. On October 27, 2000, MAPSA filed an they will be treated as one event and the owners of the plants appeal with the Maryland Court of Special Appeals challenging will share one full limit of each type of policy (currently $3.24 the September 29, 2000 order issued by the Circuit Court. The billion). Claims that arise out of terrorist acts are also covered Court of Special Appeals heard oral arguments on the appeal on by our nuclear liability and worker radiation policies. However, September 7, 2001. We also believe that this petition is without these policies are subject to one industry aggregate limit merit. However, we cannot predict the timing or outcome of (currently $200 million) for the risk of terrorism. Unlike the this case, which could have a material adverse effect on our, and property and accidental outage policies, however, an industry BGE's, financial results. wide retrospective assessment program applies above the industry limit (see below for an explanation of this program).

RestructuringOrder If there were an accident or an extended outage at any unit In early December 1999, MAPSA, Trigen-Baltimore Energy of Calvert Cliffs or Nine Mile Point, it could have a substantial Corporation, and Sweetheart Cup Company, Inc. filed appeals adverse financial effect on us.

of the Restructuring Order, which were consolidated in the Baltimore City Circuit Court. MAPSA also filed a motion to Liability Insurance delay implementation of the Restructuring Order, pending a Pursuant to the Price-Anderson Act, we are required to insure decision on the merits of the appeals by the court. against public liability claims resulting from nuclear incidents to On April 21, 2000, the Circuit Court dismissed MAPSAs the full limit of approximately $9.5 billion. We have purchased appeal based on a lack of standing (the right of a parry to bring the maximum available commercial insurance of $200 million, a lawsuit to court) and denied its motion for a delay of the and the remaining $9.3 billion is provided through mandatory Restructuring Order. However, MAPSA filed an appeal of this participation in an industry-wide retrospective assessment decision. On May 24, 2000, the Circuit Court dismissed both program. Under this retrospective assessment program, we can the Trigen and Sweetheart Cup appeals. be assessed up to $352.4 million per incident, payable at no MAPSA subsequently filed several appeals with the more than $40 million per incident per year. This assessment Maryland Court of Special Appeals, the Maryland Court of also applies in excess of our worker radiation claims insurance Appeals, and the Baltimore City Circuit Court. The effect of and is subject to inflation and state premium taxes. In addition, the appeals was to delay the implementation of customer choice the U.S. Congress could impose additional revenue-raising in BGE's service territory. measures to pay claims.

However, on August 4, 2000, the delay was rescinded and Some of the provisions of this Act expire in August 2002, and BGE retroactively adjusted its rates as if customer choice had the Act is subject to change if those provisions are extended.

been implemented July 1, 2000. While we expect these provisions to be extended, we do not On September 29, 2000, the Baltimore City Circuit Court know what impact any changes to the Act may have on us.

issued an order upholding the Restructuring Order.

On October 27, 2000, MAPSA filed an appeal with the Worker Radiation Claims Insurance Maryland Court of Special Appeals challenging the September We participate in the American Nuclear Insurers Master Worker 29, 2000 order issued by the Circuit Court. The Court of Program that provides coverage for worker tort claims filed for Special Appeals heard oral arguments on the appeal on radiation injuries. Effective January 1, 1998, this program was September 7, 2001. We believe that this petition is without modified to provide coverage to all workers whose nuclear merit. However, we cannot predict the timing or outcome of related employment began on or after the commencement date this case, which could have a material adverse effect on our, and of reactor operations. Waiving the right to make additional BGE's, financial results. claims under the old policy was a condition for acceptance under the new policy. We describe the old and new policies below:

Nuclear Insurance "*Nuclear worker claims reported on or after January 1, We maintain nuclear insurance coverage for Calvert Cliffs and 1998 are covered by a new insurance policy with an Nine Mile Point in four program areas: liability, worker annual industry aggregate limit of $200 million for radiation claims, property, and accidental outage. However, radiation injury claims against all those insured by this these policies have certain industry standard exclusions, such as policy.

ordinary wear and tear and war. Terrorist acts, while not "*All nuclear worker claims reported prior to January 1, excluded from the property and accidental outage policies, are 1998 are still covered by the old policy. Insureds under the covered as a common occurrence, meaning that if terrorist acts old policies, with no current operations, are not required occur against one or more commercial nuclear power plants to purchase the new policy described above, and may still Constellation Fnergy Group, Inc. andSubsidiaries I I

/ 83 make claims against the old policies through 2007. If California Power Purchase Agreements radiation injury claims under these old policies exceed the Our merchant energy business has $296.4 million invested in policy reserves, all policyholders could be retroactively operating power projects of which our ownership percentage assessed, with our share being up to $6.3 million. represents 146 megawatts of electricity that are sold to Pacific The sellers of Nine Mile Point retain the liabilities for Gas & Electric (PGE) and to Southern California Edison existing and potential claims that occurred prior to November (SCE) in California under power purchase agreements. Our 7, 2001. In addition, the Long Island Power Authority, which merchant energy business was not paid in full for its sales from continues to own 18 percent of Unit 2 at Nine Mile Point, is these plants to the two utilities from November 2000 through obligated to assume its pro rata share of any liabilities for retro early April 2001. At December 31, 2001, our portion of the spective premiums and other premiums assessments. If claims amount due for unpaid power sales from these utilities was under these policies exceed the coverage limits, the provisions of approximately $45 million. We recorded reserves of approxi the Price-Anderson Act would apply. mately 20% of this amount.

These projects entered into agreements with PGE and SCE Property Insurance that provide for five-year fixed-price payments averaging $53.70 Our policies provide $500 million in primary and an additional per megawatt-hour plus the stated capacity payments in the

$2.25 billion in excess coverage for property damage, deconta original Interim Standard Offer No. 4 (S04) contracts. These mination, and premature decommissioning liability for Calvert agreements also provide for the payment of all past due Cliffs or Nine Mile Point. If accidents at any insured plants amounts plus interest, which the projects expect to collect cause a shortfall of funds at the industry mutual insurance within the next two years. The SCE agreement to pay these past company, all policyholders could be assessed, with our share due amounts is contingent on SCE making certain payments to being up to $56.2 million. other creditors.

As a result of ongoing litigation before the FERC regarding Accidental Outage Insurance sales into the spot markets of the California Independent Our policies provide indemnification on a weekly basis resulting System Operator and Power Exchange, we may be required to from an accidental outage of a nuclear unit. Initial coverage pay refunds of between $3 and $4 million for transactions that begins after a 12-week deductible period and continues at we entered into with these entities for the period between 100% of the weekly indemnity limit for 52 weeks and 80% of October 2000 and June 2001. While the process at FERC is the weekly indemnity limit for the next 110 weeks. Our ongoing, FERC has indicated that we will have the ability to coverage is up to $490.0 million per unit at Calvert Cliffs, reduce the potential refund amount in order to recover

$335.4 million for Unit 1 of Nine Mile Point, and $412.6 outstanding receivables we are owed. FERC also has indicated million for Unit 2 of Nine Mile Point. This amount can be that it will consider adjustments to the refund amount to the reduced by up to $98.0 million per unit at Calvert Cliffs and extent we can demonstrate that its refund methodology resulted

$82.5 million for Nine Mile Point if an outage at either plant is in an overall revenue shortfall for our transactions in these caused by a single insured physical damage loss. markets during the refund period.

Note 12. Risk Management Activities and Fair Value of Financial Instruments Risk Management Activities In 2001, we entered into forward starting interest rate swap At December 31, 2001, these swaps were designated as cash contracts to manage a portion of our interest rate exposure for flow hedges under SFAS No. 133. We recorded this unrealized anticipated long-term borrowings to refinance our outstanding gain in "Other current assets" in our Consolidated Balance commercial paper obligations and maturing long-term debt. The Sheets and "Accumulated other comprehensive income," net of swaps have notional or contract amounts that total $800 million associated deferred income tax effects, in our Consolidated with an average rate of 4.9% and expire in the first quarter of Statements of Common Shareholders' Equity and Consolidated 2002. The notional amounts of the contracts do not represent Statements of Capitalization. Any gain or loss on the hedges will amounts that are exchanged by the parties and are not a measure be reclassified from 'Accumulated other comprehensive income" of our exposure to market or credit risks. The notional amounts into "Interest expense" and be included in earnings during the are used in the determination of the cash settlements under the periods in which the interest payments being hedged occur.

contracts. At December 31, 2001, the fair value of these swaps In 2002, we entered into additional forward starting interest was an unrealized pre-tax gain of $36.3 million. rate swaps with notional amounts that total $700 million.

These swaps have an average rate of 5.9% and expire in the first quarter of 2002.

Constellation Energy Group, Inc and Subsidiaries

84/

Our power marketing operation manages the commodity m for long-term debt: the fair value is based on quoted price risk of our electric generation operations as part of its market prices where available or by discounting remaining overall portfolio. In order to manage this risk, our merchant cash flows at current market rates.

energy business may enter into fixed-price derivative or non We show the carrying amounts and fair values of financial derivative contracts to hedge the variability in future cash flows instruments included in our Consolidated Balance Sheets in the from forecasted sales of electricity and purchases of fuel as following table, and we describe some of the items separately discussed in Note 1 on page 59. later in this section.

At December 31, 2001, our merchant energy business had designated certain fixed-price forward electricity sale contracts as At December 31, 2001 2000 cash-flow hedges of forecasted sales of electricity for the years Carrying Fair Carrying Fair 2002 through 2010 under SFAS No. 133. Amount Value Amount Value At December 31, 2001, our merchant energy business (in millions) recorded net unrealized pre-tax gains of $76.5 million on these Investments and other assets hedges, net of associated deferred income tax effects, in for which it is:

"Accumulated other comprehensive income." We expect to Practicable to reclassify $5.7 million of net pre-tax gains on cash-flow hedges estimate fair value $1,144.9 $1,144.9 $ 349.8 $ 349.8 Not practicable to from "Accumulated other comprehensive income" into earnings estimate fair value 25.8 N/A 32.7 N/A during the next twelve months based on the market prices at Fixed-rate long-term December 31, 2001. However, the actual amount reclassified debt 2 ,945.3 3,069.6 2,734.1 2,819.9 into earnings could vary from the amounts recorded at Variable-rate long-term December 31, 2001 due to future changes in market prices. In debt 1,179.1 1,179.1 1,331.8 1,331.8 2001, there was no hedge ineffectiveness recognized in earnings.

At December 31, 2000, our merchant energy business It was not practicable to estimate the fair value of invest recorded deferred pre-tax hedge losses of $58.3 million in ments held by our nonregulated businesses in several financial "Other deferred charges" in our Consolidated Balance Sheets partnerships that invest in nonpublic debt and equity securities.

for the fixed-price forward electricity sale contracts designated as This is because the timing and amount of cash flows from these a hedge of forecasted sales of electricity. We reclassified these investments are difficult to predict. We report these investments deferred hedge losses, net of associated deferred income tax at their original cost in our Consolidated Balance Sheets.

effects, to "Accumulated other comprehensive income" upon The investments in financial partnerships totaled $25.8 the adoption of SFAS No. 133, in the first quarter of 2001. million at December 31, 2001 and $32.7 million at December 31, 2000, representing ownership interests up to 11%. The Fair Value of Financial Instrumnts total assets of all of these partnerships totaled $5.4 billion at The fair value of a financial instrument represents the amount December 31, 2000 (which is the latest information available).

at which the instrument could be exchanged in a current trans action between willing parties, other than in a forced sale or Guarantees liquidation. Significant differences can occur between the fair It was not practicable to determine the fair value of certain loan value and carrying amount of financial instruments that are guarantees of Constellation Energy and its subsidiaries.

recorded at historical amounts. We use the following methods Constellation Energy guaranteed outstanding debt of and assumptions for estimating fair value disclosures for $47.9 million at December 31, 2001 and $341.0 million financial instruments: at December 31, 2000.

"*cash and cash equivalents, net accounts receivable, other Our merchant energy business guaranteed outstanding current assets, certain current liabilities, short-term debt totaling $414.8 million at December 31, 2001 and borrowings, current portion of long-term debt, and certain $33.6 million at December 31, 2000.

deferred credits and other liabilities: because of their short Our other nonregulated businesses guaranteed outstanding term nature, the amounts reported in our Consolidated debt totaling $15.9 million at December 31, 2001 and Balance Sheets approximate fair value, $16.5 million at December 31, 2000.

"*investments and other assets where it was practicable to BGE guaranteed outstanding debt of $263.3 million at estimate fair value: the fair value is based on quoted December 31, 2001 and 2000.

market prices where available, and We do not anticipate that we will need to fund these guarantees.

ConstellationEnergy Group, Inc. andSubsidiaries I I

/ 85 Note 13. Stock-Based Compensation As permitted by SFAS No. 123, Accountingfor Stock-Based Performance-Based Restricted Stock Awards Compensation, we measure our stock-based compensation in In addition, we issue common stock based on meeting certain accordance with Accounting Principles Board Opinion (APB) performance and service goals over a three to five year period.

No. 25, Accountingfor Stock Issued to Employees, and related This stock vests to participants at various times ranging from interpretations. three to five years or less. In accordance with APB No. 25, we Under our existing long-term incentive plans, we can issue recognize compensation expense for our restricted stock awards awards that include stock options and performance-based using the variable accounting method. In 2001, due to non restricted stock to officers and key employees. Under the plans, attainment of performance criteria, we recorded a credit to we can issue up to a total of 6,000,000 shares for these awards. compensation expense of $10.1 million. We recorded compen sation expense of $16.3 million for 2000 and $10.5 million for Stock Options 1999. Summarized share information for our restricted stock In May 2000, our Board of Directors approved the issuance of awards is as follows:

nonqualified stock options. Options have been granted at prices 2001 2000 1999 not less than the market value of the stock at the date of grant, (In thousands, except per share amounts) generally become exercisable ratably over a three-year period Outstanding, beginning of year 377 323 350 beginning one year from the date of grant, and expire ten years Granted 87 353 358 from the date of grant. In accordance with APB No. 25, no Released to participants - (277) (362) compensation expense is recognized for the stock option Cancelled (29) (22) (23) awards. Summarized information for our stock option awards is Available for grant, end of year 435 377 323 as follows: Weighted-average fair value 2001 2000 restricted stock granted $35.24 $32.89 $28.61 Weighted- Weighted Average Average Exercise Exercise Pro-forma Information Shares Price Shares Price Disclosure of pro-forma information regarding net income and (In thousands, except per share amounts) earnings per share is required under SFAS No. 123, which uses Outstanding, the fair value method. The fair values of our stock-based awards beginning of year 2,420 $34.65 - $ were estimated as of the date of grant using the Black-Scholes Granted 1,015 25.08 2,462 34.64 option pricing model based on the following weighted-average Exercised (512) (34.25) - assumptions:

Cancelled/

2001 2000 Expired (277) (37.74) (42) (34.25)

Risk-free interest rate 4.79% 6.37%

Outstanding, 5.0 10.0 Expected life (in years) end of year 2,646 $30.73 2,420 $34.65 Expected market price Exercisable, volatility factors 41.3% 21.0%

end of year 235 $34.25 - Expected dividend yields 1.8% 5.7%

Weighted-average fair value per share Had compensation cost for these plans been recognized of options granted $ 9.27 $ 5.60 under the fair value method, net income and basic and diluted earnings per share amounts would have been as follows:

The following table summarizes information about stock 2001 options outstanding at December 31, 2001 (shares in (In millions, except per share amounts) thousands): Pro-forma net income $87.2 Weighted-Average Pro-forma earnings per share:

Remaining Basic $ .54 Plan Exercise Number Contractual Number Diluted $ .54 Year Prices Outstanding Life Exercisable 2001 $25.08 1,015 9.9 235 The effect of applying SFAS No. 123 to our stock-based 2000 $34.25 1,631 8.4 awards results in net income and earnings per share that are not materially different from amounts reported for the year ended December 31, 2000.

Constellation Energy Group, Inc. and Subsidiaries

86 /

Note 14. Acquisition of Nine Mile Point On November 7, 2001, we completed our purchase of Nine Nine Mile Point Net Assets Acquired Mile Point located in Scriba, New York. Nine Mile Point At November 7, 2001 consists of two boiling-water reactors. Unit 1 is a 6 09-megawatt (In millions) reactor that entered service in 1969. Unit 2 is a 1,14 8-megawatt Current Assets $135.4 reactor that began operation in 1988. Nuclear Decommissioning Trust Fund 441.7 Nine Mile Point Nuclear Station, LLC, a subsidiary of Net Property, Plant and Equipment 292.6 Constellation Nuclear, purchased 100 percent of Nine Mile Intangible Assets (details below) 38.7 Point Unit 1 and 82 percent of Unit 2. Approximately one-half Total Assets Acquired 908.4 of the purchase price, or $380 million, in addition to settlement costs of $2.7 million, was paid at closing. The remainder is Current Liabilities 16.9 being financed through the sellers in a note to be repaid over Deferred Credits and five years with an interest rate of 11.0%. This note may be Other Liabilities 120.7 prepaid at any time without penalty. The sellers also transferred Net Assets Acquired 770.8 to us approximately $442 million in decommissioning funds. Note to Sellers 388.1 As a result of this purchase, we own 1,550 megawatts of Nine Total cash paid $382.7 Mile Point's 1,757 megawatts of total generating capacity.

Niagara Mohawk Power Corporation was the sole owner of The intangible assets acquired consist of the following:

Nine Mile Point Unit 1. The co-owners of Unit 2 who sold Weighted their interests are: Niagara Mohawk (41 percent), New York Average State Electric and Gas (18 percent), Rochester Gas & Electric Description Amount Useful Life Corporation (14 percent), and Central Hudson Gas & Electric (In millions) (In years)

Corporation (9 percent). The Long Island Power Authority will Operating procedures and manuals $23.4 10 continue to own 18 percent of Unit 2. Permits and licenses 12.9 27 We will sell 90 percent of our share of Nine Mile Point's Software 2.4 5 output back to the sellers at an average price of nearly $35 per Total intangible assets $38.7 megawatt-hour for approximately 10 years under power purchase agreements. The contracts for the output are on a unit In 2002, Niagara Mohawk, or its successor, will provide contingent basis (if the output is not available because the plant funds equal to the net pension obligation of Nine Mile Point is not operating, there is no requirement to provide output employees following a more precise estimate of this obligation.

from other sources). Refer to Note 7 on page 72 for additional information.

Constellation Energy Group, Inc. and Subsidiaries I I

/ 87 Note 15. Quarterly Financial Data (Unaudited)

Our quarterly financial information has not been audited but, in management's opinion, includes all adjustments necessary for a fair presentation. Our business is seasonal in nature with the peak sales periods generally occurring during the summer and winter months.

Accordingly, comparisons among quarters of a year may not represent overall trends and changes in operations.

2001 Quarterly Data 2000 Quarterly Data Earnings Earnings Earnings Earnings Income Applicable Per Share of Income Applicable Per Share of from to Common Common from to Common Common Revenue Operations Stock Stock Revenue Operations Stock Stock (In millions, except per-shareamounts) (In millions, except per-shareamounts)

Quarter Ended Quarter Ended March 31 $1,147.1 $235.0 $111.8 $0.74 March 31 $ 994.0 $184.6 S 72.1 $0.48 June 30 843.2 171.0 75.6 0.46 June 30 866.6 132.1 39.6 0.26 September 30 1,036.1 317.5 163.6 1.00 September 30 968.6 313.4 147.5 0.98 December 31 901.9 (365.7) (260.1) (1.59) December 31 1,023.3 212.5 86.1 0.57 Year Ended Year Ended December 31 $3,928.3 $357.8 $ 90.9 $0.57 December 31 $3,852.5 $842.6 $345.3 $2.30 Our first quarter results include a $8.5 million after-tax gain Our first quarter results include a $2.5 million after-tax for the cumulative effect of adopting SFAS No. 133. expense for BGE employees that elected to participate in a Our fourth quarter results include workforce reduction costs, targeted VSERP as discussed in more detail in Note 2 on contract termination related costs, and impairment losses and page 66.

other costs totaling $334.8 million after-tax. For details, refer to Our second quarter results include:

Note 2 on page 64. " a $15.0 million after-tax deregulation transition cost to Goldman Sachs incurred by our power marketing operation to provide BGE's standard offer service requirements, and

"*a $1.7 million after-tax expense for the VSERP as discussed in more detail in Note 2 on page 66.

The sum ofthe quarterlyearningsper share amounts may not equal the totalfor the year due to the effects of roundingand dilution as a result of issuing common shares during theyear.

Certain prior-yearamounts have been reclassified to conform with the currentyear' presentation.

ConstellationEnergy Group, Inc. and Subsidiaries

88 / BOARD OF DIRECTORS Christian H. Poindexter Mayo A. Shattuck III Douglas L Becker James T. Brady Chairman, Presidentand Chairmanand Chief ManagingDirector, ConstellationEnergy Group ChiefExecutive Officer, Executive Officer, Sylvan Mid-Atlantic of Ballantrae Board ofDirectors Constellation Energy Group LearningSystems, Inc. International Ltd Age 63 Age 47 Age 36 Age 61 Director since 1988" Director since 1994"* Director since 1998" Director since 1998"*

Frank P Bramble, Sr. Beverly B. Byron Edward A. Crooke James R. Curtiss, Esq.

ChiefExecutive USA, Former Congresswoman, Retired Vice Chairman, Partner Winston & Strawn Allied Irish Banks, p.l.c. U.S. House of Representatives Constellation Energy Group Age 48 and Chairman, Age 69 Age 63 Director since 1994" Allfirst Financial,Inc. Director since 1993" Director since 1988" Age 53 Director since 2002 Roger W Gale Dr. Freeman A. Edward J. Kelly III Nancy Lampton Senior Advisor, PA Hrabowski III Presidentand ChiefExecutive Chairman and Chief Consulting President, University of Officer, Mercantile Bankshares Executive Officer American Age 55 MarylandBaltimore County Corporation Life and Accident Insurance Director since 1995"* Age 51 Age 48 Company of Kentucky Director since 1994" Director since 2001 Age 59 Director since 1994" Charles R. Larson Robert J. Lawless Michael D. Sullivan Admiral United States Navy Chairman,President and Chairman,Life Source, Inc.

(Retired) ChiefExecutive Officer Age 62 Age 65 McCormick & Company, Inc. Director since 1992*

Director since 1998" Age 55 Director since 2001

• Formerly a BGE Director,was elected to the Constellation Energy Group Board of Directorsin April 1999 at the formation of the holding company.

Formerly a Directorof a subsidiary was elected to the ConstellationEnergy Group Board of Directorsin May 1999.

Constellation Energy Group, Inc. and Subsidiaries I I

Committees of the Board Executive Committee Committee on Management Christian H. Poindexter, Chairperson Michael D. Sullivan, Chairperson Mayo A. Shattuck III Douglas L. Becker Frank P. Bramble, Sr. Frank P. Bramble, Sr.

Edward A. Crooke Edward J. Kelly III Edward J. Kelly III Robert J. Lawless Robert J. Lawless Committee on NuclearPower Audit Committee James R. Curtiss, Chairperson James T. Brady, Chairperson Beverly B. Byron Freeman A. Hrabowski III Adm. Charles RI Larson (Ret.)

Nancy Lampton Roger W. Gale ConstellationEnergy Group, Inc andSubsidianes

90 / EXECUTIVE TEAM ConstellationEnergy's executive team is diverse in experience, background,andpoint of view. Those who are steeped in the knowledge and experience of Constellation work side-by-side with those who have been recruitedfor their expertise gained aroundthe world. Together they combine the right mix of energy industry tradition and competitive business savvy necessaryfor today's changing energy landscape.

Christian H. Poindexter Mayo A. Shattuck III Thomas V. Brooks Chairman ofthe Board Presidentand Chiefbxecutive Officer President, ConstellationPower Source 63, joined BGE* in 1967; served as Project 47, joined Constellation Energy in 2001. 39, joined Constellation Energy in 2001 as Engineer during Calvert Cliffs Nuclear Power Prior to this he was Chairman, DB Alex. Vice President, Business Development &

Plant's construction; was Chief Nuclear Brown, and CEO-Private Client and Asset Strategy. Prior to this, he was Vice President, Engineer 1974-76; became Treasurer-Assistant Management Group, Americas, and Global Goldman Sachs working with Constellation Secretary in 1978 and Vice President Head-Private Banking Division. In 1991, he to develop its power marketing business, Engineering and Construction in 1980; was elected President and COO of Alex. previously served as director, Enron Capital named President and CEO of Constellation Brown, Inc., which merged with Bankers & Trade Resources, joining them when they Holdings, Inc., in 1985; elected BGE Vice Trust in 1997; served as Bankers Trust Vice bought AERX, Inc., a company he helped Chairman in 1989 and Chairman, President, Chairman until it merged with Deutsche found that specialized in emissions CEO in 1993. Bank in 1999, served as Co-Head of Global credit trading Investment Banking for Deutsche Bank, and Co-Chairman and Co-CEO of DB Alex Brown and Deutsche Bank Securities until 2001.

Frank 0. Heintz Michael J. Wallace Thomas F. Brady Presidentand ChiefEvecutwe Officer, BGE President,Constellation GenerationGroup Vice President, CorporateStrategy 54, joined Constellation Energy in 2002. & Development 58, joined BGE* in 1996 as Vice President, assuming leadership of its Gas Division in Prior to this he was co-founder and Managing 52, also Chairman of BGE HOME, 1997; elected Executive Vice President, Director, Barrington Energy Partners, LLC, Constellation Energy Source, and our other BGE Utility Operations Group in 1998. an energy industry strategic consulting firm nonregulated businesses. Joined BGE* in 1969, Prior to this he served 13 years as Chairman, Previously he served as Senior Vice President became Assistant Treasurer-Assistant Secretary in Maryland Public Service Commission and Chief Nuclear Officer, Unicom/ComEd 1983, elected Vice President, Accounting &

of Illinois Economics in 1988, Vice President, Customer Service & Accounting in 1991, Vice President Customer Service & Distribution in 1993; Vice President Retail Services 1998; and assumed current position in 1999 ConstellationEnergy Group, Inc. and Subsidiaries

/91 Paul J. Allen David A. Brune E. Follin Smith Vice lresident,CorporateAffairs Vice President, Senior Vice Presidentand General Counsel and Secretary ChiefFinancialOfcer 50, joined Constellation Energy in 2001.

Prior to this he was Senior Vice President 61, joined BGE* in 1976; named General 42, joined Constellation Energy in 2001.

and Group Head-Ogilvy Public Relations, Counsel in 1984; elected CFO, Vice Prior to this she was Senior Vice President managing its energy and environment President-Finance & Accounting and and CFO of Armstrong Holdings, Inc.

practice. Previously he served as senior staff Corporate Secretary in 1997 and took over Previously, she spent 15 years with General member at Natural Resources Defense his current position in 2001.

Motors (GM), starting in the New York Treasurer's Office; other positsons included Council; Press Secretary for U.S. Senator Treasurer-GM of Canada Limited; Vice Christopher Dodd, and National Publsc President of Finance for GMAC; Assistant Radio's Editor of "Morning Edition" and Treasurer for GM, and CFO for GM's then Foreign News Editor.

Delphi Chassis Systems division John R. Collins Diane L Featherstone Elaine W.Johnston Vice President,Management Consulting & Vice President,Human Resources Vice Presidentand ChiefRisk Officer Auditing 60, joined BGE* in 1987; named Manager, 44, joined BGE* in 1988; named Assistant 48, joined BGE* in 1976; in 1992 was Constellation Enterprises** HR Services in Treasurer and Director of Financial named Manager, Staff Services; elected 1998 and Managing Director- Human Management in 1995, joined Constellation President and CEO, Constellation Energy Resources & Administration, Constellation Power Source at its formation in1997, serving Source in 1997, was named to her current Power Source Holdings in January 2001 as its senior financial officer, became Managing Director-Finance and Treasurer, position in 2001.

Constellation Power Source Holdings in 2000

• On April30. 1999, ConstellationEnergy Group. Inc became the holding companyfrBaltimore Gas and Electric Company (BGE)and its subsidiaries Constellation Enterpriseswas previously owned by BGE and was the holding companyfr BGEs nonregulatedbusinesses Constellation Energy Group, Inc. and Subsidiaries

I 92 / FIVE-YEAR STATISTiCAL

SUMMARY

2001 2000 1999 199R lqq7 20200 1999) 1008 1007 Common Stock Data Quarterly Earnings Per Share First Quarter $0.74 $0.48 $0.55 $0.50 $0.43 Second Quarter 0.46 0.26 0.45 0.39 0.05 Third Quarter 1.00 0.98 0.91 1.08 1.11 Fourth Quarter (1.59) 0.57 (59057 (0 18) 009 0 12 Total $0.57 $2.30 $1.74 $2.06 $1.72

$0.7 $.30 $1.4 2.06 $1 72 Earnings Per Share Before Special Costs Included in Operations and Nonrecurring Items $2.60 $2.43 $2.48 $2.20 $2.28 Dividends Dividends Declared Per Share $0.48 $1.68 $1.68 $1.67 $1.63 Dividends Paid Per Share 0.78 1.68 1.68 1.66 1.62 Dividend Payout Ratio Reported 84.2% 73.0% 96.6% 81.1% 94.8%

Excluding special costs and nonrecurring charges 18.5% 69.1% 67.7% 75.9% 71.5%

Market Prices High $50.14 $52.06 $31.50 $35.25 $34.31 Low 20.90 27.06 24.69 29.25 24.75 Close 26.55 45.06 29.00 30.88 34.13 Capital Structure Long-Term Debt 45.1% 52.9% 48.6% 53.5% 48.3%

Short-Term Borrowings 10.7 3.2 5.4 - 4.7 BGE Preference Stock 2.1 2.5 2.7 2.8 4.4 Common Shareholders' Equity 42.1 41.4 43.3 43.7 42.6 The sum ofthe quarterly earningsper share amounts may not equal the totalfor the year due to the effects of rounding and changes in the average number ofshares outstandingthroughoutthe year.

The quarterly earningsper share amounts include certain one-time adjustments as shown in Note 15 on page 87 to the Consolidated FinancialStatements.

Constellation Energy Group, Inc. and Subsidiaries I

SHAREHOLDER INFONMATION / 93 Common Stock Dividends and Price Ranges 2001 2000 Dividend Price Dividend Price Declared High Low Declared High Low First Quarter $0.12 $44.65 $34.69 First Quarter $0.42 $33.81 $27.06 Second Quarter 0.12 50.14 40.10 Second Quarter 0.42 35.69 31.25 Third Quarter 0.12 43.80 22.85 Third Quarter 0.42 52.06 32.06 Fourth Quarter 0.12 28.21 20.90 Fourth Quarter 0.42 50.50 37.88 Total $0.48 Total $1.68 Dividend Policy Shareholder Investment Plan The common stock is entitled to dividends when and as declared by the Constellation Energy Group's Shareholder Investment Plan provides Board of Directors. There are no limitations in any indenture or other common shareholders an easy and economical way to acquire agreements on payment of dividends. additional shares of common stock. The plan allows shareholders to reinvest all or part of their common stock dividends; purchase Dividends have been paid on the common stock continuously since additional shares of common stock; deposit the common stock they 1910. Future dividends depend upon future earnings, the financial hold into the plan; and request a transfer or sale of shares held in condition of the company, and other factors.

their accounts.

DividendIncrease On January 30, 2002, the Board of Directors announced it will increase Stock Transfer Agents and Registrars the dividend to 96 cents per share (24 cents quarterly). The company Transfer Agent and Registrar:

had been paying an annual rate of 48 cents per share (12 cents Constellation Energy Group, Inc.

quarterly), which was established April 3,2001. Baltimore, Maryland Common Stock Dividend Dates Co-Transfer Agent and Registrar:

Record dates are normally on the 10th of March, June, September, and Continental Stock Transfer and Trust Company December. Quarterly dividends are customarily mailed to each share 8th Floor holder on or about the 1st of April, July, October, and January. 17 Battery Place South NewYork, NY 10004 Stock Trading Constellation Energy Group's common stock, which is traded under Shareholder Assistance and Inquiries the ticker symbol CEG, is listed on the New York, Chicago, and Pacific If you need assistance with lost or stolen stock certificates or dividend stock exchanges, and has unlisted trading privileges on the Boston, checks, name changes, address changes, stock transfers, the Shareholder Cincinnati, and Philadelphia exchanges. As of December 31,2001, Investment Plan, or other matters, you may visit our Web site at there were 54,285 common shareholders of record. www.constellationenergy.com or contact our shareholder service representatives as follows:

Annual Meeting The annual meeting of shareholders will be held at 10 a.m. on By telephone (Monday-Friday, 8 a.m.- 4:45 p.m. EST):

Friday, May 24,2002, in the 2nd Floor Conference Room of Baltimore Metropolitan Area 410-783-5920 the Gas and Electric Building, located at 39 W. Lexington Street, Within Maryland 1-800-492-2861 Baltimore, Maryland 21201. 1-800-258-0499 Outside Maryland Form 10-K By U.S. mail:

Upon written request, the company will furnish, without charge, a copy Constellation Energy Group, Inc.

of its and BGE's Annual Report on Form 10-K, induding financial Shareholder Services statements. Requests should be addressed to Constellation Energy PO. Box 1642 Group, Inc., Shareholder Services, PO. Box 1642, Baltimore, MD Baltimore, MD 21203-1642 21203-1642. In person or by overnight delivery:

Constellation Energy Group, Inc.

Auditors Shareholder Services, Room 800 PricewaterhouseCoopers LLP 39 W Lexington Street Baltimore, MD 21201 Exetcutive Orfices 250 W Pratt Street Baltimore, Maryland 21201 Mail: P.O. Box 1475, Baltimore, Maryland 21203-1475

Constellation Energy Group 250 W. Pratt Street Baltimore, Maryland 21201 www.constellationenergy.com

EXHIBIT II QUARTERLY FINANCIAL STATEMENTS AS OF JUNE 30, 2002 Calvert Cliffs Nuclear Power Plant August 1, 2002

m oConStlatio MW Energy Group Quarterly Financial Summary June 2002 Constellation Generation Group ConstellationPowerSource Baltimore Gas andElectric Company BGE Home Products andServices ConstellationEnergy Source

Constellation Energy Group and Subsidiaries Consolidated Statements of Income (Unaudited)

Three Months Ended Six Months Ended June 30, June 30, 2002 2001 2002 2001 (in Millions, Except Per ShareAmounts)

Revenues Nonregulated revenues S 449.8 $ 219.1 5 808.7 S 505.2 Regulated electric revenues 480.4 497.4 940.7 989.6 Regulated gas revenues 90.6 109.6 311.4 461.8 Total revenues 1,020.8 826.1 2,060.8 1,956.6 Expenses Operating expenses 639.0 514.7 1,308.9 1,264.8 Workforce reduction costs 13.3 39.2 Loss on sale ofturbine 6.0 6.0 Depreciation and amortization 117.2 102.0 234.3 205.6 Taxes other than income taxes 63.6 55.5 129.2 113.9 Total expenses 839.1 672.2 1,717.6 1,584.3 Gains on Sale of Investments and Other Assets 3.2 17.1 260.3 33.7 Income from Operations 184.9 171.0 603.5 406.0 Other Income 5.1 4.2 8.9 3.0 Income Before Fixed Charges and Income Taxes 190.0 175.2 612.4 409.0 Fixed Charges Interest expense 79.5 72.5 146.6 150.5 Interest capitalized and allowance for borrowed funds used during construction (20.1) (18.8) (31.9) (34.1)

BGE preference stock dividends 3.3 3.3 6.6 6.6 Total fixed charges 62.7 57.0 121.3 123.0 Income Before Income Taxes 127.3 118.2 491.1 286.0 Income Taxes Current 6.7 36.5 167.7 112.4 Deferred 41.3 8.1 17.4 (1.2)

Investment tax credit adjustments (2.0) (2.0) (4.0) (4.1)

Total income taxes 46.0 42.6 181.1 107.1 Income Before Cumulative Effect of Change in Accounting Principle 81.3 75.6 310.0 178.9 Cumulative Effect of Change In Accounting Principle, Net of Taxes of $5.6 - - - 8.5 Net Income $ 81.3 $ 75.6 $ 310.0 $ 187.4 Earnings Applicable to Common Stock S 81.3 $ 75.6 $ 310.0 S 187.4 Average Shares of Common Stock Outstanding 164.0 163.7 163.9 157.8 EARNINGS PER COMMON SHARE Merchant energy $ 0.39 $ 0.32 $ 0.57 $ 0.60 Regulated electric 0.13 0.11 0.31 0.29 Regulated gas 0.02 0.02 0.19 0.20 Other nonregulated 0.02 (0.05) (0.02) (0.09)

Earnings per share before special items and cumulative effect of change in accounting principle 0.56 0.40 1.05 1.00 Gains on sale of investments and other assets (includes Orion sales)

• 0.01 0.06 1.01 0.13 Workforce reduction costs (0.05) - (0.15)

Loss on sale of turbine * (0.02) - (0.02)

Earnings Per Share of Common Stock and Earnings Per Share of Common Stock Assuming Dilution Before Cumulative Effect of Change in Accounting Principle 0.50 0.46 1.89 1.13 Cumulative effect ofchange in accounting principle, net of income taxes - - - 0.06 Earnings Per Share of Common Stock and Earnings Per Share of Common Stock - Assuming Dilution $ 0.50 S 0.46 $ 1.89 $ 1.19 Equity investment in nonregulated businesses at end of period S 2,568.8 $ 2,937.6 $ 2,568.8 $ 2,937.6 Equity investment in utility business at end of period S 1,386.9 S 868.8 $ 1,386.9 $ 868.8 Certainprior-periodamounts have been reclassified to conform with the currentperiod'spresentation.

• Special items included in earningsfrom operations.

Constellation Energy Group and Subsidiaries Consolidated Balance Sheets June 30, December 31, 2002

• 2001 ASST aIn Mmlons)

Current Assets Cash and cash equivalents S 251.0 S 72.4 Accounts receivable (net of allowance for uncollectibles of $24.9 and S22.8, respectively) 757.9 738.9 Trading securities 882 1782 Mark4o-mark energy assets 403.0 398.4 Fuel stocks 118.2 108.0 Materials and supplies 213.4 205.3 Prepaid taxes other than income taxes 9.1 93.4 Other 36.6 65.6 Total current assets 1,877.4 1,860.2 Investments And Other Assets Real estate projects and investments 96.9 210.7 Investments in power projects 455.9 499.1 Investment in Orion Power Holdings, Inc. - 442.5 Financial investments 38.3 60.7 Nuclear decommissioning trust fimds 676.4 683.5 Mamin-wka energy assets 1,184.4 1,819.8 Other 275.0 207.4 Total investments and other assets 2,726.9 3,923.7 Property, Plant and Equipment Regulated property, plant and equipment 5,005.1 4,948.7 Noregulated generation propetty, plant amdequipment 6,676.8 6,551.1 Other norut property, plait and equipment 201.7 192.9 Nuclear fuel (net of amortization) 201.4 169.5 Accumulated depreciation (4,234.9) (4,161.8)

Net property, plant and equipment 7,850.1 7,700.4 Deferred Charges Regulatory assets (net) 428.2 463.8 Other 130.4 129.5 Total deferred charges 558.6 593.3 Total Amets S 13,013.0 S 14,077.6 LIABIIATIES AND CAPITALZATION Current Liabilities Slmor-term borrowings S 15.5 S 975.0 Current portion of long-term debt 573.5 1,406.7 Accounts payable 616.4 523.3 Mak-ta-marsket energy liabilities 275.9 323.3 Dividends declared 42.7 23.0 Other 303.5 308.2 Total current liabilities 1,827.5 3,559.5 Deferred Credits And Other Liabilities Deferred income taxes 1,335.2 1,431.0 Mark-to-nmarket energy liabilities 802.5 1,476.5 Net pension liability 126.3 173.3 Poatreurent and postemployment benefits 347.2 330.9 Deferned investment tax credits 89.6 93.4 Other 249.9 266.9 Total defemd credits and other liabilities 2,950.7 3,772.0 Long-Tern Debt Long-tarm debt of Constellation Energy 2,100.0 935.0 Long-term debt of nonegulated bminesses 403.1 769.3 First refunding mortgage bonds of BGE 1,040.7 1,040.7 Other long-team debt of BGE 918.1 1,129.6 Company obligated mandatorily redeemable trust preferred securities of subsidiamy tt holding solely 7.16% debentures of BGE due June 30,2038 250.0 250.0 Ueamnotized discount and premium (12.8) (5.2)

Current portion of long-tam debt (573.5) (1,406.7)

Total long-term debt 4,125.6 2,712.5 BGE Preference Stock Not Subject To Mandatory Redemption 190.0 190.0 Commt s Shareholder' Equity Cmmon stock 2,060.3 2,0422 Retained earnings 1,841.2 1,611.5 Accumulated other comprehensive income 17.9 189.9 Total common shareholdersF equity 3,919.2 3,843.6 Total capitalization 8,234.8 6,746.1 Total Lialitles And Capitalization S 13,013.0 $ 14,077.6

• Unaudited Certainprior-periodamounts have been reclassified to conform with the currentperiod'spresentation.

Constellation Energy Group and Subsidiaries Merchant Energy Operating Statistics ThreeMonths Ended Six Months Ended June 30, June30, 2002 2001 2002 2001 Revenues (In Millions)

Standard Offer Service Revenue finm BGE $297.0 $ 309.1 $ 569.6 $ 591.9 Other Generation Revenue 194.4 24.0 324.4 69.9 Mark-to-Market Energy Revenues 90.3 47.0 154.2 59.0 Other Revenue _F_1 3.9 - 8.9 Total Revenue $ 581.7 $ 384.0 $1.048.1 S 729.7 Sir Months Ended June 30, Hydro &

Nuclear

• Coal Oil Gas Other Total Generation by Fuel Type (%)

2002 53.8 36.8 1.8 4.4 3.2 100.0 2001 37.3 51.1 4.1 4.9 2.6 100.0

• Includes ourownership percentage ofgeneration at Nine Mile Pointas of November 2001.

Utility Operating Statistics ThreeMonths Ended Sir Months Ended June 30, June 30, 2002 2001 2002 2001 ELECTRIC Revenues (In Millions)

Residential-with househeating S 77.0 S 75.8 $ 181.5 $ 193.1

-other 137.7 130.2 252.7 245.6

-total 214.7 206.0 434.2 438.7 Commercial 210.5 228.9 402.9 426.4 industrial 46.6 54.6 88.4 106.7 System Sales 471.8 489.5 925.5 971.8 Other 8.6 8.0 15.3 18.0 Total $ 480.4 $ 497.5 $ 940.8 $ 989.8 Sales (In Thousands) - MWH Residential -with househeating 1,028 1,012 2,622 2,826

-otle" 1,689 1,551 3-292 3,136

--oDa 2717 2,563 5,914 5,962 Commercial 3,435 3,476 6,919 6,956 Industrial 1,106 1,117 2,173 2,195 Total System Sales 798 7.156 15.006 15.113 GAS Revenues (InMillions)

Residential -excluding delivery service S 54.7 $ 63.9 S 186.0 S 259.0

--delivery savice 1.9 2.3 10.1 10.8

--ot13 56.6 66.2 196.1 269.8 Conmnrcial -excluding delivery service 12.5 17.3 47.6 822.

-delivey service 52 3.9 15.8 11.1 Industial -excluding delivery service 2.1 1.9 6.2 9.0

-delivery sAvice 3.1 3.2 7.0 7.1 Systan Sales 79.5 92.5 2727 379.2 Off-System Sales 11.5 14.2 39.8 82.3 Other 1.5 2.9 3A 5.8 Total F 92.5 S109.6 S 315.9 S 467-3 Sales (In Thousands) - DTH Residential --excluding delivery service 4,460 4,672 19,317 21,145

-dewvemy service 797 1,007 3,764 5,029

-total 5,257 5,679 23,081 26,174 Conummrcial -.excluding delivery service 1,238 1,627 5,991 7,667

-delivery s*e 5,188 5,036 14,717 12,793 Industrial -excluding delivery service 145 208 752 779

--delivery service 5,174 5,701 11,442 12,111 System Sales 17,002 18,251 55,983 59,524 Off-System Sales 2,782 2,480 10,987 11,054 Total 19,784 20,731 66,970 70,578 Operatingstatisticsdo not reflect the eli,ninationof intercompany transactions.

Heating/Cooling Degree Days (Calendar-Month Basis)

Heating Degre Days - Actual 493 471 2,616 2,918

- Normal 532 536 2,960 2,969 Coing Deee Days - Actual 295 262 298 262

- Noinal 230 228 233 231

Constellation Energy Group and Subsidiaries Supplemental Financial Statistics Twelve Months Ended Jate 30, 2092 2001 Capitalization*

Long-term debt 49.0% 42.1%

Company obligated mandatonly redeemable trust preferred securities of BGE 2.9% 3.1%

Short-term bonrowings 0.2% 3.8%

BGE Preference stock 2.2% 2.3%

Comimon equity 45.7% 48.7%

Return on Average Common Equity Reported 5.5% 12.7%

Excluding special items and cumulative effect of change in accounting principle 9.8r 12.5%

Ratio of Earnings to Fixed Charges (SEC Method) 1.87 3.01 Effective Tax Rate 33.1% 37.8%

Certainprior-periodamounts have been reclassifiedto conform with the currentperiod'spresentation.

• Capitalizationincludes currentportion of long-termn debt and BGEpreferencestock and is net of cash.

Common Stock Data Three Mend, Ended Twelve Mondts Ended Jwe 30, Jame 30, 2002 2001 2002 2001 Common Stock Dividends - Per Share

-Declared $0.24 $0.12 $0.72 $1.08

-Paid $0.24 $0.12 $0.60 $I.38 Market Value Per Share

-High $32.38 $50.14 $43.80 $52.06

-Low $27.65 $40.10 $20.90 $32.06

-Close $29.34 $42.60 $29.34 $42.60 Shares Outstanding-Ead of Period (in MIllions) 164.1 163.7 164.1 163.7 Book Value per Share-End of Period $ 23.88 $ 24.32 $ 23.88 S 24.32 Certainprior-periodamounts have been reclassifiedto conform with the currentperiod'spresentation.

Inquires concerningthis sunnary should be directed to:

Foltin Snith Investor Retatom Dep "Irent ConstellationEnergy Group Senior Vice President, 410-783-3670 P. O. Bar 1475 ChiefFimacialOfficer Baltimore,Maryland 21203 410-234-5000

EXHIBIT III PROJECTED CASH FLOW FOR 12 MONTHS ENDED JULY 31, 2003 Calvert Cliffs Nuclear Power Plant August 1, 2002

Exhibit III Page 1 of 2 Internal Cash Flow Projection For Calvert Cliffs Nuclear Power Plant Percentage Ownership in all Operating Calvert Cliffs Unit No. 1 100.00%

Nuclear Units Calvert Cliffs Unit No. 2 100.00%

Maximum Total Contingent Liability (000) per Nuclear Incident $176,200 Payable at Per Year (000) $20,000 Actual Projected Twelve Months Twelve Months Ended 6/30/02 Ended 7/31/03 Non - Cash Expenses ($000)

Depreciation and Amortization $492,700 $556,800 Deferred Income Taxes and Investment Tax Credits (15,900) (13,600)

Total $476,800 $543,200 Percentage of Total to Maximum Total Contingent Liability Payable Per Year 2,384.0% 2,716%

Retained Earnings ($000)

Net Income After Taxes $213,500 Less Allowance for Funds Used During Construction $88,100 Less Dividends paid $98,300 Total $399,900 Total Internal Cash Flow $876,700 Percentage of Total Internal Cash Flow Maximum Total Contingent Liability Payable Per Year 4,383.5%

Exhibit III Page 2 of 2 Constellation Energy Group Underlying Assumptions for Projected Cash Flows (1) Depreciation is generally computed using composite straight-line rates applied to the average investment in classes of depreciable property. Vehicles are depreciated based on their estimated useful lives.

(2) Estimates of Federal income taxes and other tax expense are based upon existing tax laws and any known changes thereto.

(3) Accounting policies are consistent with those in effect June 30, 2002.

EXHIBIT IV NARRATIVE STATEMENT CURTAILMENT OF CAPITAL EXPENDITURES Calvert Cliffs Nuclear Power Plant August 1, 2002

Exhibit IV Constellation Energy Group Curtailment of Capital Expenditures Estimated construction expenditures including nuclear fuel and Allowance for Funds Used During Construction for the twelve months ended July 31, 2003 are $795.5 million. To insure that retrospective premiums under the Price Anderson Act would be available during the aforementioned twelve month period without additional funds from external sources, construction curtailments would affect all construction expenditures rather than impacting a specific project.