ML081560339

Annual Financial Report

ML081560339
Person / Time
Site:	Ginna
Issue date:	05/29/2008
From:	Harding T Constellation Energy Group
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
Download: ML081560339 (187)

Text

Tom Harding R.E. Ginna Nuclear Power Plant, LLC Acting Director- Licensing 1503 Lake Road Ontario, New York 14519-9364 585.771.3384 Thomas.harding@constellation.com Constellation Energy Nuclear Generation Group May 29, 2008 U. S. Nuclear Regulatory Commission Washington, DC 20555 ATTENTION: Document Control Desk

SUBJECT:

R.E. Ginna Nuclear Power Plant Docket No. 50-244 2007 Annual Financial Report In accordance with the U.S. Nuclear Regulatory Commission requirements of 10 CFR 50.71(b) and 10 CFR 140.21(e), enclosed is the Constellation Energy 2007 Annual Report. This report contains the financial data required by both regulations.

Should you have questions regarding this matter, please contact me at (585) 771-3384.

Very truly yours, Thomas L. Harding Attachment cc: S. J. Collins, NRC D. V. Pickett, NRC Resident Inspector, NRC io/q7

Constellation Energy- Responsible Leadership 2007TAnnual Report

Financial Highlights In millions, except per share amounts 2007 2006  % Change Common Stock Data Reported (GAAP) earnings per share $ 4.50 $ 5.16 1Loss) Income from discontinued operations $ 10.011 $ 1.04 Special Items ' $ 10.091 $ 0.51 Earnings per common share from continuing operations and before special items (adjusted earnings per share]2 $ 4.60 $ 3.61 27.4%

Dividends declared per common share $ 1 74 $ 1.51 15.2%

Average shares outstanding-assuming dilution 182.5 181.4 Market price per share-year-end $102.53 $ 68.87 48.9%

Financial. Data Total Revenues $21,193 $ 19,285 GAAP net income $ 822 $ 936 (Loss) Income from discontinued operations $ Ill $ 188 Special items (after-tax)' $ 116) $ 93 Net income from continuing operations before special items 2 $ 839 $ 655 Total assets $21,946 $21,802 Total debt $ 5,041 $ 5,101 Total common equity $ 5,340 $ 4,609 Capital expenditures $ 1,665 $ 1,149 1 Includes impairment tosses and other costs, mark-to-market gains from certain economic. non-qualifying hedges. earnings (losses) from our synthetic fuel processing facilities, deferred income tax expenses and benefits related to 2007 increase in Maryland's corporate tax rate, workforce reduction costs, gain on the sate of gas-fired plants and merger-related costs.

2 Represents a measure that is not determined in accordance with generally accepted accounting principles [GAAP).However, we believe the impact of discontinued operations, accounting changes and special items obscures trends in our results and that it is useful to consider our results excluding these items.

2005 Earnings: Our GAAP earnings per share were $3*47. Excluding special items of $0,58. our earnings per share were $2.89.

Dividend Growth 3,N I El

$1.91 1 Adjusted Earnings Per Share

$4.60 Revenues 190 $21.2 (Annual amount per share] (In billions of doltars]

Our commitment to shareholders has Our adjusted earnings per share grew Total revenues increased to $21.2 billion included increasing dividends. Since to another record high of $4.60, up in 2007.

2004, our annual dividend payments have 27 percent from 2006.

increased by more than 67 percent. Note: See Financial Highlights, including the GAAP reconciliation, above. for more details.

Contents ResponsibLe Leadership I Meeting the Energy Needs of Our Customers:, Creating Enduring Partnerships With Our Communities 10 Protecting and Preserving Our Environment I] Giving Exceptional People Opportunity for Growth 12 Delivering Performance for Our Shareholders 13 Letter to Shareholders 1, Constellation Energy at a Glance 16 Leadership 1 Understanding Our Form 10-K 19 Glossary 24 Form 10-K 2ý Shareholder Information rn-ide B* *-!

0 ~ 00 CONSTELLATION ENERGY 1

Our retirees built our company's strong foundation. Today, retirees like Richard Presberry, who had 35 years of service with the company, remain focused on our performance as shareholders.

Performance SHAREHOLDERS Shareholders invest their trust and hard-earned capital in our company. In turn, we're invested in meeting and exceeding their expectations, year after year, and we have. For the last six years, we've consistently delivered superior results for our shareholders and have become a leading energy company 2 RESPONSIBLE LEADERSHIP

right right Marcus Boston, Minh Tran, distribution construction manager, bitting trainee, BGE and payments, Constellation NewEnergy Power right Laura Szivos.

engineering anatyst, Consteltation Power Generation far right LaMetrice Dopson, director, business performance improvement ieftto right Lydia Obeng, associate-origination, Global Commodities Group Todd Mercer, energy sales consultant, Constetlation NewEnergy Gas John Fitzpatrick, I&C technician, Consteltation Energy I

Nuclear Group Opportunity EMPLOYEES Our employees truly make Constellation Energy outstanding. Our people are inspired by opportunity, challenge and growth, and we value and reward their contributions. We have a responsibility to create and foster an environment where personal development and professional success remain two of the most important results we produce.

CONSTELLATION ENERGY 3

We provide tools to help customers better manage their energy use. BGE Product-Program Manager Cynthia Edwards discusses BGE's PeakRewards program with customer Gordon Curtis, who participated in our demand response pilot program.

Solutions RESIDENTIAL CUSTOMERS The cost and consumption of energy are rapidly rising across the globe. As an energy leader, Constellation Energy's responsibility to our customers is to provide more than power or natural gas.

We promote innovative ideas that help lower demand, increase use of renewable energy and improve reliability And, we provide customers with tools to help manage their energy use in today's challenging energy marketplace.

4 RESPONSIBLE LEADERSHIP

right Greg Fox {righti, business development

manEger, Constellation Energy Projects & Services.

works with Rob below Taylor, Washington Reviewing the U.S. EPR engineering deputy, Suburban Sanitary design plans for UniStar procurement and Commission's (WSSC)

Nuclear Energy's engineering, UniStar energy manager, to possiblte fleet of new Nuclear Energy; and help WSSC expand its nuclear reactors in the Eric de Fraguier, energy portfolio to United States are [left senior vice president, include wind power.

to right) Ron Affotter, procurement and vice president, U.S. EPR engineering, UniStar deployment, AREVA NP, Nuclear Energy.

Inc.: Mark Finley, right right Ron Melchior Itefti, Michael Kagan [rightI.

director- project president, Constellation management, NewEnergy, and Constellation Energy Jonathan Kraft, Projects & Services, president and chief and Rob Threlkeld, operating officer energy manager of The Kraft Group, for General Motors, work together to know the value of reduce emissions from the newly built solar electricity used at power rooftop system every New England for GM's facitity in Patriots' home game Fontana, Calif. The by using renewable new system reduces energy certificates.

GM's energy costs and carbon footprint.

Innovation BUSINESS CUSTOMERS Our products and services help commercial, industrial and public-sector customers effectively manage their energy costs and protect their bottom lines against uncertain and volatile energy prices.

Our responsibility is to help our customers expand their vision from today to tomorrow, enabling them to proactively shape their energy future.

CONSTELLATION ENERGY 5

left Brenda Pettigrew (left),

ANN:*BGE senior community relations specialist, discusses energy-efficiency measures with customer Edith Wroten at a BGE energy conservation workshop.

above Monique Gibson tleftt, legal secretary, volunteered her time to help provide energy-efficient compact fluorescent lighting in a Baltimore neighborhood as part of a larger effort to improve life in our home city. Shown with Monique is resident Daisy McClean.

far left Christopher Boone, BGE distribution construction trainee,

/1 donates his time and talent to help build a Habitat for Humanity home.

left Katie Beltezza (rightl.

analyst-origination, Global Commodities Group, helps high school student Rebecca Crawford understand the college application process as part of our support for theB4 Students mentoring program, Partnerships OUR COMMUNITIES The decisions and investments we make today will have a meaningful effect on future generations.

Our goal- and responsibility- is to make a tangible and positive difference in the communities where we live, work and do business. Our company and our employees establish enduring partnerships that help us live up to this commitment.

6 RESPONSIBLE LEADERSHIP

We're investing in cleaner energy by instalting state-of-the-art emissions-controt equipment at our Brandon Shores Power Plant in Maryland. Tom Schwalter, construction management supervisor, Constellation Power Generation, has been overseeing this important project, which witl make the plant one of the cleanest coal-burning facilities of its size in the country.

Commitment THE ENVIRONMENT We understand it is important to do what is right for our planet. We are committed to using natural resources responsibly, reducing pollution, improving energy efficiency and enhancing environmental stewardship. We embrace these challenges and continue to apply our knowledge, skills and creativity toward meeting them. We are focusing our capital spending on initiatives to reduce emissions at our fossil-fuel power plants, and we're a leader in the potential renaissance of new nuclear power plants in the U.S. We've made significant progress, but there's more to be done.

CONSTELLATION ENERGY 7

As a enerp-v CVcbmpany, Constellation Energy has a responsibility to our shareholders, customeý...ib:':;,:,:.employ1 communities and the world around us. We evaluate and execute business decisions based on considering the needs of all those to whom we are responsible.

8 RESPONSIBLE LEADERSHIP

Meeting the Energy Needs of Our Customers The customers and communities we serve need innovative and effective solutions to keep pace with rising energy demands. We're committed to meeting these needs ... it's the very foundation of responsible leadership.

BGE HOME Certified usage during high-priced, high-usage peak demand and peak prices. Load Technician Barry Roysdon exptains periods can mean lower customer response rewards customers for the benefits of the utility bills and more available energy. saving energy, improves electric grid high-efficiency heating In addition, BGE plans to conduct a reliability and lessens the need for and air conditioning system to customer pilot program in 2008 of its Advanced new power plants.

Joia Nagy. BGE HOME Metering Infrastructure, also known technicians work as smart meters. This initiative Many large commercial and industrial hard to hetp make customers more uses advanced technology to read users have well-established plans comfortable in their meters remotely, virtually eliminating for lowering their carbon footprint.

homes by delivering estimated bills and leading to faster Constellation NewEnergy is a leader superior service and products. restoration of power outages. in the market for renewable energy Residential customers also will be certificates, a popular tool for able to participate in an expanded supporting environmentally friendly Today's energy challenges are global. time-of-use pilot program, offering generation sources. For example, And where others see only challenge, Lower electric rates during off-peak we have an agreement to match we see opportunity. Recently, there's hours and encouraging lower power consumption with renewable been a sea change in the current consumption during peak periods. energy at each New England Patriots' energy environment, driven, in part, home game.

by rising prices. But this change also Our subsidiary, BGE HOME, offers has been fueled by environmental residential customers customized We're also building green energy concerns. Energy is an asset, a energy-management solutions solutions, including a rooftop solar precious one especially in a time of to help increase energy efficiency panel project for General Motors.

rising demand and prices. It must and comfort in their homes. At Washington Suburban Sanitary be managed wisely, and we provide BGE HOME offers a full suite of Commission, the eighth-largest water customers the tools to do so. products and services, including and wastewater utility in the nation, the sale and service of heating and we successfully incorporated green Baltimore Gas and Electric (BGEJ, cooling systems, water heaters, technology into its energy portfolio our regulated utility, offers residential plumbing and electrical systems, through wind power. This initiative customers a variety of energy- window and siding replacement earned Constellation Energy a 2007 management solutions through its and appliance repair. Green Power Leadership award from Smart Energy Savers ProgramsM . the U.S. Department of Energy.

As part of the Smart Energy Savers Other innovations allow commercial, ProgramsM . PeakRewards, BGE's industrial and public-sector A common thread in the latest wave of demand response infrastructure customers to manage energy as a innovation in environmentally friendly program, offers participating strategic asset. These include risk energy solutions is the power of the customers either a smart thermostat management programs to help competitive marketplace. Competition or a toad switch that cycles air business customers maintain budget spurs companies like ours to offer conditioning units during periods certainty through times of volatile new products and services that of peak demand and provides prices. New load response programs meet-and exceed-the needs of customers with bill credits. Less allow customers to capitalize on the our customers.

financial advantages of reducing their electricity load during times of CONSTELLATION ENERGY 9

Creating Enduring Partnerships With Our Communities Part of responsible leadership is facing, head on, the most difficult questions. For example, what does it mean to be a valuable and vital corporate citizen? How can our company be a meaningful contributor in our local communities?

Constellation Energy has a long- multiple community outreach efforts, Global Commodities Group employees standing history and heritage of we are able to help our customers Lindsay Klaus, caring for the communities where better manage their energy bills by analyst-application we Live, work and do business. providing education about energy development, and Antonio Biondo, It's a core value-one that our assistance and energy conservation, analyst-credit, were company and our employees take as well as through the installation among employee very seriously. Creating lasting of weatherization measures in volunteers who participated in a partnerships and helping our their homes. company-sponsored communities are among the most clean-up effort to help restore the valuable things we do. Since 2003, Constellation Energy Chesapeake Bay has provided approximately watershed.

Whether it's supporting the American $2.6 million in support to Red Cross through multiple blood Maryland-based charitable drives each year, building homes organizations, resulting from our Living Classrooms and the National with Habitat for Humanity, mentoring sponsorship of PGA TOUR and Aquarium. In 2007, employees at-risk youth, providing energy Champions Tour golf events in volunteered more than 45,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> assistance to those who need it the greater Baltimore, Md., of their time to service organizations most, or leading Central Maryland- community. Most recently, we and charitable causes throughout our corporate home-in United Way served as the title sponsor of the the country.

giving, Constellation Energy and our 2007 Constellation Energy Senior employees generously give their time Players Championship, which We also make valuable contributions and resources. Responsible citizenship was also the first-ever PGA TOUR toward a variety of environmental is part of our corporate DNA. or Champions Tour event to be initiatives-like providing funding powered by 100 percent renewable to the Chesapeake Bay Trust, Constellation Energy's ongoing energy. Constellation Energy Center for Watershed Protection, partnerships with more than 50 employed various strategies to ensure Clean Air Partners, Trust for network-wide, community-based that all of the tournament's energy Public Land, Maryland Association assistance organizations deliver needs were offset with clean, for Environmental and Outdoor financial help with gas and electric renewable energy. Education and Alliance for the bills for residential customers in Chesapeake Bay. In 2007, employee Maryland, as well as a wide variety Through our Power of Caring volunteers participated in company-of human service assistance program, Constellation Energy sponsored clean-up activities programs. BGE's Community provides employees with the to help restore the Chesapeake Assistance Fund also supports local opportunity to connect to our core Bay watershed.

organizations that focus on energy value of social responsibility by assistance, poverty solutions and means of both employee giving and conservation initiatives for limited- community volunteer initiatives.

income families in Central Maryland. We've established partnerships with Through these programs and many local and national agencies such as Catholic Charities, CollegeBound Foundation, the Independent College Fund of Maryland, Kennedy Krieger Institute, 10 RESPONSIBLE LEADERSHIP

Protecting and Preserving Our Environment Being a responsible leader is recognizing the effect we have on the global neighborhood, while maintaining our commitment to meeting the energy needs of our customers and minimizing the impact of our business on the environment.

Nuclear power We believe nuclear power can and policy because of our low-emitting produces electricity must make a meaningful contribution generation fleet and clean energy with minimal greenhouse gas in the world's efforts to deal with solutions. Our efforts to produce emissions, meaning threats posed by human influence on electricity in cleaner and more cleaner air and reduced impact on climate change. The result will be a sustainable ways also create the environment. dramatic lessening of our country's- significant emission-reduction Shown is our Calvert and the world's-reliance on fossil opportunities for other industry Cliffs Nuclear Power Plant, located on the fuels. In 2007, we announced a joint sectors through electric technology western shores of venture with the world's largest applications that replace fossil-the Chesapeake Bay, nuclear plant operator, EDF Group. fuel uses.

which has been generating electricity This venture, called UniStar Nuclear safety, reliably and Energy, is focusing on the potential Not only are we addressing the cleanly for more than increasing need for more development and deployment of the 30 years.

first fleet of new nuclear power environmentally friendly products, BGE HOME's new plants in the United States in almost solutions and power sources headquarters is three decades. nationally and globally, but we also the company's first have implemented green building office designed to meet the LEED green In addition to our new nuclear practices at our new BGE HOME building standard. activities, we have an equally robust headquarters. The building's interior BGE HOME Manager program to limit emissions across was designed to meet Leadership of Inventory Control and Logistics Jeff our fossil fleet. Nearly $1 billion in Energy and Environmental Design Cavatlo can now bike in capital expenditures have been (LEEDI Green Facility standards to work, taking advantage of some of authorized for construction of for commercial interiors-the first the building's new a state-of-the-art flue gas of its kind among Constellation green design features desulfurization system-also Energy locations. A program of the like tow-flow showerheads and called a scrubber system-at our U.S. Green Building Council, LEED faucets, and bike On the most important environmental Brandon Shores Power Plant and promotes a whole-building approach racks installed to issue of our time, climate change, other environmental upgrades. to minimize the environmental encourage alternative transportation. The our company's policy is unequivocal. The scrubber system will footprint of a building by recognizing new building also We believe it is imperative to slow, substantially reduce sulfur dioxide performance in sustainable site features non-CFC, stop and then reverse the growth of development, water conservation, and mercury emissions and is high-efficiency heating and cooling greenhouse gas emissions. Our expected to be fully operational lighting, recycling, energy efficiency, equipment. generation fleet emits less carbon in early 2010. materials selection and indoor than many others in our industry. environmental quality.

More than 60 percent of the electricity Over time, we expect a federal policy we produce comes from nuclear will be implemented to supersede and hydro power sources, which regional initiatives and align the U.S.

generate electricity with minimal with a global effort to reduce greenhouse gas emissions. greenhouse gas emissions. In fact, we are active in helping to accelerate a federal policy and make it stronger.

We believe Constellation Energy is well poised to benefit from a national CONSTELLATION ENERGY I1I

Giving Exceptional People Opportunity for Growth What drives our company's success? Our people. Constellation Energy employees embrace challenges and have an intense focus on execution. In many fields, particularly new nuclear development and carbon trading markets, we are on the cutting edge in our industry Our teams are helping to shape the future.

Our employees share a commitment as leadership effectiveness, learning Safety is the most important part of our to continuing to deliver exceptional and development opportunities, jobs. 8GE crews, results for our shareholders. For alt and teamwork. As a result of survey like the one shown of us at Constellation Energy, it's our feedback, we have implemented here, begin each job by discussing safety key responsibility. To retain our talented company-wide and business-unit procedures. Shown team, we've established a competitive initiatives that have helped to (left to right] are Total Rewards program that goes increase employee engagement. Dan Moser, overhead mechanic; Vernon beyond salary. Our compensation Mitchell, cable splicer; philosophy is built upon the concept We also are committed to creating Jason Frith, cable of pay for performance. Employees an environment that values diversity splicer trainee; Patrick McBurney, know that at Constellation Energy, and inclusion as strategic assets cable splicer; and hard work and results pay off. for the future of our company. We Dave Wisniewski, have a number of major initiatives senior construction inspector.

We strive to be a top-tier employer under way to ensure that we continue marked the launch of our newest in terms of competitive compensation to attract, retain and develop top flagship leadership development and work-life balance. In November talent that is diverse in background, program, the Transformational of 2007, BusinessWeek named skills and experience. One of Leadership Program, created in Constellation Energy as one of the our initiatives is the creation of our partnership with the University of best 95 places in the nation to launch Diversity Council, a cross-functional Virginia's Darden Business School, a career. More than 90 percent team of leaders from across the well-known for delivering world-of new graduates remain with our enterprise. The council is dedicated class executive education. In 2007, company five years or more. Few to developing and implementing Constellation Energy was named to employers can match that statistic best-practice initiatives that Training magazine's Top 125 list for and we're very proud of it. promote diversity and inclusion in excellence in workplace learning all that we do at Constellation Energy. and development.

Employee engagement is critical to Our ability to value different business success. We believe the perspectives and leverage the talents What's more, we're as committed to best way to find out what our of a diverse workforce is crucial to the safety of our people as we are employees think about working at our continued success. to their career fulfillment. Regardless Constellation Energy is to ask them of where our people work or what and to listen to their feedback. Since At Constellation Energy, growth jobs they do, we foster a culture that 2003, we have been conducting is both a business imperative and a values and promotes safety. In fact, biennial employee engagement personal commitment. We invest safety is the one underlying principle surveys to give our employees an considerably in our most important on which all of our business priorities opportunity to share their insights asset-the skills, talents and are built. It has to be. Just recently, about working for our company. capabilities of our people. Employees our Calvert Cliffs Nuclear Power Plant In the past four years, we've seen can access a variety of learning was recognized as a Maryland Voluntary significant increases in the overall programs on business-relevant Protection Program Star level site engagement levels of our employees, topics, resources and tools. by the state of Maryland and the including through the results of our Thousands of employees participate Occupational Safety and Health most recent survey in 2007. We also in our suite of online courses, Administration for exemplifying continue to score well above the U.S. classroom training and college commendable safety and database norms in many areas such degree programs each year. 2007 health programs.

12 RESPONSIBLE LEADERSHIP

Delivering Performance for Our Shareholders

\\/ b( ive rcI.porrs Ile b leadership tr)rslates into outstandinig pertormance. In 2o0),

(Ont inuLd sItrong perforMn ceMi adni execution Of OUr bIusiness strategy on(ce agaMi translated in to stu1ri-r tIta tl r(:turn of nnore than I Oi percent for our shareho lders.

1-Year Total $151.88 Through our focus on performance Return To Shareholders and risk management, we have

• Constellation Energy been and remain diligent stewards s&P 500 S of the capital we manage. In 2007,

• S&P 500 Utilities Index our Board of Directors authorized

$123.13 a share repurchase program of up to $1 billion, which provides us the

$105 ability to effectively return capital

---

to our shareholders. We executed on $250 million of this program in 12/31/06 01 07 Q2 '07 03 07 0407 2007. At the same time, the program enables us to maintain our financial flexibility to continue to pursue 5-Year Total higher value-added strategic Return To Shareholders $419.51 investments and opportunities.

• Constellation Energy S 500 S&P Throughout our company we are S&P 500Utilities Index

$280.30 focused on consistently and

- appropriately managing risk, while making significant investments

$182.85 for future growth. Some examples 5100¶3 include our pursuit of new nuclear development in North America,

-- environmental improvements in

'02 "03 '04 '05 "06 07 our power plants, continued investments in our transmission and As we see it, our commitment to Our growth has been driven by the distribution network to ensure maintaining a responsible balance continued solid performanc :e of our reliable service and growth through among the priorities of our business units and our abit ity to strategic acquisitions.

stakeholders is a key driver of move forward on several key strategic shareholder value for our company. objectives, while appropriat ely When we evaluate and execute The commitment has paid off for managing risk. We believe t hat our business decisions based on our investors. We have delivered expertise in managing risk is a key considering the needs of all those significantly better returns than our differentiator that sets us a part from to whom we are responsible-our peers and the major market indices. our peers. We've had the vission shareholders, customers, employees, In 2008, we also announced a to see opportunities and ways to communities and the environment-10 percent increase in our dividend, grow our business-and eve n more we position ourselves squarely to raising it to $1.91 per share annually important-our people have had the deliver exceptional performance and from an annual rate of $1.74 per courage to take those grow th steps drive future growth.

share in 2007. and execute on our busines 's plans.

CONSTELLATION ENERGY 13

Dear Fellow Shareholders,

energy sector so unique, and often so challenging, is that we must During the past six years, we have make Long-term investment decisions transformed Constellation Energy in the face of considerable uncertainty.

from a mid-sized, Baltimore-based How do we ensure new generation utility into one of the nation's most is as environmentally friendly as diverse and successful integrated possible? If "green" energy sources energy companies. Today, cost more-and today they do-how Constellation Energy owns a Low-cost, do we help to ease the financial J

environmentally advantaged burden on Lower-income residential baseLoad generation fleet, and is customers? Finally, how do we Chairman, North America's Leading competitive balance environmental and economic Mayo President and CEOIII A.Shattuck power supplier, a top gas marketer concerns, while still meeting our and a Leader in advancing America's growth objectives for shareholders? United States. White a decision to new nuclear renaissance. build a new nuclear facility has yet to As a CEO, I don't have a right to be made, UniStar Nuclear Energy We're very proud of these answer these challenging questions... is moving ahead with the Licensing achievements, which have been I have the responsibility to do so. and permitting processes to site recognized and rewarded by And so does our company. This is a potential new unit at our existing investors, particularly during 2007 the essence of Responsible Calvert Cliffs Nuclear Power Plant when ourtotal return for shareholders Leadership at Constellation Energy. in Southern Maryland. A similar was 52 percent. Investors aren't the application is in the works to develop only ones taking notice. In 2008-for TransLating Responsible Choices another potential nuclear unit at the second consecutive year- into Exceptional Performance our Nine Mile Point Nuclear Station Constellation Energy was named to It begins with our own financial in upstate New York. UniStar Nuclear the prestigious BusinessWeek 50 performance and obligations to Energy is also working with list of the best-performing our shareholders. established and emerging energy companies within the S&P 500. companies to develop potential new In 2007, we generated $21.2 billion nuclear units in Pennsylvania, Our success is gratifying, and yet in revenues and grew adjusted Missouri and at other sites throughout it tells only part of our story. The earnings by 27 percent to $4.60 per the country. We believe nuclear priorities of our shareholders must share, our highest earnings Level energy, with low emissions and its be balanced with those of our to date. Our 2007 earnings growth ability to meet increasing demand, customers and communities that rate exceeded both the S&P electric must play a vital role in securing rely on our vital energy services. utility index and the S&P 500 by at our nation's energy future.

There are many important policy Least 10 percentage points. During issues and industry trends that each of the Last three years, we Our existing nuclear and fossil plants affect our business. Our nation is outpaced our industry peers in total are Located in high-value asset eager to reduce dependency on shareholder return- 52 percent markets and are well managed. In foreign energy sources to improve in 2007, 23 percent in 2006 and 2007, Calvert Cliffs achieved the our energy security, while addressing 35 percent in 2005. We continue to be highest capacity factor rating for a the challenges of global climate disciplined stewards of investor nuclear power plant in the world.

change. Today, we compete globally capital. During the fourth quarter of for energy commodities-natural 2007, we executed on $250 million of Our wholesale and retail competitive gas, oit, coal and others-and we an up to $1 billion stock repurchase power and natural gas supply are facing increasing price volatility program and, for 2008, we increased businesses continue to set the bar due to the influence of growing shareholder dividends by 10 percent for our industry. During the past demands from developing countries to an annual $1.91 per share from year, we made several acquisitions, Like China and India, as well as the $1.74 per share in 2007. enabling us to grow our wholesale increasing competition for capital. Load-serving business in the We've made great strides on several Southeast market, adding upstream Against this backdrop, business initiatives in 2007, gas reserves and expanding the Constellation Energy is poised to particularly related to the potential geographic footprint of our retail make the most significant capital development of new nuclear units. gas operations in the Midwest investments in our history to develop Our joint venture with EDF Group, market. To meet the needs of the power generation sources UniStar Nuclear Energy, is our business customers, we're needed to meet growing consumer establishing itself as a comprehensive, significantly broadening the scope and business demand. To meet robust international partnership of our renewable energy portfolio.

the needs of future generations, we that is welt-positioned as a Leader in We announced several innovative must act today. What makes the the new nuclear renaissance in the renewable energy projects, and 14 RESPONSIBLE LEADERSHIP

are helping our corporate clients, management and performance. We distinguishing us once again as large and small, reduce their impact have made considerable progress the No. 1 contributor in Central on the environment with solutions on the construction of the Brandon Maryland and a leading contributor such as renewable energy products, Shores scrubber that will make it in other markets where we and wind and solar power. one of the cleanest coal-burning conduct business.

facilities of its size in the country-BGE is addressing.the demand side part of a nearly $1 billion investment For the third consecutive year, of the energy equation, as well, in environmental upgrades. We have Constellation Energy has been named with a comprehensive program of one of the lowest-emitting generation to the Dow Jones Sustainability customer-oriented conservation and fleets in our industry. That's an North America Index, based on demand response initiatives. important plus for our environment companies that operate in a socially Combined, these programs should and, from a business standpoint, responsible and sustainable way.

help play a significant role in reducing positions us well to benefit in a In early 2008, we also were named energy usage. Customers who carbon-constrained economy. to the 100 Best Corporate Citizens use Less electricity can experience list by CRO [Corporate Responsibility significant savings on their bills. Recently, we negotiated a Officer] Magazine.

Lower demand also improves grid comprehensive settlement agreement reliability and yields environmental with political and regulatory leaders We believe that the future bodes dividends. The demand response in our home state of Maryland. This well for Constellation Energy. Our program-PeakRewards-is quickly agreement enhances our strategic management team has a superior gaining traction-BGE's goal is to flexibility and delivers meaningful track record of driving significant enroll 50 percent of its residential benefits for both our company and earnings growth and delivering customers, making this potentially BGE customers. Equally important, substantial total shareholder return.

one of the nation's largest and most it allows for all parties to move We have a proven generation fleet significant residential programs. forward with a focus on meeting and high-quality assets in high-BGE also plans to soon launch the Maryland's future energy needs. By value markets, providing us with pilot phase of a leading-edge settling past disputes, we are clear and substantial earnings growth.

advanced metering initiative to help moving to a more stable regulatory With greenhouse gas regulation customers better manage their environment that is a fundamental on the horizon, our low-emitting energy usage. This technology takes building block as we consider fleet is well-positioned to drive the guesswork out of estimating significant capital investments in long-term earnings.

electricity usage, and remote Maryland such as a new nuclear monitoring provides information facility at Calvert Cliffs. Responsible leadership at that can lead to faster restoration Constellation Energy is about during outages. Delivering Continued Excellence accountability. It encompasses our Consistently, the driver of our financial and environmental Investing For Future Growth and success has been our employees' performance and the full scope of Environmental Sustainability dedication to operational excellence- our business activities. It extends Across the energy industry, we're for our customers, investors and all from our shareholders to the entering a phase that will feature of our stakeholders. This includes a communities and stakeholder groups significant capital investment in demonstrated commitment to we serve. I'm proud to say this new generation, distribution and safety-an absolute imperative for commitment is embedded in our core transmission systems and energy our company across all lines of values, and it has played a pivotal conservation programs to keep pace business. Calvert Cliffs was recently role in creating what I believe is with increasing demand. Through recognized as a Maryland Voluntary an extraordinary company with an 2010, we plan to invest $380 million Protection Program (VPPJ Star level extremely bright future. I want in capacity expansion and reliability site by the state of Maryland and the to thank all of you-employees, enhancements in our generation Occupational Safety and Health shareholders, customers and fleet. For 2008, we expect to invest Administration. Less than one percent partners-for your ongoing support more than $440 million in BGE of the eight million worksites in the and contributions to our success.

to meet anticipated customer U.S. achieve the VPP level of safety growth and increased reliability, performance, and we are using this which we believe will lead to future as a model for our other generation earnings growth for BGE. And, plants and operation facilities.

through UniStar Nuclear Energy, we will continue to be at the forefront of I am particularly proud of the Mayo A. Shattuck III new nuclear development. generosity of our company's more April 8, 2008 than 10,000 employees. Their Constellation Energy is committed contributions to the United Way to improving our environmental in 2007 topped a record $5.1 million, CONSTELLATION ENERGY 15

Constellation Energy at a Glance We are North America's largest competitive provider of power to wholesale, commercial, industrial and public-sector customers, one of the top gas marketers and a leading supplier of coal to customers around the world. Our customers include more than two-thirds of the FORTUNE 100 companies, as well as some of the world's largest producers and consumers of power, natural gas, oil and coal. We own a diverse fleet of power plants and are a leader in the potential development of new nuclear plants in the U.S. Through our regulated utility, Baltimore Gas and Electric, we deliver electricity and natural gas to customers in Central Maryland.

Our Vision Our Foundational Values Our Performance Values To be the first-choice provider for customers These values guide our actions: These values measure our results:

seeking energy solutions in the complex and Integrity Speed changing energy marketplace. Teamwork Accountability Social & Environmental Responsibility Passion for Excellence Customer Focus Creation of Value Corporate Social Responsibility Our Accomplishments

• Ranked No. 39 on the 2008 BusinessWeek 50 Best Performers list

• Named to the Dow Jones Sustainability North America Index for the

• Moved up to No. 119 on the FORTUNE 500 list in 2007 third consecutive year

• Advanced to No. 363 on the FORTUNE Global 500 list in 2007

• Received a 2007 Green Leadership award from the U.S. Department of

• Named one of America's Most Admired Companies by FORTUNE Energy for successfully incorporating green power into the overall energy magazine in 2007 portfolio for the Washington Suburban Sanitary Commission

• Ranked as a Platts Top 250 Global Energy Company

• Named by CRO (CorporateResponsibility Officer] Magazine to its

• Recognized as one of the Best Places to Launch a Career by BusinessWeek 100 Best Corporate Citizens list

• Named one of the Top 50 Military-Friendly Employers by

• Ranked the largest corporate philanthropist in the Baltimore, Md., area G.I. Jobs Magazine by the Baltimore Business Journal

• Named to Training magazine's annual Top 125 list for our outstanding Learning & Organizational Development team Operating a Strategic Generation Fleet 61% Nuclear 35% Coal, Gas & Oil 4% Renewable & Alternative Our generating facilities are strategically located and use a variety of fuels. More than 60 percent of our generating output is from nuclear power that generates electricity with minimal greenhouse gas emissions.

16

I@W@Mgb@@@M @Wftm I Conste.l.ation Energy Resources Constellation Energy Serving as an intermediary, managing price Energy producers and intensive energy Global Commodities Group and supply risk between producers and users worldwide Wholesale marketing, risk management, and consumers of electricity, coal; natural gas, portfolio management and trading operation freight and oil. Helping producers manage the risk associated with setting their output and helping'cons~umers manage the price risk associated with buying ,it. Managing the output and fuels for our generation fleet.

Conste!lation NewEnergy Powei. Meeting our customers' energy and risk More than 14,000 commercial, industrial and Retail electricity supply business providing management and sustainability needs through public-sector organizations throughout North energy products and services, innovative products and outstanding service. America, including more than two-thirds of the Serving as an extension of our customers' FORTUNE 100 companies, representing more energy-procurement functions to help them than 16,000 megawatts of peak load effectively manage energy risk, costs and usage.

Constellation NewEnergy Gas Offering customers superior service and More than 14,000 commercial, industrial, Natural gas supply and transportation-related expertise by providing reliable and economical municipal and local gas distribution and power services operation supplies of natural gas. generation facilities in competitive markets throughout North America Conste!lation Energy Power . Owning and operatinq+safey, efficiently Wholesale customers in cinmpetiti 'ee'nergy Generation & DeveLopm.ent Group and reliably-a diversified fleet of fossil and -markets across North Aimerica .'

Power generatiori operation . renewable energy generating facilities.,

Nuclear Constellation Energy Nuclear Group Owning and operating-safely, efficiently and Wholesale customers in competitive energy Nuclear energy generation and development reliably-a fleet of nuclear energy generating markets across North America facilities. Executive oversight of new nuclear development activities.

Energy Delivery Baltimore Gas and Electric Safely and reliably delivering electricity and More than 1.2 miltioneleectric and 640,000 Regulated, utility deliveringi power and naturalgas to our customers Becoming a, - natural gas residential, cormmerciat and natural gas .. , recognized industry leader Improving the' industrial cistom6rsrinrBaltimore and in all,.

or part or prt o; of, 10c~dties-.i'n'Cetral'.Maryland*'*

1,cuit iity of our distribution system *reducing.

ireab interrOptions 6ndl improving our response to outages.  %

. . ...i. . . . . .. . . ................................ . ... . . . . . . ..................... 7 -. ............ -.. .. .............................

Energy Consulting Services Felton-McCord &Associates Offering clients energy consulting and Serving large commercial, industrial, municipal Leading provider of energy consulting and management expertise in the physical, and institutional energy users, as well as management services financial, regulatory and legislative aspects producers, generators, aggregators, third-of energy markets. party marketers, utilities, storage owners and operators Constellation Energy Providing customized energy and environmental Commercial, industrial and public-sector Projects & Services Group solutions-includihg energy consulting, energy facilities throughout North America Full-service energy company - projects and energy assets-that reduce carbon fo0otprint and total en6igy spend, while

. -i ncireasing,reLiabil~ity*::*. * . ii v,*....... ,

BGE HOME Providing customer- centric., energy-focused Residential and small commercial customers Competitive provider of energy-related solutions for heating, air conditioning, plumbing, in Maryland products and services electrical and indoor air quality needs, as well as window replacements and the sale of natural gas to the residential market.

17

Leadership Board of Directors Committees of the Board Executive Team Corporate Governance Mayo A.Shattuck III Executive Committee Mayo A. Shattuck III We are an industry leader in Chairman, President and CEO, Mayo A. Shattuck 111,Chairman Chairman, President and CEO corporate governance. We conduct Constellation Energy Edward A. Crooke our business honestly, with respect Michael J. Wallace Director since 1999 Robert J. Lawless for our professional obligations.

President and CEO, and with regard for legal and Yves C. de Ba!mann Audit Committee Constellation Energy Nuclear Group regulatory requirements. The Co-Chairman, Bregal Investments James T. Brady, Chairman Vice Chairman, independence of our Board of Director since 2003 Yves C. de Batmann Constellation Energy Directors is important to us-12 of Ann C. Berzin Douglas L. Becker Henry B. Barron our 13 directors are independent Edward A.Crooke Chairman and CEO, Chief Nuclear Officer, according to New York Stock John L. Skolds Laureate Education, Inc. Constellation Energy Nuclear Group Exchange Listing standards.

Director since 1998 All committee members are audit Executive Vice President, Michael D. Sullivan, one of our committee financial experts as defined Constellation Energy independent directors, serves Ann C. Berzin by the SEC rules.

as lead director.

Retired Chairman and CEO, Thomas F. Brady Compensation Committee Financial; Guaranty Executive Vice President, Copies of the charters of each of Robert J. Lawless, Chairman Insurance Company Constellation Energy the committees of the Board of Douglas L. Becker Director since 2008 Chairman. BGE Directors, as well as copies of our Dr. Freeman A. Hrabowski III Corporate Governance Guidelines, James T. Brady .Lynn M. Martin Thomas V.Brooks Principles of Business Integrity.

Managing Director, Michael D. Sullivan President,.

Corporate Compliance Program, Mid-Atlantic, BalLantrae All committee members are Constellation Energy Resources Insider Trading Policy, Policy

-International, Ltd. independent directors. Executive Vice President, and Procedures with Respect to Diirector since 1999 Constel*ation Energy Committee on Nuclear Power Related Person Transactions and

'Edward A. Crooke James R. Curtiss, Chairman John:R. Collins ,Information Disclosure Policy

• -Retired Vice Chairman, Edward A. Croboke. Excdutive Vice Presidernt and are avaiLabLeon our Web site at

• Constellation Energy Nancy Lampton Chief Financial Officer www.consteltation.com.

Director since 1988 Lynn M. Martin IrvingB'. Yoskowitz James R. Curtiss, Esq. John L. Skolds Interests Aligned with Executive Vice President and Retired Partner. Winston & Strawn All committee members are Shareholders General Counsel independent directors. We maintain guidelines requiring Director'since 1994 Paul J. Allen Nominating and our executives and directors Dr. Freeman A. Hrabowski III Senior Vice President, Corporate Governance Committee to acquire and maintain holdings President, University of Maryland Corporate Affairs and Michael D.Sullivan, Chairman of Constellation Energy stock to Baltimore County Chief Environmental Officer Douglas L. Becker further align the interests of our Director since 1994 Felix J.-Dawson executives and directors with Dr. Freeman A. Hrabowski III Nancy Lampton Robert J. Lawless Co-Chief Commercial Officer, the interests of our shareholders.

Chairman and CEO, Lynn M. Martin Constellation Energy Resources American Life and Accident Chairman, All committee members are Insurance Company of Kentucky independent directors. Constellation Energy Partners Director since 1994 Senior Vice President, Constellation Energy Robert J. Lawless Chairman, Kenneth W. DeFontes, Jr.

McCormick & Company, Inc. President and CEO, BGE Director since 2002 Senior Vice President, Constellation Energy Lynn M. Martin President, Beth S. Perlman The Martin Hall Group LLC Senior Vice President, Director since 2003 Chief Administrative Officer and Chief Information Officer John L. Skolds Retired Executive Vice President, -George E. Persky Exelon Corporation Co-Chief Commercial Officer, Director since 2007 Constellation Energy Resources Senior'Vice President,

• Michael D. Sullivan Constellation Energy Co-Founder and Chairman,

• '* :' Life Source, Inc. * ,

,,Director since 1992 18

Understanding Our Form 10-K One of our priorities at Constellation Energy is to provide you with clear, easy-to-read and easy-to-understand information about our company. We want you to know what we do, how we do it and how we're doing.

This special section is intended to be a guide, describing and summarizing some of the inforrmiation contained in our Form 10-K and providing page numbers where more details can be found. Our complete Form 10-K follows this special section.

Breaking Down Our Form 10-K Our Form 10-K has four parts:

Part 1:In-depth descriptions of our businesses.

Part II: Our financial performance, the information in which investors are usually most interested.

Part III: Directs readers to other filings made with the Securities and Exchange Commission for details about our Board of Directors, executive compensation, auditor fees, stock ownership information and other matters.

Part IV: A Listing of financial statement schedules and exhibits.

Over the next several pages, we provide descriptions and summaries of some of the major topics included in Parts I and II.

Part I: Our Businesses Part I of our Form 10-K provides details about our businesses:

Our merchant energy business Our regulated utility-Baltimore Gas and Electric Company Our other nonregulated businesses Also included is information about our environmental matters, employees, properties and executive officers Here's Where You Look in Part I Highlights of What You'll Find mw@31M_ ý It" 2 1.,Business Overview We have a merchant energy business and a regulated utility.

2 Operating Segments Our reportable operating segments are-merchant energy, regulated etectric and regulated gas. We also have certain other, nonregutatied business activities:.

3-10 Merchant Energy Our business Business We provide energy products and services to wholesale and retail customers, including distribution utilities, cooperatives, aggregators, and commercial. industrial and governmental customers. We manage contractually contro!led physical assets, including

,generation facilities, natural gas properties 'and international coaland freight assets:

We generate electricity and we provide risk management services andtrade energy and energy-related commodities. .

Fuet sources . . -

Our electricity generated by fuel type in 2007: nuclear-61 percernt.,coal *,gas and oil.,-.

35 percent; renewable and alternative'-four percent.

Our competition We encounter competition from companies of various sizes with varying'levets of experience, and financial and human resources and differing strategies.

Merchant energy business operating statistics for the last five years The steady increases in revenues reflect the strong growth of our merchant energy business.

10-15 Baltimore Gas and Our business - - .

Electric Company We're an electric transmission and distribution utility and a natural gas distribution utility with a service territory that includes the City of Baltimore and parts of Central Maryland.

Electric and gas operating statistics for the last fiveyears Revenues by type, distribution volumes to our customers.and thenumber. of customers.

15 Other Nonregulated We offer energy solutions to residential, commercial, industrial and Businesses government customers.

Note: This special section is intended to be a guide. Youcan find more details about all these items in our Form 10-K. which folleos this special section.

19

Understanding Our Form 10-K Here's Where You Look in Part I Highlights of What You'll Find

15. Consolidated Capital Our total capital requirements for 2007 were approximately $1.7 billion, and we expect Requirements them to be approximately $2.5 billion in 2008.

15-17 Environmental We are subject to regulations concerning air quality, water quality and the disposal Matters of hazardous substances. Over the next three years, our total estimated capital

' *requirements for environmental matters are approximately $1.0 billion.

17 Employees We had approximately 10,200 employees at year-end 2007.

18-23 1A. Risk Factors There are a number of risks related to our businesses and the industries in which we operate that could adversely affect our financial results.

23-25 2. Properties Our offices Our corporate offices are in Baltimore, Maryland. We have marketing offices throughout North America and we also Lease space internationally.

Our energy-producing properties We own approximately 8,700 megawatts of electric generating capacity at plants diversified by fuel type and located strategically throughout the United States.

25-26 . Executive Officers Our executive officers have a diverse mix of energy, financial and other experience in of the Registrant competitive and regulated markets.

Part I1:Our Financial Performance Part IIcontains management's discussion and analysis of our results of operations and financial condition and our audited financial statements.

It compares our results from 2007 with those from 2006 and our results from 2006 with those from 2005.

The sections in Part II include:

Introductory Items-The Basics Management's Discussion and Analysis-The Context Financial Statements-The Numbers Notes to the Financial Statementsý-The Details Introductory Items The Basics: Includes information about our common stock prices and dividends and historical financial data.

Here's Where You Look in Part II Highlights of What You'll Find

@& IamM 27-28 5. Market for Our dividend information Registrant's Common We declared dividends of $1.74 per share in 2007 and increased our annual dividend rate Equity, Related to $1.91 per share in January 2008.

Shareholder Matters Our stock price and Issuer Purchases The price of our common stock-based on New York Stock Exchange Composite of Equity Securities Transactions-ranged from $68.78 to $106.29 in 2007.

Our common share repurchase program Our Board of Directors approved a common share repurchase program for up to $1 billion of our outstanding common shares, which is expected to be executed over a 24-month period in a manner that preserves flexibility to pursue additional strategic investment opportunities. We have repurchased approximately 2.5 million outstanding common shares for $250 million pursuant to this program.

29-30 '6. Selected Summary of our operations and financial condition and our financial statistics for the Financial.Data last five years.

Note: This speciat section is intended to be a guide. You can find more detaits about alt these items in our Form 10-K. which foltows this special section.

20

4',

.. ...i .. .. .. . . .

DManagementsDiscussionand Analysts  %

The Context: Our rannagement discusses in detail the financial resufts andco'ndition of o ur1oam pany and the (ay We manage'our bdsiness Here's Whe& You 60bk in Part.II . , Hghlights i'. of WhatYou,'l Find "

31 7. Man'aoement's . Introduction and We summarize how we.have organized ourd iscussion and anaysi s.X: "

Discussion andc Overview

• .Analysis of Financial Condition and Results of Opnrations -

>31-432~ 44V4444,4a 44,44~~l. 4 ' :competitie

We arepursuing a toastrategy supply activities and our* reulte provour energuatnd energydrelatedyser,vcesthrough our aryland utility.,;*., <7;;*G;.;*%**

32-35 Business Environment Energy markets have been volatile over the last several years, with significant changes in naturaL gas, coal and power prices. We continue to be subject to extensive federal and state regulation.

35-39 " .- "*i*' ".C. *o*.*..  ! Cr icatiaccounting*q These are the accounting policies that requiredifficult, subjectie or comptex judgment

,..,.4andwhch4re os impor~tant to the portrayal of our financial condition and r~esults.

,The . . .. .aortr con trats , n (CEP)

- , . 44

.P 40~~~~~~ Sinfiatovnsr07 tinfoiocaUntevents intctude

. ...operationsP . , g . .. , . . . ..

Ohe partoa T4 dsaneonsoliation reyýofostelltation mrepurchgas-firedpcombied-cycle Eonergy ParterLL power generatig EP' facitityiAlabama 4

., , - Contributions toourshppngjontventure ,

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. ...* *%* .H., .'

: ::,.', " .;'/:;i", -. OF M i6nm}8'f16ur n'ucear'develop~ment joint'venturewi th Etectricite de Franc [F F]-;*.:

41".56 4 4 thedetailedsditcussio n ofourlean:ings w

overaliinetincomegforzuu07was oil$821.5 pdife mit[ n, a.decrease of $i1g14.as-rand driv...]en mostly tbhyowexearndgeour detoithe acsence ofpthe gi ohe sale of eds-.ire aeneratyngfacLtmpees d gn2006,sliower earningse romoursyntheec g fue rocessaing facili ties Coiuebtoahigheropnasetout ofitax crentsuand fewer ear t ur regulatedbusinesese.4

..... .. Our merchFanm ....

energy ncomeafromdcontinutnen 4~.4,4. u$rawit El ct7. r ite rnc 2E7FIn

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~

41-~~6 ~ Results of Operati ~ons The2 deti~led$of incTeaissae dicuson 1t 2 silion f006. ~

from2000GE in~U4 4

.~

... .Our reg ulated e~ectric net income fro 2007 wa $97. dcese eitc a rn, of S22.3 r; i((1on*,

The'pa06.,Our regutated naturaheticsfelttancredit 14~4 * ~444. 44444444 <4k 4 ,.Cas

" Oiimrchantenergy inomfrmcniugoperations was $69 ilini 20 ii 4

4.

.. 4. ,ge57-59 Condi Cash f .. iranciat

. . .. yh f r

.44, Cash -. .. i was $*27.8 million. in 2. . "

All of our security ratings are investment-grade  :

'44, 44444444.4474RE.4444 rces.*,4 .*4We're estimating that we'll spend $2.5 billion in capital for 2008 and $2.0 biion in 21200too U

459-62 fund existing and anticipated projects. ' 4 4

'A'.

Noie: Thi sspecial section is intendec to be a guide You ca fiindrnore detai[s about all ihese items in our FM -K, which ihis special "oiloels se tion.

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Understanding Our Form o-K Wa,-~'~u Whmr~o Vni; nok in Part ii I4inhliahtnfWfiatYntiilFind Here's Wher. .. You

.. L. .. J. . Ib0. L,-

62-67 Market Risk We are exposed to"various risks. Our risk managemerit program relies upon an effe ctive,

,system of internal contros,-and the audit committee of our+Board of Directors periodically reviews compliance with our risk parameters, limits and trading guidelines:.

5,.

ýOur Financial Statements The Numbers: We provide separate financial statements for Constellation Energy and-BGE, This~section also includes our management's reports on our financialinformation and the effectiveness of our internaleontrols'as well as our auditor'sreports on our financial information and its reportS on the effectiveness of Constellatio6'nEnerg"s S y.

interri'l era controlsa controls.

Here's WhereYou Look in Prtlk -Highlights of WhatYo6u'llFind

,.-~

68 ' 8. Financial - I Reports of Our management accepts responsibility for the information and represenitations in our IStatements],'ndata Management financialstatements and concludes that our internal~controL over fiancial reporting was Supplementary Data Seffective as of December.31. 2007., -

69-70 >s4Reports of §PricewaterhouseCoopers LLP st tes its opinion that both ConstellatinEeg'ad Independet, BGE'sconsolidaed financial statements ar Iepresen'ted fairly, ina~llmaterial respects, anid Registered PujbLic

• that Consteltation Energy maintained, Winall material respects, effective internal control:,.

~>Accdointina Firmi ~ over finanialreportingatDecember 31, 2007. , > i4s.

71 , Consolidated -~Our net income for 2007 was $821.5 million..,

Statements of Inco,me .

72-73 7 *< Consolidated OutrtotaL assetsweLFe $211.9billionat December 31, 2 0 07.

Ba.ance Sheets . . n.

74 Consolidated Our cash and cash equivalents at December31 2007 were $1.1 billion a decrease of Statements of . $12 billion from a year earlier.

Flowsdcste. VeCash ., ",

Csolida C,7 ,n 1(sition of and changes in our common shareholders equity In 2007 Sw w d $368* million in dividetndst

$6..StatmentsOf $ ..... * " "

SShareholders' 'E(,uýit 76-7 Cosoldatd AtDecmbe 31 200, or ttalcapitalization was $ 10.2 billion-$4.7 billion in long-term Statements of .',debt, $19. 2million in minority interests, $190.0 million in preference stock, arid $5.3 billion, Capitalization in common shareholders' equity.

78-81 BGE Financad We include financial statements for BGE because it isa separate registrant required to .

.~~~~ ~Statement, 5 sfile, reports with the SEC. ~ ~ 5 5 ~ 5 .

Nnteo'u tn Our I:

The Details: WeexpLain the processes, events, actions. projects, issues and specifics that produce the amounts reflectedinour financilastatements.

Here'sWhere You Look in Part 1, Highlights of What You'lt Find -.

Ff. MM919 .E 82-93' ,Note 1: Significant 'Accounting methods that we use and how they/re appiiedthr6oughout our businesses, Accounting Policies along with the new accounting standards issued and adopted.

Note: This spieciat section issintendedtoheaguide You coonfind more detail abou alt thse ries inourFom 10 Kwhch folows this speciat section

,22 , ' , <* > . > o o , < * , ¢ < :

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55.5 ii

_,H;-li1*lihhts nf W~hat You'Rl'F:inr!

we,-ris wtere'o'Vtinn in Part It iIin~sn ~,CAicn 94-97~4 Not 2 OherEvni Other events added $38.4 milli6nto our pre-tax earnings refL'ecting $63.3 milLion ingai ns'

.4444444 44 4 on sales of equity of CEP, offset by $20.2 million in impairment Losses and other

." '44 costs, $2.4 million in Losses from discontinued operations and $2.3 million in Workfor*:eY 44k; 97-98 Note 3: Information by -Our revenues, net income and other financial information broken out by operating Operating Segment segment show the growth of our merchant energy business.99-102 .- ' Note6 4: Invoýstments Ou , investments are mainly financial investments related to ourtnuclear 4 4 4,,-4 Adecombmissioning trust funds., a u of g $

102-103 ,Note 5: Intangible At December 31, 2007, our carrying amrrounti of goodwill was $261,.3 million, and our total Assets , , net intangible assets subject to amortization were $353.1 million.

V IO3"J105 10 444.4444 -,." ~44 - Note6:.Regulator~y-At December31, 200:7, our total regulatory assets (net)were$65151 m illion, which -

44

>4-44444,4544-4.

- 4<444 vssetsInet A , included$593.4 million deferred for future collection under the rate stabilzation plan

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provided for in Maryland Legislation. *>4 .. 4- ,, .

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105-109 Note 7: ,Pension, We provide details-obligations, assets, assumption details and company contributions-Postretirement Other about our employeebenefi6t plans.

Postemptoymnent,.

and Employee Savings ,

Plan Benefits .

4;;.

109 44 INote 8: Creditl ;.4, Our short-term borrowings (debt that matures within one year from the date its issued)] *4

~~44,4 -~.acititiesand Short- may includ~ebank;L'oans, commercial paper and bank lines of credit.,,: ~'~

~TemBarrowlngs '4 44""

44,54444~4-44 4 ,~444.

110-112 - Note 9: Long-Term We provide details about our long-term debt (debt that matures a year or more from the, Debt, Common Stock date its issued), our common stock repurchase program and about our preference stock.

anl P'reference Stockv.

Nat, 1Nte*,xesO -W4Our income tax expense for 2007 was $428.3,million, which reflected a net $55.9-million '

mfavorable ipact from 'synthetic fuel tax credits after estimated hase-out.,

1ý16 Note v 11: Leases We provide details about the capital and operating Leases in which we enter.-4, 117-121 W4 4 12:444 Not 444.44,444 We provide details aboutour commitments, financial guarantees, contingencies ,

44 '~' Commitments,.'444 environmental matterslegalproceedings involving us and our insurance coverage. 44 -

44444

~ ~-44;~44444444 5,~4 ContingeinciOes'~ 4 122-12 Note 13: Hedging We explain how we manage commodity price fluctuations and interest rate exposure, Activities and and we disclose the fair value of our financial instruments.

4 We pr.ov'. so. .s e in the f *stock options,4re.stricted 4stock,

-Fair Value of Finai ncial 4444~$. '. - Instruments' 4 44-' ,'We provide stock based compensation in thie form ofstock, options *restricted stock;* 444**','4 4-124-1254:. 44~4Q 4.44444-444- Note 14:Stock-Based 4

-4444 4.> ' "44omppensation 4 performance and service-based units and equity to employees'. - 44,.  :÷i, 126 .- , ,We Note 15: Merger and acquired working interests in gas- and oi[rproducing properties, Cornerstone Energy,

. ,Acquisitions Inc., and a partially completed gas-fired, combined-cycle power generating facility in Alabama (February 2008). " . - - .

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!:i'127 .W  ;:*47,4 ?-Note'16:

N Related Party OOurrmerchant energy business provdes:BGE withaportionof the energy i needs we

,4... 4- <....,- .. ran sactions, 3GE provideBGE with the services of certaincorporatefunctions, and BGE participates in-" '

44jj~j~ ' 4 4 .~ 4 '"'4'4 4 444our benefit plans.;~;

42444 44.~,, '4.~' 44~~~244; 4 128-129 Note 17: Quarterly' We break outaour financial 'results-and those of BGE-by quarter for the last two years.

.,4 " . ..... "' *'

Financial Data - ,  ; . . .. . .> 4,4

- (Unaudited)4 4, Note: This specia section is intended to be a guide.,You can findmore detaits about att these items in our Form 10-K; which follows this speiia sectioh.

23K

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4 . --

.Glossary Aggregator Generating Capacity Regional Transmission Organization WRTO) a company, intermediary or agent that combines the amount of electricity that can be produced a group of companies with responsibility for the the energy needs of multiple customers and by a specific generating facility planning and use of power transmission lines then buys or provides the energy and services in a geographic region Generation needed the process of transforming other forms of Regulated Business British Thermal Unit (BTU) energy-coat, natural gas, uranium, oil, wind, the portion of our business whose primary a basic unit used to measure natural gas; water or sun-into electricity operations and prices are set and controlled by the amount of natural gas needed to raise the the rules and activities of a state utility Hedging temperature of one pound of water by one commission entering into transactions to manage various degree Fahrenheit types of risk such as commodity price risk Securities and Exchange Commission (SEC)

Competitive Supply Business the U.S. agency charged with protecting Independent System Operator the portion of our business that provides energy investors, maintaining fair, orderly and efficient an independent, regulated entity established and related value-added services to wholesale markets and facilitating capital formation to manage a regional transmission system in and retail customers in competitive markets a non-discriminatory manner and to help Standard Offer Service Dekatherm (DTH) ensure the safety and reliability of the bulk in Maryland, the obligation of a utility-such as a standard measurement of natural gas; power system Baltimore Gas and Electric-to supply electricity 10 therms or one million BTUs to residential customers and to serve as the Load-Serving provider of last resort [POLR) for those customers Deregulation the process of providing customers with the who have not chosen an alternate supplier in the industry, the process by which regulated energy they need

.markets become competitive markets, Tolling Contract Mark-to-Market giving customers the.opportunity to choose their an agreement where a buyer pays a plant the valuation of a security, commodity or financial energy supplier owner a fixed amount per month to have the instrument to reflect current market values right to convert fuel provided by the buyer Distribution Maryland Public Service Commission into electric energy the delivery of energy to locations where the agency responsible for regulating public customers use it-including homes, businesses, Transmission I utilities doing business in Maryland and industrial facilities the sending of electricity at high voltage, usually Megawatt 1MW) on lines running along high towers, from Estimated Proved Reserves one million watts of electricity, enough generating plants to substations; where~it is then estimated quantities of crude oil, natural electricity to light 10,000 100-watt light bulbs reduced to a lower voltage that-is delivered gas, and natural gasLiquids that geological and for one hour td homes, businesses and industrial fiacilities

'en'gineering data show with reasonable Nuclear Regulatory Commission (NRC)

'certainty to-be'recoverable in future years from Unit.Contingent Power Purchase Agreement known reservoirs under existing economic the US. agency that regulates commercial a contract with a.power pta.nt o-,peratorwhere

>'and operating conditions nuclear power plants and the civilian use of the buyer receives the specified output from the, nuclear materials plant unless the plant isýnot operating .

+Federal Energy RegulatoryCommission (FERC)

, the U.S. agency that regulates interstate Origination Value at Risk[VaRl ' ' " "

energy activities the initiation of wholesale energy purchases 'a statistical measure that helps eva'luate risk by and sales that may include value-added services showing how much the value ofour derivative ,

Full Requirements Service along with the energy assets and liabilities subject to mark-to-market a product offering that'handles all of a customer's accounting may change undervarious,--

energy needs through a combined service that Peak Load circumstances .  :

may include generating or buying energy, a measure of the maximum amount of electricity managing Load and power purchase agreements, delivered at a point in time scheduling delivery, managing risk, settling Portfolio Management and Trading accounts, and other related activities using energy and energy-related commodities to manage our portfolio of purchases and sales to customers through structured transactions, and trading energy and energy-.

related commodities to deploy risk capital to earn additional returns 24

Shareholder Information Dividends Stock Transfer Agent and Registrar Form 10-K The Board of Directors sets the record and American Stock Transfer & Trust Company Our 2007 Form 10-K is included as part of this payment dates for qluarterly dividends. In ShareholderServices annual report. Our 2007 Form 10-K and our January 2008, we raised our quarterly dividend 59 Maidenl'ane " other SEC filings are available on our Web siteat to 47.75 cents per share-a 10 percent New York, NY 10038 www.constellation.com. We also will provide increase over the previous quarterly dividend (8001 258-0499 additional copies upon request. Send requests to and equivalent to an annual dividend of www.amstock.com Constellation Energy Shareholder Services,

$1.91 per share. We paid the new dividend on 750 East Pratt Street, Baltimore, MD 21202.

Shareholder Assistance April 1, 2008, to shareholders of record on For general inquiries, or for assistance with lost Stock Trading March 10, 2008. Projected record dates for or stolen stock certificates or dividend checks, Constellation Energy common stock trades the next three quarters are June 10, 2008; name or address changes, stock transfers, or the under the ticker symbol CEG on the New York Sept. 10. 2008; and Dec. 10, 2008. Projected Shareholder Investment Plan, please contact and Chicago stock exchanges.

payment dates are July 1,2008; Oct. 1, 2008; our Stock Transfer Agent and Registrar.

and Jan. 2, 2009. Forward-Looking Statements Shareholder Investment Plan We make statements in this annual report that Detailed information about our dividend policy, Our Shareholder Investment Plan provides arec onsidered forward-looking within the :

as well as our dividend-payments and stock shareholders with an easy, economical way meaning of the Securities and Exchahge Act'of price ranges for the last two years. is available to acquire additional shares. In addition, accounts 1934. These statements are not guarantees on page 27 ofour 2007 Form 10-K included can be used to sell, deposit and transfer shares. of our future results and are subject to risks, withinthis annual report. To participate, or for more information, please uncertainties and other important factors-Certifications contact our Stock Transfer Agent and Registrar. including those in the Forward-Looking As required by the Sarbanes-Oxley Act of 2002, Statements and Risk Factors sections of our E-mail Alerts we have filed the Chief Executive Officer and 2007 Form 10-K included within this annual To automatically receive e-mail alerts about our Chief Financial Officer certifications in our 2007 report-that could cause our actual results, financial information- including notification to differ.

Form 10-K. Additionally, our Chief Executive of SEC filings, financial reports, presentations Officer provided an annual certification in June and press releases-go to E-mail Alerts on the 2007 with respect to our compliance with the Investor Relations section of our Web site at New York Stock Exchange corporate governance www.consteLLation.cbm and register your listing standards. preferences. You also can make changes in Independent Registered P,ublic Accounting Firm your notification options or unsubscribe from PricewaterhouseCoopers LLP the service.

The cover and narrative section of this annual report are printed on recycled paper that contains 30 percent post-consumer fiber; the Form 10-K portion of this report contains 10 percent post-consumer fiber. These post-consumer recycled papers are made from fiber sourced from well-managed forests and other controlled wood sources and are independently certified by SmartWood, a program of the Rainforest Alliance, to the Forest Stewardship Council (FSC] standards:,Sandy Alexander, Inc., an ISO 14001:2004 certified printer with FSC Chain of Custody; printed this report with the use.of Green-e' certified renewable wind power, r'esulting in nearlyzkero volatile-organic compound emissions. - -

Savings from the use of postrconsumer recycled fiber in place of virgin fiber: Savings from the use of wind-generated electricity:

170.67 trees preserved for the future 27,354 lbs air emissions not generated cna 492.82 lbs waterborne waste not created 11 barrels crude oil unused

_- 72,496 gallons wastewater flow saved This amount of wind-generated electricity is equivalent to:

0 8.021 lbs solid waste not generated A taking two cars off the road for one year OR 4* 15,794 lbs net greenhouse gases prevented *dý planting 1,849 trees 120,890,400 BTUs energy not consumed

, C Mixed Sources FSC . , , . a,,y e d

K RID ERO UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended DECEMBER 31, 2007 Commission IRS Employer file number Exact name of registrant as specified in its charter Identification No.

1- 12869 CONSTELLATION ENERGY GROUP, INC. 52-1964611 1-19 10 BALTIMORE GAS AND ELECTRIC COMPANY 52-0280210 MARYLAND (States of incorporation) 750 E. PRATT STREET BALTIMORE, MARYLAND 21202 (Address of principal executive offices) (Zip Code) 410-783-2800 (Registrants' telephone number, including area code)

SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT-Name of each exchange on Tide of each class which registered Constellation Energy Group, Inc. Common Stock-Without Par Value New York Stock Exchange, Inc.

J Chicago Stock Exchange, Inc.

6.20% Trust Preferred Securities ($25 liquidation amount per preferred security) issued by BCE Capital Trust II, '~New York Stock Exchange, Inc.

fully and unconditionally guaranteed, based on several obligations, by Baltimore Gas and Electric Compn I SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:

Nor Applicable Indicate by check mark if Constellation Energy Group, Inc. is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes FX No F.

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

Indicate by check mark if Constellation Energy Group, Inc. is nor required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes El No FX.

Indicate by check mark if Baltimore Gas and Electric Company is nor required to File reports pursuant to Section 13 or Section 15(d) of the Act. Yes 0l No FXj.

Indicate by check mark whether the registrants (I) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months, and (2) have been subject to such filing requirements for the past 90 days. Yes Z No 0l.

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will nor be contained, to the best of registrants' knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. FX Indicate by check mark whether Constellation Einergy Group, Inc. is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):

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

Large accelerated filer El Accelerated filer El Non-accelerated filer Z Smaller reporting company El Indicate by check mark whether Constellation Energy Group, Inc. is a shell company (as defined in Rule 12b-2 of the Exchange Act) Yes E3 No Fx Indicate by check mark whether Baltimore Gas and Electric Company is a shell company (as defined in Rule 12b-2 of the Exchange Act) Yes El No FX Aggregate market value of Constellation Energy Group, Inc. Common Stock, without par value, held by non-affiliates as of June 30, 2007 was approximately $15,630,501,504 based upon New York Stock Exchange composite transaction closing price.

CONSTELLATION ENERGY GROUP, INC. COMMON STOCK, WITHOUT PAR VALUE 177,923,807 SHARES OUTSTANDING ON JANUARY 31, 2008.

DOCUMENTS INCORPORATED BY REFERENCE Part of Form 10-K Doctsment Incorporated by Reference III Certain sections of the Proxy Statement for the 2008 Annual Meeting of Shareholders for Constellation Energy Group, Inc.

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

TABLE OF CONTENTS Page Forward Looking Statem ents ................................................. 1 PART I Item 1 - B usiness ................................................................... 2 Overview ............................................................. 2 Merchant Energy Business ............................................... 3 Baltimore Gas and Electric Company ...................................... 10 Other Nonregulated Businesses ........................................... 15 Consolidated Capital Requirements ....................................... 15 Environm ental M atters .................................................. 15 E m ployees ............................................................. 17 Item 1A - Risk Factors ............................................................... 18 Item 2 - Properties .................................................................. 23 Item 3 - Legal Proceedings ........................................................... 25 Item 4 Submission of Matters to Vote of Security Holders ............................... 25 Executive Officers of the Registrant (Instruction 3 to Item 401(b) of Regulation S-K) . 25 PART II Item 5 - Market for Registrant's Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities ................................................. 27 Item 6 - Selected Financial Data ...................................................... 29 Item 7 - Management's Discussion and Analysis of Financial Condition and Results of O perations ................................................................. 3.1 Item 7A - Quantitative and Qualitative Disclosures About Market Risk ...................... 67 Item 8 - Financial Statements and Supplementary Data ................................... 68 Item 9 - Changes in and Disagreements with Accountants on Accounting and Financial D isclosu re ................................................................. 129 Item 9A and 9A(T) - Controls and Procedures ..................................................... 129 Item 9B - O ther Inform ation .......................................................... 129 PART III Item 10 - Directors, Executive Officers and Corporate Governance .......................... 130 Item 11 - Executive Com pensation ..................................................... 130 Item 12 - Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters ..................................... 130 Item 13 - Certain' Relationships and Related Transactions, and Director Independence ......... 131 Item 14 - Principal Accountant Fees and Services ......................................... 131 PART IV Item 15 - Exhibits and Financial Statement Schedules. . .. ...... ... .... .... ..... ..... .. . 13 2 Signatu res ...................................................................................... 13 8

Forward Looking Statements " the effectiveness of Constellation Energys and We make statements in this report that are considered BCE's risk management policies and procedures forward looking statements within the meaning of the and the ability and willingness of our Securities Exchange Act of 1934. Sometimes these counterparties to satisfy their financial and statements will contain words such as "believes," performance commitments, "anticipates," "expects," "intends," "plans," and 'other

• operational factors affecting commercial similar words. We also disclose non-historical information operations of our generating facilities (including that represents management's expectations, which are nuclear facilities) and BGE's transmission and based on numerous assumptions. These statements and distribution facilities, including catastrophic projections are not guarantees of our future performance weather-related damages, unscheduled outages and are subject to risks, uncertainties, and other or repairs, unanticipated changes in fuel costs important factors that could cause our actual or availability, unavailability of coal or gas performance or achievements to be materially different transportation or electric transmission services, from those we project. These risks, uncertainties, and workforce issues, terrorism, liabilities associated factors include, but are not limited to: with catastrophic events, and other events

" the timing and extent of changes in commodity beyond our control, prices and volatilities for energy and energy " the actual outcome of uncertainties associated related products including coal, natural gas, oil, with assumptions and estimates using judgment electricity, nuclear fuel, freight, and emission when applying critical accounting policies and allowances, preparing financial statements, including factors

" the liquidity and competitiveness of wholesale that are estimated in determining the fair value markets for energy commodities, of energy contracts, such as the ability to

• the effect of weather and general economic and obtain market prices and, in the absence of business conditions on energy supply, demand, verifiable market prices, the appropriateness of and prices, models and model inputs (including, but not

" the ability to attract and retain customers in limited to, estimated contractual load our competitive supply activities and to obligations, unit availability, forward adequately forecast their energy usage, commodity prices, interest rates, correlation and

• the timing and extent of deregulation of, and volatility factors),

competition in, the energy markets, and the " changes in accounting principles or practices, rules and regulations adopted in those markets, " losses on the sale or write down of assets due

" uncertainties associated with estimating natural to impairment events or changes in gas reserves, developing properties, and management intent with regard to either extracting natural gas, holding or selling certain assets,

" regulatory or legislative developments federally, " the ability to successfully identify and complete in Maryland, or in other states that affect acquisitions and sales of businesses and assets, deregulation, the price of energy, transmission and or distribution rates and revenues, demand for " cost and other effects of legal and energy, or increases in costs, including costs administrative proceedings that may not be related to nuclear power plants, safety, or covered by insurance, including environmental environmental compliance, liabilities.

• the ability of our regulated and nonregulated Given these uncertainties, you should not place businesses to comply with complex and/or undue reliance on these forward looking statements.

changing market rules and regulations, Please see the other sections of this report and our

" the ability of Baltimore Gas and Electric other periodic reports filed with the Securities and Company (BCE) to recover all its costs Exchange Commission (SEC) for more information on associated with providing customers service, these factors. These for-ward looking statements

" the conditions of the capital markets, interest represent our estimates and assumptions only as of the rates, foreign exchange rates, availability of date of this report.

credit facilities to support business Changes may occur after that date, and neither requirements, liquidity, and general economic Constellation Energy nor BGE assume responsibility to conditions, as well as Constellation Energy update these forward looking statements.

Group's (Constellation Energy) and BGE's ability to maintain their current credit ratings, 1

PART I In addition, the website for Constellation Energy Item 1. Business includes copies of our Corporate Governance Guidelines, Principles of Business Integrity, Corporate Overview Compliance Program, Insider Trading Policy, Policy and Constellation Energy is an energy company that Procedures with respect to Related Person Transactions, includes a merchant energy business and BGE, a and Information Disclosure Policy, and the charters of regulated electric and gas public utility in central the Audit, Compensation and Nominating and Maryland. Corporate Governance Committees of the Board of Constellation Energy was incorporated in Directors. Copies of each of these documents may be Maryland on September 25, 1995. On April 30, 1999, printed from our website or may be obtained from Constellation Energy became the holding company for Constellation Energy upon written request to the BGE and its subsidiaries. References in this report to Corporate Secretary.

"we" and "our" are to Constellation Energy and its The Principles of Business Integrity is a code of subsidiaries, collectively. References in this report to the ethics that applies to all of our directors, officers, and "regulated business(es)" are to BGE. employees, including the chief executive officer, chief Our merchant energy business is a competitive financial officer, and chief accounting officer. We will provider of energy solutions for a variety of customers. post any amendments to, or waivers from, the It has electric generation assets located in various Principles of Business Integrity applicable to our chief regions of the United States and provides energy executive officer, chief financial officer, or chief solutions to meet customers' needs. Our merchant accounting officer on our website.

energy business focuses on serving the energy and capacity requirements (load-serving) of, and providing Operating Segments other energy products and risk management services for, The percentages of revenues, net income, and assets various customers. attributable to our operating segments are shown in the BGE is a regulated electric transmission and tables below. We present information about our distribution utility company and a regulated gas operating segments, including certain other items, in distribution utility company with a service territory that Note 3 to Consolidated FinancialStatements.

covers the City of Baltimore and all or part of ten Unaffiliated Revenues counties in central Maryland. BGE was incorporated in Merchant Regulated Regulated Other Maryland in 1906. Energy Electric Gas Nonregulated Our other nonregulated businesses:

" design, construct, and operate renewable energy, 2007 83% 12% 4% 1%

heating, cooling, and cogeneration facilities, and 2006 83 11 5 1 2005 81 12 6 1 provide various energy-related services, including energy consulting, for commercial, Net Income (1) industrial, and governmental customers Merchant Regulated Regulated Other Energy Electric Gas Nonregulated throughout North America, and

• provide home improvements, service heating, 2007 83% 12% 3% 2%

air conditioning, plumbing, electrical, and 2006 77 16 5 2 indoor air quality systems, and provide natural 2005 67 28 5 -

gas to residential customers in central Total Assets Maryland. Merchant Regulated Regulated Other Energy Electric Gas Nonregulated Constellation Energy maintains a website at constellation.com where copies of our annual reports on 2007 73% 20% 6% 1%

Form 10-K, quarterly reports on Form 10-Q, current 2006 75 17 6 2 reports on Form 8-K, and any amendments may be 2005 77 16 6 1 obtained free of charge. These reports are posted on our (1) Excludes income from discontinued operations in website the same day they are filed with the SEC. The 2007, 2006 and 2005 and cumulative effects of SEC maintains a website (sec.gov), where copies of our changes in accountingprinciples in 2005 as discussed filings may be obtained free of charge. The website in more detail in Item 8. FinancialStatements and address for BGE is bge.com. These website addresses are Supplementary Data.

inactive textual references, and the contents of these websites are not part of this Form 10-K.

2

Merchant Energy Business " Plants with Power Purchase Agreements--our Introduction generating facilities outside the Mid-Atlantic Our merchant energy business integrates electric Region with long-term power purchase generation assets with the marketing and risk agreements. As discussed in Note 2 to management of energy and energy-related products to Consolidated Financial Statements, the sale of wholesale and retail customers, allowing us to manage the High Desert facility in 2006 resulted in a energy price risk over geographic regions and time. reclassification of its results to discontinued Our merchant energy business includes: operations.

• a power generation and development operation

• Wholesale Competitive Supply-our marketing, that owns, operates, and maintains fossil and risk management, and trading operation that renewable generating facilities, and holds provides energy products and services primarily interests in qualifying facilities, fuel processing to distribution utilities, power generators, and facilities and power projects in the other wholesale customers. We also include in United States, our wholesale competitive supply results our

• a nuclear generation operation that owns, global coal sourcing and logistics services and operates and maintains nuclear generating upstream and downstream natural gas services.

facilities and oversees our new nuclear " Retail Competitive Supply-our operation that development activities, provides electric and natural gas energy

• a customer supply operation that primarily products and services to commercial, industrial, provides energy products and services relating and governmental customers.

to load-serving obligations to wholesale and " Other-our investments in qualifying facilities retail customers, including distribution utilities, and domestic power projects and our cooperatives, aggregators, and commercial, generation operations and maintenance services.

industrial and governmental customers, and Beginning in 2008, we will analyze our merchant

• a global commodities operation that manages energy business in terms of Generation, Customer contractually controlled physical assets, Supply and Global Commodities activities.

including generation facilities, natural gas

• Generation-will encompass all of our properties, international coal and freight assets, generating assets, including those currently provides risk management services, and trades included in the Mid-Atlantic Region, Plants energy and energy-related commodities. with Power Purchase Agreements and Other.

Our merchant energy business: + Customer Supply-will encompass the current

" provided approximately 32,700 megawatts Retail Competitive Supply and the power (MW) of peak load in the aggregate to load-serving portion of Wholesale Competitive distribution utilities, municipalities, and Supply.

commercial, industrial, and governmental

• Global Commodities-will encompass the customers during 2007, remaining Wholesale Competitive Supply

• provided approximately 410,000 million British businesses including our marketing, risk Thermal Units (mmBTUs) of natural gas to management, and trading operations, global commercial, industrial, and governmental coal sourcing and logistics services, and customers during 2007, upstream and downstream natural gas services.

" delivered approximately 28 million tons of coal We present details about our generating properties to international and domestic third-party in Item 2. Properties.

customers and to our own fleet during 2007, and Mid-Atlantic Region

" managed approximately 8,730 MW of We own 6,355 MW of fossil, nuclear, and hydroelectric generation capacity as of December 31, 2007. generation capacity in the Mid-Atlantic Region. The For years 2007 and prior, we analyze the results of output of these plants is managed by our global our merchant energy business as follows: commodities operation and is hedged through a

• Mid-Atlantic Region-our fossil, nuclear, and combination of power sales to wholesale and retail hydroelectric generating facilities and market participants. Our merchant energy business load-serving activities in the Mid-Atlantic meets the load-serving requirements of various contracts region of the PJM Interconnection (PJM). This using the output from the Mid-Atlantic Region and also includes active portfolio management of from purchases in the wholesale market.

generating assets and other physical and financial contractual arrangements, as well as other PJM competitive supply activities.

3

BGE transferred all of these facilities to our We exclusively operate Unit 2 under an operating merchant energy generation subsidiaries on July 1, 2000 agreement with LIPA., LIPA is responsible for 18% of as a result of the implementation of electric customer the operating costs (and decommissioning costs) of Unit choice and competition among suppliers in Maryland, 2 and has representation on the Nine Mile Point Unit 2 except for the Handsome Lake facility that commenced management committee, which provides certain operations in mid-2001. The assets transferred from oversight and review functions.

BGE are subject to the lien of BGE's mortgage. We We own 100% of the Ginna nuclear facility. Ginna expect the assets to be released from this lien following consists of a 581 MW reactor that entered service in payment in March 2008 of the last series of bonds 1970 and is licensed to operate until 2029. We sell up to outstanding under the mortgage and the subsequent 80% of the plant's output and capacity to the former discharge of the mortgage. owners for 10 years ending in 2014 at an average price Our merchant energy business supplies BGE with of $44.00 per MWH under a long term unit contingent a portion of its market-based standard offer service power purchase agreement. The remaining output is obligation. For 2007, the peak load supplied to BGE managed by our global commodities operation and sold was approximately 3,200 MW into the wholesale market.

Plants with Power Purchase Agreements Competitive Supply We own 2,134 MW of nuclear generation capacity with We are a leading supplier of energy products and power purchase agreements for a significant portion of services to wholesale customers and retail commercial, their output. Our facilities with power purchase industrial, and governmental customers. In 2007, our agreements are the Nine Mile Point Nuclear Station wholesale competitive supply operation provided (Nine Mile Point) and the R.E. Ginna Nuclear Plant approximately 16,500 peak MWs of wholesale full (Ginna). Both Nine Mile Point and Ginna are located requirements load-serving products. During 2007, our within the New York Independent System Operator retail competitive supply activities served approximately (NYISO) region. 16,200 MW of peak load and approximately 410,000 We own 100% of Nine Mile Point Unit 1 (620 mmBTUs of natural gas.

MW) and 82% of Unit 2 (933 MW). The remaining interest in Nine Mile Point Unit 2 is owned by the Wholesale and Retail Load-Serving Activities Long Island Power Authority (LIPA). Unit 1 entered Our wholesale competitive supply operation structures service in 1969 and is licensed to operate until 2029. transactions that serve the full energy and capacity requirements of various customers such as distribution Unit 2 entered service in 1988 and is licensed to utilities, municipalities, cooperatives, and retail operate until 2046.

We sell 90% of our share of Nine Mile Point's aggregators that do not own sufficient generating capacity or in-house supply functions to meet their own output to the former owners of the plant at an average load requirements.

price of nearly $35 per megawatt-hour (MWH) under Our retail competitive supply operation structures agreements that terminate between 2009 and 2011. The transactions to supply full energy and capacity agreements are unit contingent (if the output is not requirements and provide natural gas, transportation, available because the plant is not operating, there is no requirement to provide output from other sources). The and other energy products and services to retail, commercial, industrial, and governmental customers.

remaining 10% of our share of Nine Mile Point's output is managed by our global commodities operation Contracts with these customers generally extend from one to ten years, but some can be longer. To meet our and sold into the wholesale market.

customers' load-serving requirements, our merchant After termination of the power purchase energy business obtains energy from various sources, agreements, a revenue sharing agreement with the former owners of the plant will begin and continue including:

" bilateral power and natural gas purchase through 2021. Under this agreement, which applies only to our ownership percentage of Unit 2, a agreements with third parties,

• unit contingent purchases from generation predetermined strike price is compared to the market price for electricity. If the market price exceeds the companies,

• our generation assets, strike price, then 80% of this excess amount is shared with the former owners of the plant. The average strike " regional power pools, price for the first year of the revenue sharing agreement

• tolling contracts with generation companies, which provide us the right, but not the is $40.75 per MWH. The strike price increases two obligation, to purchase power at a price linked percent annually beginning in the second year of the to the variable cost of production, including revenue sharing agreement. The revenue sharing agreement is unit contingent and is based on the fuel, with terms that generally extend from several months to several years, but can be operation of the unit.

longer, and 4

• exchange traded electricity and natural gas *futures contracts (which are exchange traded contracts. standardized commitments to purchase or sell a commodity or financial instrument, or make a Portfolio Management and Trading cash settlement, at a specified price and future We continue to identify and pursue opportunities which date).

can generate additional returns through portfolio Active portfolio management allows our merchant management and trading activities within our business. energy business to:

These opportunities have increased due to the

• manage and hedge its fixed-price energy significant growth in scale of our competitive supply purchase and sale commitments, operations. In managing our portfolio, we may " provide fixed-price energy commitments to terminate, restructure, or acquire contracts. Such customers and suppliers, transactions are within the normal course of managing " reduce exposure to the volatility of market our portfolio and may materially impact the timing of prices, and our recognition of revenues, fuel and purchased energy

• hedge fuel requirements at our non-nuclear expenses, and cash flows. generation facilities.

Our global commodities operation actively uses Coal and International Services energy and energy-related commodities and contracts Our global commodities operation participates in global for those commodities in order to manage our portfolio coal sourcing activities by providing coal and of energy purchases and sales to customers through coal-related logistical services for the variable or fixed structured transactions. We use both derivative and supply needs of global customers. In late 2006, we nonderivative contracts in managing our portfolio of formed a shipping joint venture that will own and energy sales and purchase contracts. Generally, we operate six freight ships for the delivery of coal and expect to use both derivative and nonderivative other dry bulk freight products. We own a 50% interest contracts to hedge our portfolio in order to reduce in this joint venture. In 2007, we delivered volatility. Although a substantial portion of our approximately 28 million tons of coal to global portfolio is hedged, we are able to identify customers and to our own generation fleet. Additionally, opportunities to deploy risk capital to increase the value we entered into power, natural gas, freight, and of our accrual positions, which we characterize as emissions transactions outside of the United States. We portfolio management.

also include in our coal services the results from our We trade energy and energy-related contracts and synthetic fuel processing facility in South Carolina. In commodities and deploy risk capital in the management 2008, these synthetic fuel processing facilities will be of our portfolio in order to earn additional returns.

decommissioned.

These activities are managed through daily value at risk We will continue to evaluate new international and stop loss limits and liquidity guidelines, and could opportunities, including expanding our coal sourcing, have a material impact on our financial results. We freight, power, natural gas and emissions activities discuss the impact of our trading activities and value at outside of the United States.

risk in more detail in Item 7. Managementý Discussion and Analysis. Natural Gas Services These activities involve the use of physical Our global commodities operation includes upstream commodity inventories and a variety of instruments, (exploration and production) and downstream including: (transportation and storage) natural gas operations. Our

• forward contracts (which commit us to upstream activities include the acquisition, development, purchase or sell energy commodities in the and exploitation of natural gas properties. Our future), downstream activities include providing natural gas to

• swap agreements (which require payments to or various customers, including large utilities, commercial from counterparties based upon the difference and industrial customers, power generators, wholesale between two prices for a predetermined marketers, and retail aggregators.

contractual (notional) quantity), In 2007, 2006 and 2005, we acquired working

" option contracts (which convey the right to buy interests in gas producing fields. We discuss these or sell a commodity, financial instrument, or acquisitions in more detail in Note 15 to Consolidasted index at a predetermined price), and FinancialStatements.

5

In November 2006, we completed the initial In connection with this joint venture, we entered public offering of Constellation Energy Partners LLC into an investor agreement with EDF under which EDF (CEP), a limited liability company that we formed. may purchase in the open market up to a total of 9.9%

CEP is principally engaged in the acquisition, of our outstanding common stock during the next five development, and exploitation of natural gas properties. years, with a limit of 5% ownership during the first During 2007, CEP conducted additional equity twelve months of the agreement. EDF has agreed to issuances in which we did not participate, and our vote any shares of our common stock owned by it in ownership percentage fell below 50 percent. Therefore, the manner recommended by our board of directors in 2007, we deconsolidated CEP and began to account and not take any actions that seek control of for our interest under the equity method of accounting. Constellation Energy during the next five years.

We discuss the impact of CEP's equity issuances and deconsolidation on our financial results in more detail Fuel Sources in Note 2 to ConsolidatedFinancialStatements. Our power plants use diverse fuel sources. Our fuel mix based on capacity owned at December 31, 2007 and Other our generation based on actual output by fuel type in We hold up to a 50% voting interest in 24 operating 2007 were as follows:

energy projects that consist of electric generation (primarily relying on alternative fuel sources), fuel Fuel Capacity Owned Gener;atiof processing, or fuel handling facilities. Of those, the Nuclear .............. 45% 6 I1%

electric generation projects are considered qualifying Coal ................. 31 35 facilities under the Public Utility Regulatory Policies Act Natural Gas ........... 7 -

of 1978. Each electric generating plant sells its output O il .................. 8 to a local utility under long-term contracts. Renewable and We also provide operation and maintenance Alternative (1) ...... 5 4 services, including testing and start-up, to owners of Dual (2) .............. 4 electric generating facilities. (1) Includes solar, geothermal, hydro, waste coal and biomass.

UniStar Nuclear (2) Switches between naturalgas and oil.

In 2005, we formed UniStar Nuclear, LLC (UniStar), a joint enterprise with AREVA NP, Inc., (AREVA) to We discuss our risks associated with fuel in more introduce the advanced design Evolutionary Power detail in Item 7. Management's Discussion and Reactor to the U.S. market. Upon conversion to U.S. Analysis-Market Risk.

electrical standards, the technology will be known as the U.S. EPR. Nuclear In August 2007, we formed a joint venture, The output of our nuclear facilities over the past five UniStar Nuclear Energy, LLC (UNE) with an affiliate years (including periods prior to our acquisition of of Electricite de France, SA (EDF). We have a 50% Ginna in June 2004) is presented in the following table:

ownership interest in this joint venture to develop, own, Calvert Cliffs Nine Mile Point Ginna and operate new nuclear projects in the United States Capacity Capacity Capacity and Canada. The agreement with EDF includes a MWH Factor MWH* Factor MWH Factor phased-in cash investment of $625 million by EDF in (MWJH in millions)

UNE. Initially, EDF invested $350 million of cash in 2007 14.3 94% 12.3 90% 4.9 98%

UNE, and we contributed UniStar and other UniStar-2006 13.8 90 12.8 93 4.1 93 related assets, which had a book value of $49 million, 2005 14.7 97 12.7 93 4.0 93 and the right to develop new nuclear projects at our 2004 14.5 96 12.1 89 4.3 100 existing nuclear plant locations. Upon reaching certain 2003 13.7 93 12.2 90 3.9 90 licensing milestones, EDF will contribute up to an

• representsour proportionateownership interest additional $275 million of cash in UNE for a total of

$625 million. In the event that the joint venture is The supply of fuel for nuclear generating stations terminated, the remaining equity of UNE, after certain includes the:

expenses, will be divided equally between Constellation " purchase of uranium (concentrates and uranium Energy and EDF pursuant to the joint venture hexafluoride),

agreement. " conversion of uranium concentrates to uranium hexafluoride,

" enrichment of uranium hexafluoride, and

" fabrication of nuclear fuel assemblies.

6

Uranium and We have commitments that provide for In connection with our purchase of Ginna, all of Conversion sufficient quantities of uranium the former owner's rights and obligations related to (concentrates and uranium hexafluoride) recovery of damages for DOE's failure to meet its for the next several years. contractual obligations were assigned to us. However, Enrichment We have commitments that provide for we have an obligation to reimburse the former owner our uranium enrichment requirements for for up to $10 million of any recovered damages for the next several years. such claims.

Fuel Assembly We have commitments for the fabrication Storage of Spent Nuclear Fuel-On-Site Facilities Fabrication of fuel assemblies for reloads required for Calvert Cliffs has a license from the NRC to operate an the next several years for Calvert Cliffs on-site independent spent fuel storage installation that Nuclear Power Plant, Inc. (Calvert Cliffs), expires in 2012. We have storage capacity at Calvert Nine Mile Point and for Ginna.

Cliffs that will accommodate spent fuel from operations The nuclear fuel markets are competitive, and through 2011. In addition, we can expand our prices can be volatile; however, we do not anticipate any temporary storage capacity at Calvert Cliffs to meet significant problems in meeting our future supply future requirements until approximately 2025. Nine requirements. Mile Point and Ginna are developing independent spent fuel storage installations at each of those facilities, Storage of Spent Nuclear Fuel-FederalFacilities which we expect to be completed in 2011 and 2010, One of the issues associated with the operation and respectively. Nine Mile Point and Ginna have sufficient decommissioning of nuclear generating facilities is storage capacity within the plant until the expected disposal of spent nuclear fuel. There are no facilities for completion of the on-site independent spent fuel the reprocessing or permanent disposal of spent nuclear storage installations.

fuel currently in operation in the United States, and the NRC has not licensed any such facilities. The Nuclear Cost for Decommissioning Nuclear Facilities Waste Policy Act of 1982 (NWPA) required the federal We are obligated to decommission our nuclear plants government, through the Department of Energy after these plants cease operation. Every two years, the (DOE), to develop a repository for the disposal of spent NRC requires us to demonstrate'reasonable assurance nuclear fuel and high-level radioactive waste. that funds will be available to decommission the sites.

As required by the NWPA, we are a party to When BGE transferred all of its nuclear generating contracts with the DOE to provide for disposal of spent assets to our merchant energy business, it also nuclear fuel from our nuclear generating plants. The transferred the funds accumulated to pay for NWPA and our contracts with the DOE require decommissioning Calvert Cliffs. At December 31, 2007, payments to the DOE of one tenth of one cent (one the external Calvert Cliffs trust fund assets were mill) per kilowatt hour on nuclear electricity generated $457.4 million.

and sold to pay for the cost of long-term nuclear fuel Under the Maryland Public Service Commission's storage and disposal. We continue to pay those fees into (Maryland PSC) order regarding the deregulation of the DOE's Nuclear Waste Fund for our nuclear electric generation, BGE ratepayers must pay a total of generating facilities. The NWPA and our contracts with $520 million, in 1993 dollars adjusted for inflation, to the DOE required the DOE to begin taking possession decommission Calvert Cliffs through fixed annual of spent nuclear fuel generated by nuclear generating collections. BGE is collecting this amount on behalf of units no later than January 31, 1998. Calvert Cliffs. Any costs to decommission Calvert Cliffs The DOE has stated that it may not meet that in excess of this $520 million, in 1993 dollars adjusted obligation until 2017 at the earliest. This delay has for inflation, must be paid by Calvert Cliffs. If BGE required that we undertake additional actions to provide ratepayers have paid more than this amount at the time on-site fuel storage at our nuclear generating facilities, of decommissioning, Calvert Cliffs must refund the including the installation of on-site dry fuel storage excess. If the cost to decommission Calvert Cliffs is less capacity as described in more detail below. than the $520 million, in 1993 dollars adjusted for In 2004, complaints were filed against the federal inflation, BGE's ratepayers are obligated to pay, Calvert government in the United States Court of Federal Cliffs may keep the difference.

Claims seeking to recover damages caused by the DOE's failure to meet its contractual obligation to begin disposing of spent nuclear fuel by January 31, 1998.

These cases are currently stayed, pending litigation in other related cases.

7

In 2006, BGE received approval from the Coal Maryland PSC to continue previously approved annual We purchase the majority of our coal for electric customer collections for decommissioning of generation under supply contracts with mining approximately $18.7 million through December 31, operators, and we acquire the remainder in the spot or 2016. BGE will be required to submit a filing to forward coal markets. We believe that we will be able to determine the level of customer contributions after renew supply contracts as they expire or enter into December 31, 2016. Senate Bill 1, which was enacted contracts with other coal suppliers. Our primary coal in June 2006, requires BGE to provide credits to burning facilities have the following requirements:

residential electric customers equal to the amount Approximate collected for decommissioning annually for 10 years Annual Coal Requirement Special Coal beginning January 1, 2007. Under the provisions of (tons) Restrictions Senate Bill 1, we are required to apply the collection of the nuclear decommissioning trust funds over the ten Brandon Shores 3,500,000 Sulfur content less year period beginning January 1, 2007 toward the Units 1 and 2 than 1.20 lbs of fulfillment of the decommissioning obligations of BGE (combined) SO 2/mmBTU C. P. Crane 850,000 Low ash melting ratepayers. As discussed in Item 7. Managements Units 1 and 2 temperature Discussion and Analysis-Business Environment-Regulation-Maryland-SenateBill I and 400 section, (combined)

H. A. Wagner 1,100,000 Sulfur content less we have notified the State of Maryland of our intent to Units 2 and 3 than'l.60 lbs of file an action challenging the legality of this Senate (combined) S0 2/mmBTU Bill 1 requirement.

The sellers of Nine Mile Point transferred a Coal deliveries to these facilities are made by rail

$441.7 million decommissioning trust fund to us at the and barge. Over the past few years, we expanded our time of sale. In return, we assumed all liability for the coal sources through a variety of methods, including costs to decommission Unit 1 and 82% of the costs to restructuring our rail contracts, increasing the range of decommission Unit 2. We believe that this amount is coals we can consume, adding synthetic fuel as an adequate to cover our responsibility for alternate source, and finding potential other coal supply decommissioning Nine Mile Point to a greenfield status sources including shipments from various international (restoration of the site so that it substantially matches sources. While we primarily use coal produced from the natural state of the surrounding properties and the mines located in central and northern Appalachia, we site's intended use). At December 31, 2007, the Nine are capable of switching to imported coals to manage Mile Point trust fund assets were $610.2 million. our coal supply. Synthetic fuel will no longer be burned The seller of Ginna transferred $200.8 million in as an alternate source since tax credits for synthetic fuel decommissioning funds to us. In return, we assumed all expired on December 31, 2007. The timely delivery of liability for the costs to decommission the unit. We coal together with the maintenance of appropriate levels believe that this amount will be sufficient to cover our of inventory is necessary to allow for continued, reliable responsibility for decommissioning Ginna to a generation from these facilities.

greenfield status. At December 31, 2007, the Ginna All of the Conemaugh and Keystone plants' annual trust fund assets were $263.2 million. coal requirements are purchased by the plant operators from regional suppliers on the open market. The sulfur restrictions on coal are approximately 2.3% for the Keystone plant and approximately 5.3% for the Conemaugh plant.

The annual coal requirements for the ACE, Jasmin, and Poso plants, which are located in California, are supplied under contracts with mining operators. These plants are restricted to coal with sulfur content less than 2.0%.

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

8

All of our coal requirements reflect historical With respect to power generation, we compete in generating levels. The actual fuel quantities required can the operation of energy-producing projects, and our vary substantially from historical generating levels competitors in this business are both domestic and depending upon the relationship between energy prices international organizations, including various utilities, and fuel costs, weather conditions, and operating industrial companies and independent power producers requirements. (including affiliates of utilities, Financial investors, banks and investment banks), some of which have greater Gas financial resources.

We purchase natural gas, storage capacity, and States are considering different types of regulatory transportation, as necessary, for electric generation at initiatives concerning competition in the power and gas certain plants. Some of our gas-fired units can use industry, which makes a competitive assessment residual fuel oil or distillates instead of gas. Gas is difficult. Increased competition that resulted from some purchased under contracts with suppliers on the spot of these initiatives in several states contributed in some market and forward markets, including financial instances to a reduction in electricity prices and put exchanges and under bilateral agreements. The actual pressure on electric utilities to lower their costs, fuel quantities required can vary substantially from year including the cost of purchased electricity. Many states to year depending upon the relationship between energy continue to support or expand retail competition and prices and fuel costs, weather conditions, and operating industry restructuring. Other states that were requirements. However, we believe that we will be able considering deregulation have slowed their plans or to obtain adequate quantities of gas to meet our postponed consideration of deregulation. In addition, requirements.

certain previously restructured states are considering oil reregulation of their retail markets. While there is Under normal burn practices, our requirements for significant activity in this area, we believe there is residual fuel oil (No. 6) amount to. approximately adequate growth potential in the current deregulated 1.0 million to 1.5 million barrels of low-sulfur oil per market and that further market changes could provide year. Deliveries of residual fuel oil are made from the additional opportunities for our merchant energy suppliers' Baltimore Harbor and Philadelphia marine business.

terminals for distribution to the various generating plant As the market for commercial, industrial, and locations. Also, based on normal burn practices, we governmental energy supply continues to grow, we have require approximately 8.0 million to 11.0 million experienced increased competition on a regional basis in gallons of distillates (No. 2 oil and kerosene) annually, our retail competitive supply activities. The increase in but these requirements can vary substantially from year retail competition and the impact of wholesale power to year depending upon the relationship between energy prices compared to the rates charged by local utilities prices and fuel costs, weather conditions, and operating has, in certain circumstances, reduced the margins that requirements. Distillates are purchased from the we realize from our customers. However, we believe that suppliers' Baltimore truck terminals for distribution to our experience and expertise in assessing and managing the various generating plant locations. We have risk and our strong focus on customer service will help contracts with various suppliers to purchase oil at spot us to remain competitive during volatile or otherwise prices, and for fuiture delivery, to meet our adverse market circumstances.

requirements.

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

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

9

Merchant Energy Operating Statistics 2007 2006 2005 2004 2003 Revenues (In millions)

Mid-Atlantic Region $ 3,462.2 $ 2,813.5 $ 2,283.9 $ 1,925.6 $1,696.2 Plants with Power Purchase Agreements 657.3 650.5 665.9 555.3 463.3 Competitive Supply-Retail 9,086.3 8,014.7 6,942.3 4,280.0 2,567.7 Competitive Supply-Wholesale 5,469.4 5,612.7 4,672.3 3,353.8 2,703.9 Other 69.3 74.8 58.0 73.6 45.1 Total Revenues $18,744.5 $17,166.2 $14,622.4 $10,188.3 $7,476.2 Generation (In millions)-MWIH* 51.6 59.1 60.2 55.3 51.6

• Includes outputfrom gas-firedplants until sale in December 2006 Operatingstatistics do not reflect the, elimination of intercompany transactions.

Baltimore Gas and Electric Company StandardOffer Service BGE is an electric transmission and distribution utility BGE is obligated to provide market-based standard offer company and a gas distribution utility company with a service (SOS) to all of its electric customers. The SOS service territory that covers the City of Baltimore and rates charged recover BGE's wholesale power supply all or part of ten counties in central Maryland. BGE is costs and include an administrative fee. The regulated by the Maryland PSC and Federal Energy administrative fee includes a shareholder return Regulatory Commission (FERC) with respect to rates component and an incremental cost component. As and other aspects of its business. discussed in Item 7. Management's Discussion and BGE's electric service territory includes an area of Analysis-Regulated Electric Business-Senate Bill 1 approximately 2,300 square miles. There are no Credits section, BGE is now required to credit to municipal or cooperative wholesale customers within residential electric customers the shareholder return BGE's service territory. BGE's gas service territory component of the administrative charge for residential includes an area of approximately 800 square miles. SOS service.

BGE's electric and gas revenues come from many Bidding to supply BGE's market-based standard customers-residential, commercial, and industrial. offer service will occur from time to time through a competitive bidding process approved by the Maryland Electric Business PSC. Successful bidders, which may include subsidiaries Electric Competition of Constellation Energy, will execute contracts with Deregulation BGE for varying terms.

Effective July 1, 2000, electric customer choice and competition among electric suppliers was implemented Commercial and Industrial Customers in Maryland. As a result of the deregulation of electric BGE is obligated to provide market-based standard offer generation, all customers can choose their electric service to commercial and industrial customers for energy supplier. While BGE does not sell electric varying periods beyond June 30, 2004, depending on commodity to all customers in its service territory, BGE customer load.

continues to deliver electricity to all customers and In August 2006, the Maryland PSC issued an provides meter reading, billing, emergency response, and order indefinitely extending the obligation of Maryland regular maintenance. utilities to provide SOS service for those commercial and industrial customers for which market-based standard offer service was scheduled to expire at the end of May 2007. The extended service will be provided on substantially the same terms as under the then existing service, except that wholesale bidding for service to some customers will be conducted more frequently.

BGE's obligation to provide market-based standard offer service to its largest commercial and industrial customers expired on May 31, 2005. BGE continues to provide an hourly-priced market-based standard offer service to those customers.

10

Residential Customers These programs generally take effect on summer As a result of the November 1999 Maryland PSC order days when demand and/or wholesale prices are relatively regarding the deregulation of electric generation in high and had the effect of reducing BGE's system peak Maryland, BGE's residential electric base rates were load by 248 MW during the summer period in 2007.

frozen until July 2006. Subsequent, orders of the BGE is also developing other programs designed to Maryland PSC specified that BGE would procure the help BGE manage peak demand, improve system power to serve residential customers beginning July reliability and improve service to customers by giving 2006 via auctions to be conducted in late 2005 and customers greater control over their energy use.

early 2006. The procured power costs of these auctions Recently, the Maryland PSC approved full would have resulted in an average electric residential implementation of a demand response program, which customer bill increase of 72%. In June 2006, Senate will enable BGE to regulate participating customer Bill 1 was enacted, which, among other things: energy use through the use of programmable thermostats

" capped rate increases by BGE for residential and air conditioner load control devices at customer SOS service at 15% from July 1, 2006 to premises during peak demand periods. The Maryland May 31, 2007, PSC also approved the implementation of an advanced

" gave residential SOS customers the option from metering pilot program, which will enable BGE to June 1, 2007 until December 31, 2007 of paying improve customer service and offer special pricing as an a full market rate or choosing a short term rate incentive to customers to reduce energy use during peak stabilization plan in order to provide a smooth demand periods and to detect power outages transition to market rates without adversely electronically. BGE has also initiated a program that will affecting the creditworthiness of BGE, and provide incentives to customers to use energy efficient

" provided for full market rates for all residential products and to take other actions to conserve energy.

SOS service starting January 1, 2008. We also discuss the demand response initiatives in Item 7. Managements Discussion and We further discuss the impacts of Senate Bill 1 Analysis-Regulation-Maryland-MarylandPSC section.

and other recent legislation in Item 7. Managements Discussion and Analysis-Business Environment-Transmission and Distribution Facilities Regulation-Maryland-Senate Bills I and 400 section.

BGE maintains approximately 250 substations and We discuss the market risk of our regulated electric 1,300 circuit miles of transmission lines throughout business in more detail in Item 7. Management's central Maryland. BGE also maintains approximately Discussion and Analysis-Market Risk section.

24,000 circuit miles of distribution lines. The transmission facilities are connected to those of Electric Load Management neighboring utility systems as part of PJM. Under the BGE has implemented various programs for use when PJM Tariff and various agreements, BGE and other system-operating conditions or market economics market participants can use regional transmission indicate that a reduction in load would be beneficial.

facilities for energy, capacity, and ancillary services These programs include:

transactions including emergency assistance.

• two options for commercial and industrial We discuss various FERC initiatives relating to customers to reduce their electric loads, wholesale electric markets in more detail in Item 7.

• air conditioning control for residential and Management's Discussion and Analysis-FederalRegulation commercial customers, and section.

• residential water heater control.

11

Electric Operating Statistics 2007 2006 2005 2004 2003 Revenues (In millions)

Residential $1,514.9 $1,092.1 $1,066.6 $1,015.8 $ 959.0 Commercial Excluding Delivery Service Only 577.4 733.4 722.1 708.9 694.2 Delivery Service Only 217.0 149.4 107.5 78.6 66.1 Industrial Excluding Delivery Service Only 31.6 46.8 52.8 92.3 137.0 Delivery Service Only 27.8 26.2 28.0 21.3 18.2 System Sales and Deliveries 2,368.7 2,047.9 1,977.0 1,916.9 1,874.5 Other (A) 87.0 68.0 59.5 50.8 47.1 Total $2,455.7 $2,115.9 $2,036.5 $1,967.7 $1,921.6 Distribution Volumes (In thousands)-MWH Residential 13,365 12,886 13,762 13,313 12,754 Commercial Excluding Delivery Service Only 4,364 6,325 7,847 9,286 9,937 Delivery Service Only 11,921 9,392 7,967 5,767 4,982 Industrial Excluding Delivery Service Only 287 467 614 1,429 2,556 Delivery Service Only 3,175 2,988 3,122 2,562 1,780 Total 33,112 32,058 33,312 32,357 32,009 Customers (In thousands)

Residential 1,103.1 1,093.3 1,084.1 1,072.1 1,061.7 Commercial 116.7 115.5 114.7 113.6 112.1 Industrial 5.5 5.2 5.0 4.8 4.9 Total 1,225.3 1,214.0 1,203.8 1,190.5 1,178.7 (A) Primarily includes network integration transmission service revenues, late payment charges, miscellaneous service fees, and tower leasing revenues.

Operatingstatistics do not reflect the elimination of intercompany transactions.

"Delivery service only" refers to BGE's delivery of commodity that was purchased by the customer from an alternate supplier.

12

Gas Business BGE purchases the natural gas it resells to The wholesale price of natural gas as a commodity is customers directly from many producers and marketers.

not subject to regulation. All BGE gas customers have BGE has transportation and storage agreements that the option to purchase gas from alternative suppliers, expire from 2008 to 2027.

including subsidiaries of Constellation Energy. BGE BGE's current pipeline firm transportation continues to deliver gas to all customers within its entitlements to serve BGE's firm loads are 338,053 service territory. This delivery service is regulated by the dekatherms (DTH) per day.

Maryland PSC. BGE's current maximum storage entitlements are BGE also provides customers with meter reading, 248,153 DTH per day. To supplement its gas supply at billing, emergency response, regular maintenance, and times of heavy winter demands and to be available in balancing services. temporary emergencies affecting gas supply, BGE has:

Approximately 50% of the gas delivered on BGE's

• a liquefied natural gas facility for the distribution system is for customers that purchase gas liquefaction and storage of natural gas with a from alternative suppliers. These customers are charged total storage capacity of 1,092,977 DTH and a fees to recover the costs BGE incurs to deliver the daily capacity of 311,500 DTH, and customers' gas through our distribution system.

• a propane air facility and a mined cavern with In December 2005, the Maryland PSC issued an a total storage capacity equivalent to 564,200 order granting BGE a $35.6 million annual increase in DTH and a daily capacity of 85,000 DTH.

its gas base rates, which are the rates the Maryland PSC BGE has under contract sufficient volumes of allows BGE to charge its customers for the cost of propane for the operation of the propane air facility and providing them delivery service plus a profit. In is capable of liquefying sufficient volumes of natural gas December 2006, the Baltimore City Circuit Court during the summer months for operations of its upheld the rate order. However, certain parties have liquefied natural gas facility during peak winter periods.

filed an appeal with the Court of Special Appeals. We BGE historically has been able to arrange cannot provide assurance that the Maryland PSC's order short-term contracts or exchange agreements with other will not be reversed in whole or in part or that certain gas companies in the event of short-term disruptions to issues will not be remanded to the Maryland PSC for gas supplies or to meet additional demand.

reconsideration. BGE also participates in the interstate markets by For customers that buy their gas from BGE, there releasing pipeline capacity or bundling pipeline capacity is a market-based rates incentive mechanism. Under this with gas for off-system sales. Off-system gas sales are market-based rates incentive mechanism, our actual cost low-margin direct sales of gas to wholesale suppliers of of gas is compared to a market index (a measure of the natural gas. Earnings from these activities are shared market price of gas in a given period). The difference between shareholders and customers. BGE makes these between our actual cost and the market index is shared sales as part of a program to balance our supply of, and equally between shareholders and customers. BGE must cost of, natural gas.

secure fixed-price contracts for at least 10%, but not more than 20%, of forecasted system supply requirements for flowing (i.e., non-storage) gas for the November through March period. These fixed-price contracts are not subject to sharing under the market-based rates incentive mechanism.

13

Gas Operating Statistics 2007 2006 2005 2004 2003 Revenues (In millions)

Residential Excluding Delivery Service Only $ 552.0 $ 490.2 $ 558.5 $ 478.0 $ 444.5 Delivery Service Only 19.0 20.6 23.2 14.2 13.6 Commercial Excluding Delivery Service Only 154.1 148.9 174.4 135.4 128.6 Delivery Service Only 41.2 35.9 31.9 28.0 24.6 Industrial Excluding Delivery Service Only 7.8 7.5 10.5 9.4 11.5 Delivery Service Only 22.1 19.3 12.4 7.8 11.4 System Sales and Deliveries 796.2 722.4 810.9 672.8 634.2 Off-System Sales 157.4 168.6 154.7 77.2 84.8 Other 9.2 8.5 7.2 7.0 7.0 Total $ 962.8 $ 899.5 $ 972.8 $ 757.0 $ 726.0 Distribution Volumes (In thousands)-DTH Residential Excluding Delivery Service Only 39,199 33,019 39,107 39,080 40,894 Delivery Service Only 4,310 3,948 5,423 6,053 6,640 Commercial Excluding Delivery Service Only 12,464 11,683 14,133 13,248 13,895 Delivery Service Only 30,367 25,695 -28,993 34,120 29,138 Industrial Excluding Delivery Service Only 658 604 921 865 1,143 Delivery Service Only 17,897 20,325 19,357 14,310 18,399 System Sales and Deliveries 104,895 95,274 107,934 107,676 110,109 Off-System Sales 19,963 19,738 17,209 9,914 12,859 Total 124,858 115,012 125,143 117,590 122,968 Customers (In thousands)

Residential 602.3 597.1 590.9 582.0 575.2 Commercial 42.7 42.3 42.0 41.6 41.1 Industrial 1.2 1.2 1.2 1.2 1.2 Total 646.2 640.6 634.1 624.8 617.5 Operating statistics do not reflect the elimination of intercompany transactions.

"Deliveryservice only" refers to BME~ delivery of commodity that was purchased by the customer from an alternate supplier.

14

Franchises We continuously monitor federal, state, and local BCE has nonexclusive electric and gas franchises to use environmental initiatives to determine potential impacts streets and other highways that are adequate and on our financial results. As new laws or regulations are sufficient to permit it to engage in its present business. promulgated, we assess their applicability and Conditions of the franchises are satisfactory. implement the necessary modifications to our facilities or their operation to maintain ongoing compliance. Our Other Nonregulated Businesses capital expenditures were approximately $190 million Energy Projects and Services during the five-year period 2003-2007 to comply with We offer energy projects and services designed primarily existing environmental standards and regulations. Our to provide energy solutions to large commercial, estimated environmental capital requirements for the industrial and governmental customers. These energy next three years are approximately $575 million in products and services include:

2008, $390 million in 2009, and $30 million in 2010.

" designing, constructing, and operating renewable energy, heating, cooling, and Air Quality cogeneration facilities, I Federal

" energy savings projects and performance The Clean Air Act created the basic framework for the contracting, federal and state regulation of air pollution.

• energy consulting and procurement services, National Ambient Air Quality Standards (NAAQS)

• services to enhance the reliability of individual The NAAQS are federal air quality standards authorized electric supply systems, and under the Clean Air Act that establish maximum

" customized financing alternatives.

ambient air concentrations for the following specific Home Products and Gas Retail Marketing pollutants: ozone (smog), carbon monoxide, lead, We offer services to customers in Maryland including: particulates, sulfur dioxides (SO 2 ), and nitrogen dioxides

" home improvements, (NO,).

" the service of heating, alt conditioning, In order for states to achieve compliance with the plumbing, electrical, and indoor air quality NAAQS, the Environmental Protection Agency (EPA) systems, and adopted the Clean Air Interstate Rule (CAIR) in March

" the sa-le of natural gas to residential customers. 2005 to further reduce ozone and fine particulate pollution by addressing the interstate transport of SO 2 Consolidated Capital Requirements and nitrogen oxide (NO.) emissions from fossil Our total capital requirements for 2007 were fuel-fired generating facilities, located primarily in the

$1,665 million. Of this amount, $1,263 million was Eastern United States.

used in our nonregulated businesses and $402 million In December 2006, the United States Court of was used in our regulated business. We estimate our Appeals for the District of Columbia Circuit ruled that total capital requirements will be $2.5 billion in 2008.

a requirement to impose fees on emissions sources based We continuously review and change our capital on the previous ozone standard (Section 185 fees),

expenditure programs, so actual expenditures may vary which had been rescinded by the EPA in May 2005, from the estimate above. We discuss our capital remained applicable retroactive to November 2005 and requirements fuirther in Item 7. Managements Discussion remanded the issue to the EPA for reconsideration. A and Analysis-Capital Resources section.

petition to the United States Supreme Court to hear an Environmental Matters appeal was denied in January 2008. The EPA has The development (involving site selection, announced that it intends to propose regulations by the environmental assessments, and permitting), summer of 2008 to address how Section 185 fees will construction, acquisition, and operation of electric be handled. In addition, the exact method of generating and distribution facilities are subject to computing these fees has not been established and will extensive federal, state, and local environmental and depend in part on state implementation regulations that land use laws and regulations. From the beginning have nor been proposed. Consequently, we are unable phases of development to the ongoing operation of to estimate the ultimate financial impact of this matter existing or new electric generating and distribution in light of the uncertainty surrounding the anticipated facilities, our activities involve compliance with diverse EPA and state rulemakings. However, the final laws and regulations that address emissions and impacts resolution of this matter, and any fees that are to air and water, protection of natural and cultural ultimately assessed could have a material impact on our resources, and chemical and waste handling financial results.

and disposal.

15

In September 2006, the EPA adopted a stricter CapitalExpenditure Estimates NAAQS for particulate matter. We are unable to We expect to incur additional environmental capital determine the impact that complying with the stricter spending as a result of complying with the air quality NAAQS for particulate matter will have on our financial laws and regulations discussed above. To comply with results until the states in which our generating fucilities are CAIR, HAA, and CPR, we will install additional air located adopt plans to meet the new standard. emission control equipment at our coal-fired generating facilities in Maryland and at our co-owned coal-Fired Hazardous Air Emissions facilities in Pennsylvania to meet air quality standards.

In March 2005, the EPA finalized the Clean Air We include in our estimated environmental capital Mercury Rule (CAMR) to reduce the emissions of requirements capital spending for these alt quality mercury from coal-fired facilities through a market-projects, which we expect will be approximately based cap and trade program. CAMR was to affect all

$550 million in 2008, $350 million in 2009, coal or waste coal Fired boilers at our generating

$15 million in 2010 and $25 million from 201 1-2012.

facilities. However, in February 2008, the United States Our estimates are subject to significant Court of Appeals for the District of Columbia Circuit uncertainties including the timing of any additional struck down CAMR. At this time, we cannot predict federal and/or state regulations or legislation, such as what actions the EPA will take in response to the any regulations adopted by the EPA in response to the court's decision. However, any action that requires the court decision striking down CAMR, the installation of additional emissions control technology implementation timetables for such regulation or beyond what is required under Maryland's Healthy Air legislation, and the specific a-mount of emissions Act and Clean Power Rule, which are discussed below, reductions that will be required at our facilities. As a may require us to incur additional costs, which could result, we cannot predict our capital spending or the have a material effect on our financial results.

scope or timing of these projects with certainty, and the New Source Review actual expenditures, scope and timing could differ In connection with its enforcement of the Clean Air significantly from our estimates.

Act's new source review requirements, in 2000, the EPA We believe that the additional air emission control requested information relating to modifications made to equipment we plan to install will meet the emission our Brandon Shores, Crane, and Wagner plants located reduction requirements under CAIR, l-AA, and CPR.

in Maryland. The EPA also sent similar, but narrower, If additional emission reductions still are required, we information requests to two of our newer Pennsylvania will assess our various compliance alternatives and 'their waste-coal burning plants in which we have an related costs, and although we cannot yet estimate the:

ownership interest. We responded to the EPA in 2001, additional costs we may incur, such costs could be and as of the date of this report the EPA has taken no material.

further action.

Based on the level of emissions control that the Global Climate Change EPA and states are seeking in these new source review Although uncertainty remains as to the nature and timing enforcement actions, we believe that material additional of greenhouse gas emissions regulation, there is an costs and penalties could be incurred, and planned increasing likelihood that such regulation will occur at the capital expenditures could be accelerated, if the EPA federal and/or state level. In the event that greenhouse gas was successful in any future actions regarding our emissions reduction legislation or regulations are enacted, facilities. we will assess our various compliance alternatives, which may include installation of additional environmental State controls, modification of operating schedules or the closure Maryland has adopted the Healthy Air Act (HAA) and of one or more of our coal-fired generating facilities. Any the Clean Power Rule (CPR), which establish annual compliance costs we incur could have a material impact SO 2 , NO,, and mercury emission caps for specific on our financial results.

coal-fired units in Maryland, including units located at However, to the extent greenhouse gas emissions three of our facilities. The requirements of the l-AA are regulated through a federal, mandatory cap and and the CPR for SO 2 , NO,., and mercury emissions are trade greenhouse gas emissions program, we believe our more stringent and apply sooner than those under business could also benefit. Our generation fleet CAIR. In addition, Pennsylvania has adopted currently has a carbon dioxide (C0 2 ) emission rate regulations requiring coal-fired generating facilities lower than the industry average with more than 60% of located in Pennsylvania to reduce mercury emissions. the fleet's output coming from low carbon dioxide Several other states in the northeastern U.S. emitting nuclear and hydroelectric plants. Our global continue to consider more stringent and earlier SO 2 , commodities business has experience trading in the NO,,, and mercury emissions reductions than those markets for emissions allowances and renewable energy required under CAIR or what would have been required credits.

under CAMR.

16

In accordance with H-AA requirements, Maryland Hazardous and Solid Waste became a full participant in the Northeast Regional We discuss proceedings relating to compliance with the Greenhouse Gas Initiative (RGGI) in April 2007. In Comprehensive Environmental Response, Compensation Octoher 2007, under RGGI, the Maryland Department and Liability Act in Note 12 to Consolidated Financial of the Environment proposed auctioning 90% of CO 2 Statements.

allowances associated with Maryland's power plants, Our coal-fired generating facilities produce which include plants owned by us. If this proposal is approximately two and a half million tons of enacted, we could incur material costs to purchase CO 2 combustion by-products ("ash") each year. The EPA allowances necessary to offset emissions from our plants. announced in 2007 its intention to develop national In addition, California has adopted regulations standards to regulate this material as a non-hazardous requiring our generating facilities in California to waste, and has been developing or considering submit greenhouse gas emissions data to the state, regulations governing the placement of ash in landfills, which the state intends to use to develop a plan to surface impoundments, sand/gravel surface mines and reduce greenhouse gas emissions. coal mines. In addition, the Maryland Department of We continue to evaluate the potential impact of the Environment proposed revised regulations governing the HAA and California CO 2 emissions requirements the disposal, storage, use and placement of ash in and RGGI participation on our financial results; December 2007. Final rules are expected in June 2008.

however, our compliance costs could be material. Federal and state regulation has the potential to result in additional requirements. Depending on the scope of Water Quality any final requirements, our compliance costs could be The Clean Water Act established the basic framework material.

for federal and state regulation of water pollution As a result of these regulatory proposals and our control and requires facilities that discharge waste or current ash generation projections, we are exploring our storm water into the waters of the United States to options for the management of ash, including obtain permits. construction of an ash placement facility. Over the next Water Intake Regulations five years, we estimate that our capital expenditures for The Clean Water Act requires cooling water intake this project will be approximately $75 million. Our structures to reflect the best technology available for estimates are subject to significant uncertainties minimizing adverse environmental impacts. In July including the timing of any regulatory change, its 2004, the EPA published final rules under the Clean implementation timetable, and the scope of the final Water Act for existing facilities that establish requirements. As a result, we cannot predict our capital performance standards for meeting the best technology spending or the scope and timing of this project with available for minimizing adverse environmental impacts. certainty, and the actual expenditures, scope and timing We currently have six facilities affected by the could differ significantly from our estimates.

regulation. In January 2007, the United States Court of Employees Appeals for the Second Circuit ruled that the EPA's rule Constellation Energy and its subsidiaries had did not properly implement the Clean Water Act approximately 10,200 employees at December 31, 2007.

requirements in a number of areas and remanded the Ar the Nine Mile Point facility, approximately 510 rule to the EPA for reconsideration.

employees are represented by the International In response to this ruling, in July 2007, the EPA Brotherhood of Electrical Workers, Local 97. The labor suspended the second phase of the regulations pending contract with this union expires in June 2011. We further rulemaking and directed the permitting believe that our relationship with this union is authorities to establish controls for cooling water intake satisfactory, but there can be no assurances that this will structures that reflect the best techiiology available for continue to be the case.

minimizing adverse environmental impacts. In November 2007, a number of parties petitioned the United States Supreme Court to hear an appeal of the Second Circuit's decision.

A decision by the United Stares Supreme Court on whether to hear the case is not expected until mid to late 2008. In addition, the EPA is expected to propose new regulations by the end of 2008. During this period, we will continue to evaluate our compliance options in light of the Second Circuit decision and the EPA's July 2007 order. At this time, we cannot estimate our compliance costs, but they could be material.

17

Item IA. Risk Factors fuel through short-term contracts or on the spot You should consider carefully the following risks, along market. Fuel prices can be volatile, and the price that with the other information contained in this Form 10-K can be obtained for power produced from such fuel The risks and uncertaintiesdescribed below are not the may not change at the same rate as fuel costs. As a only ones that may affect us. Additional risks and result, fuel price increases may adversely affect our uncertainties also may adversely affect our business and financial results.

operations including those discussed in Item 7. Exposure to counterpartyperformance. Our Managements Discussion and Analysis. If any of the merchant energy business enters into transactions with following events actually occur, our business andfinancial numerous third parties (commonly referred to as results could be materially adversely affected. "counterparties"). In these arrangements, we are exposed to the credit risks of our counterparties and the risk Our merchant energy business may incur that one or more counterparties may fail to perform substantial costs and liabilities and be exposed under their obligations to make payments or deliver fuel to price volatility and counterparty performance or power. In addition, we enter into various wholesale risk as a result of its participation in the transactions through Independent System Operators wholesale energy markets.

(ISOs). These IS*s are exposed to counterparty credit We purchase and sell power and fuel in markets risks. Any losses relating to counterparty defaults exposed to significant risks, includihg price volatility for impacting the ISOs are allocated to and borne by all electricity and fuel and the credit risks of counterparties other market participants in the ISO. These risks are with which we enter into contracts.

enhanced during periods of commodity price We use various hedging strategies in an effort to fluctuations. Defaults by suppliers and other mitigate many of these risks. However, hedging counterparties may adversely affect our financial results.

transactions do not guard against all risks and are not always effective, as they are based upon predictions The operation of power generation facilities, about future market conditions. The inability or failure including nuclear facilities, involves significant to effectively hedge assets or fuel or power positions risks that could adversely affect our financial against changes in commodity prices, interest rates, results.

counterparty credit risk or other risk measures could We own and operate a number of power generation significantly impair future financial! results. facilities. The operation of power generation facilities Exposure to electricity price voldtility. We buy and involves many risks, including start up risks, breakdown sell electricity in both the wholesale bilateral markets or failure of equipment, transmission lines, substations and spot markets, which expose us 'to the risks of rising or pipelines, use of new technology, the dependence on and falling prices in those markets, .and our cash flows a specific fuel source, including the transportation of may vary accordingly. At any given, time, the wholesale fuel, or the impact of unusual or adverse weather spot market price of electricity for each hour is conditions (including natural disasters such as generally determined by the cost of supplying the next hurricanes) or environmental compliance, as well as the unit of electricity to the market during that hour. This risk of performance below expected or contracted levels is highly dependent on the regional generation market. of output or efficiency. This could result in lost In many cases, the next unit of electricity supplied revenues and/or increased expenses. Insurance, would be supplied from generating stations fueled by warranties, or performance guarantees may not cover fossil fuels, primarily coal, natural gas and oil. any or all of the lost revenues or increased expenses, Consequently, the open market wholesale price of including the cost of replacement power. A portion of electricity may reflect the cost of coal, natural gas or oil our generation facilities were constructed many years plus the cost to convert the fuel to electricity and an ago. Older generating equipment may require significant appropriate return on capital. Therefore, changes in the capital expenditures to keep it operating at peak supply and cost of coal, natural gas and oil may impact efficiency. This equipment is also likely to require the open market wholesale price of electricity. periodic upgrading and improvement. Breakdown or A portion of our power generation facilities failure of one of our operating facilities may prevent the operates wholly or partially without long-term power facility from performing under applicable power sales purchase agreements. As a result, power from these agreements which, in certain situations, could result in facilities is sold on the spot market or on a short-term termination of the agreement or incurring a liability for contractual basis, which if not fully hedged may affect liquidated damages.

the volatility of our financial results.

Exposure to fiel cost volatility. Currently, our power generation facilities purchase a portion of their 18

We are subject to numerous environmental laws " inadequacy or lapses in maintenance protocols; and regulations that require capital

• impairment of reactor operation and safety expenditures, increase our cost of operations systems due to human or mechanical error; and may expose us to environmental liabilities.

" costs of storage, handling and disposal of We are subject to extensive federal, state, and local nuclear materials, including the availability or environmental statutes, rules and regulations relating to unavailability of a permanent repository for air quality, water quality, waste management, wildlife spent nuclear fuel; protection, the management of natural resources, and

" regulatory actions, including shut down of units the protection of human health and safety that could, because of public safety concerns, whether at among other things, require additional pollution control our plants or other nuclear operators; equipment, limit the use of certain fuels, restrict the " limitations on the amounts and types of output of certain facilities, or otherwise increase costs. insurance coverage commercially available; Significant capital expenditures, operating and other

" uncertainties regarding both technological and costs are associated with compliance with environmental financial aspects of decommissioning nuclear requirements, and these expenditures and costs could generating facilities; and become even more significant in the future as a result

" environmental risks, including risks associated of regulatory changes. with changes in environmental legal For example, there is increasing likelihood that requirements.

regulation of greenhouse gas emissions will occur at the Nuclear Accident Risks. In the event of a nuclear federal and/or state level, which could increase our accident, the cost of property damage and other compliance and operating costs.

expenses incurred may exceed our insurance coverage We are subject to liability under environmental available from both private sources and an industry laws for the costs of remediating environmental retrospective payment plan. In addition, in the event of contamination. Remediation activities include the an accident at one of our or another participating cleanup of current facilities and former properties, insured party's nuclear plants, we could be assessed including manufactured gas plant operations and offsite retrospective insurance premiums (because all nuclear waste disposal facilities. The remediation costs could be plant operators contribute to a nationwide catastrophic significantly higher than the liabilities recorded by us.

insurance fund). Uninsured losses or the payment of Also, our subsidiaries are currently involved in retrospective insurance premiums could each have a proceedings relating to sites where hazardous substances material adverse effect on our financial results.

have been released and may be subject to additional proceedings in the future.

Our generation growth plans may not achieve the We are subject to legal proceedings by individuals desired financial results.

alleging injury from exposure to hazardous substances We may expand our generation capacity over the next and could incur liabilities that may be material to our several years through increasing the generating power of financial results. Additional proceedings could be filed existing plants, the renovation of retired plants owned against us in the future. by us, and the construction or acquisition of new We may also be required to assume environmental plants. The renovation, development, construction, and liabilities in connection with future acquisitions. As a acquisition of additional generation capacity involves result, we may be liable for significant environmental numerous risks. Any planned power uprates, remediation costs and other liabilities arising from the construction, or renovation could result in cost operation of acquired facilities, which may adversely overruns, lower than expected plant efficiency, and affect our financial results. higher operating and other costs. With respect to the renovation of retired plants or the construction of new Our generation business may incur substantial plants, we may incur significant sums for preliminary costs and liabilities due to its ownership and engineering, permitting, legal, and other expenses before operation of nuclear generating facilities.

it can be established whether a project is feasible, We own and operate nuclear power plants. Ownership economically attractive, or capable of being financed.

and operation of these plants exposes us to risks in If we were unable to complete the construction or addition to those that result from owning and operating renovation of a plant, we may not be able to recover non-nuclear power generation facilities. These risks our investment in the project. Furthermore, we may be include normal operating risks for a nuclear facility and unable to run any new, acquired or renovated plants as the risks of a nuclear accident.

efficiently as projected, which could result in Nuclear Operating Risks. The ownership and higher-than-projected operating and other costs that operation of nuclear generating facilities involve routine adversely affect our financial results.

operating risks, including:

• mechanical or structural problems; 19

We often rely on single suppliers and at times on guidelines are based on historical price movements. If single customers, exposing us to significant price movements significantly or persistently deviate financial risks if either should fail to perform from historical behavior, the limits may not protect us their obligations. from significant losses.

We often rely on a single supplier for the provision of Our risk management policies and procedures may fuel, water, and other services required for operation of not always work as planned. As a result of these and a facility, and at times, we rely on a single customer or other factors, we cannot predict with precision the a few customers to purchase all or a significant portion impact that risk management decisions may have on of a facility's output, in some cases under long-term our financial results.

agreements that provide the support for any project deht used to finance the facility. The failure of any one The use of derivative contracts by us in the customer or supplier to fulfill its contractual obligations normal course of business could result in could negatively impact our financial results. financial losses that negatively impact our Consequently, our financial performance depends on financial results.

the continued performance by customers and suppliers We use derivative instruments, such as swaps, options, of their obligations under these long-term agreements. futures and forwards, to manage our commodity and financial market risks and to engage in trading Reduced liquidity in the markets in which we activities. We could recognize financial losses as a result operate could impair our ability to appropriately of volatility in the market values of these contracts or if manage the risks of our operations. a counterparty fails to perform.

We are an active participant in energy markets through In the absence of actively quoted market prices our competitive energy businesses. The liquidity of and pricing information from external sources, the regional energy markets is an important factor in our valuation of these derivative instruments involves ability to manage risks in these operations. Over the management'Is judgment or use of estimates. As a result, past several years, several merchant energy businesses changes in the underlying assumptions or use of have ended or significantly reduced their activities as a alternative valuation methods could affect the reported result of several factors including government fair value of these contracts.

investigations, changes in market design and deteriorating credit quality. As a result, several regional A failure in our operational systems or energy markets experienced a significant decline in infrastructure, or those of third parties, may liquidity. Liquidity in the energy markets can be adversely affect our financial results.

adversely affected by various factors, including price Our businesses are dependent upon our operational volatility and the availability of credit. As a result, systems to process a large amount of data and complex future reductions in liquidity may restrict our ability to transactions. If any of our financial, accounting or other manage our risks and this could impact our Financial data processing systems fail or have other significant results. shortcomings, our financial results could be adversely affected. Our Financial results could also be adversely We may not fully hedge our generation assets, affected if an employee causes our operational systems competitive supply or other market positions to fail, either as a result of inadvertent error or by against changes in commodity prices, and our deliberately tampering with or manipulating our hedging procedures may not work as planned. operational systems. In addition, dependence upon To lower our financial exposure related to commodity automated systems may further increase the risk that price fluctuations, we routinely enter into contracts to operational system flaws or employee tampering or hedge a portion of our purchase and sale commitments, manipulation of those systems will result in losses that weather positions, fuel requirements, inventories of are difficult to detect.

natural gas, coal and other commodities, and We may also be subject to disruptions of our competitive supply. As part of this strategy, we routinely operational systems arising from events that are wholly utilize fixed-price forward physical purchase and sales or partially beyond our control (for example, natural contracts, futures, financial swaps, and option contracts disasters, acts of terrorism, epidemica, computer viruses traded in the over-the-counter markets or on exchanges. and telecommunications outages). Third party systems However, we may not cover the entire exposure of our on which we rely could also suffer operational system assets or positions to market price volatility and the failure. Any of these occurrences could disrupt one or coverage will vary over time. Fluctuating commodity more of our businesses, result in potential liability or prices may negatively impact our financial results to the reputational damage or otherwise have an adverse affect extent we have unhedged positions.

on our financial results.

In addition, risk management tools and metrics such as daily value at risk, stop loss limits and liquidity 20

We operate in deregulated segments of the Our merchant energy business has contractual electric and gas industries created by federal obligations to certain customers to provide full and state restructuring initiatives. If competitive requirements service, which makes it difficult to restructuring of the electric or gas industries is predict and plan for load requirements and may reversed, discontinued, restricted or delayed, result in increased operating costsý to our our business prospects and financial results business.

could be materially adversely affected. Our merchant energy business has contractual The regulatory environment applicable to the electric obligations to certain customers to supply full and natural gas industries has undergone substantial requirements service to such customers to satisfy all or a changes as a result of restructuring, initiatives at both portion of their energy requirements. The uncertainty the state and federal levels. These initiatives have had a regarding the amount of load that our merchant energy significant impact on the nature of the electric and business must be prepared to supply to customers may natural gas industries and the manner in which their increase our operating costs. A significant under- or participants conduct their businesses. We have targeted over-estimation of load requirements could result in our the competitive segments of the electric and natural gas merchant energy business nor having enough or having industries created by these initiatives. too much power to cover its load obligation, in which Due to recent events in the energy markets, energy case it would be required to buy or sell power from or companies have been under increased scrutiny by state to third parties at prevailing market prices. Those prices legislatures, regulatory bodies, capital markets and credit may nor be favorable and thus could increase our rating agencies. This increased scrutiny could lead to operating costs.

substantial changes in laws and regulations affecting us, including modifications to the auction processes in Our financial results may fluctuate on a seasonal competitive markets and new accounting standards that and quarterly basis or as a result of severe could change the way we are required to record weather.

revenues, expenses, assets and liabilities. Recent Our business is affected by weather conditions. Our proposals by the Maryland PSC relating to the structure overall operating results may fluctuate substantially on a of the electric industry in Maryland and various options seasonal basis, and the pattern of this fluctuation may for re-regulation of the industry is one example of how change depending on the nature and location of any these laws and regulations can change. We cannot facility we acquire and the terms of any contract to predict the future development of regulation in these which we become a party. Weather conditions directly markets or the ultimate effect that this changing influence the demand for electricity and natural gas and regulatory environment will have on our business. affect the price of energy commodities.

If competitive restructuring of the electric and Generally, demand for electricity peaks in winter natural gas markets is reversed, discontinued, restricted and summer and demand for gas peaks in the winter.

or delayed, or if the recent Maryland PSC proposals are Typically, when winters are warmer than expected and implemented in a manner adverse to us, our business summers are cooler than expected, demand for energy is prospects and financial results could be negatively lower, resulting in less electric and gas consumption impacted. than forecasted. Depending on prevailing market prices for electricity and gas, these and other unexpected Our financial results may be harmed if conditions may reduce our revenues and results of transportation and transmission availability is operations. First and third quarter financial results, in limited or unreliable. particular, are substantially dependent on weather We have business operations throughout the United conditions, and may make period comparisons less States and internationally. As a result, we depend on relevant.

transportation and transmission facilities owned and Severe weather can be destructive, causing outages operated by utilities and other energy companies to and/or property damage. This could require us to incur deliver the electricity, coal, and natural gas we sell to additional costs. Catastrophic weather, such as the wholesale and retail markets, as well as the natural hurricanes, could impact our or our customers' gas and coal we purchase to supply some of our operating facilities, communication systems and generating facilities. If transportation or transmission is technology. Unfavorable weather conditions may have a disrupted or capacity is inadequate, our ability to sell material adverse effect on our financial results.

and deliver products may be hindered. Such disruptions could also hinder our ability to provide electricity, coal A downgrade in our credit ratings could or natural gas to our customers or power plants and negatively affect our ability to access capital may materially adversely affect our financial results. and/or operate our wholesale and retail competitive supply businesses.

We rely on access to capital markets as a source of liquidity for capital requirements not satisfied by 21

operating cash flows. If any of our credit ratings were to outcome may affect our, or BCE's, financial results, but be downgraded, especially below investment grade, our it could be material.

ability to raise capital on favorable terms, including the In addition, the June 2006 legislation required commercial paper markets, could be hindered, and our BCE to provide credits to residential electric customers borrowing costs would increase. Additionally, the totaling approximately $39 million annually. In January business prospects of our wholesale and retail 2008, we notified the State of Maryland of our intent competitive supply businesses, which in many cases rely to file a federal action to enforce our righ ts under the on the creditworthiness of Constellation Energy, would 1999 Maryland electric deregulation settlement and to be negatively impacted. Some of the factors that affect challenge the constitutionality of the residential credit ratings are cash flows, liquidity, the amount of customer credits provided for under the June 2006 debt as a component of total capitalization, and legislation. We may incur significant costs to litigate political, legislative and regulatory events. this action and we cannot provide any assurances that it In addition, the ability of BCE to recover its costs will be resolved in our favor. If the action is resolved in of providing service and timing of BCE's recovery could a manner adverse to us, which may include a court have a material adverse effect on the credit ratings of determining that the legislation appropriately required BCE and us. the residential rate credits or overturning aspects of the 1999 electric deregulation settlement, the impact on We, and BGE in particular, are subject to our, or BCE's, Financial results could be material.

extensive local, state and federal regulation that The regulatory process may restrict our ability to could affect our operations and costs. grow earnings in certain parts of our business, cause We are subject to regulation by federal and state delays in or affect business planning and transactions governmental entities, including the Federal Energy and increase our, or BCE's, costs.

Regulatory Commission, the Nuclear Regulatory Commission, the Maryland PSC and the utility Poor market performance will affect our benefit commissions of other states in which we have plan and nuclear decommissioning trust asset operations. In addition, changing governmental policies values, which may adversely affect our liquidity and regulatory actions can have a significant impact on and financial results.

us. Regulations can affect, for example, allowed rates of Our qualified pension obligations have exceeded the fair return, requirements for plant operations, recovery of value of our plan assets since 2001. At December 31, costs, limitations on dividend payments and the 2007, our qualified pension obligations were regulation or re-regulation of wholesale and retail approximately $315 million greater than the fair value competition (including but not limited to retail choice of our plan assets. The performance of the capital and transmission costs). markets will affect the value of the assets that are held BCE's distribution rates are subject to regulation in trust to satisfy our future obligations under our by the Maryland PSC, and such rates are effective until qualified pension plans. A decline in the market value new rates are approved. In addition, limited categories of those assets may increase our funding requirements of costs are recovered through adjustment charges that for these obligations, which may adversely affect our are periodically reset to reflect current and projected liquidity and financial results.

costs. Inability to recover material costs not included in We are required to maintain funded trusts to rates or adjustment clauses, including increases in satisfy our future obligations to decommission our uncollectible customer accounts that may result from nuclear power plants. A decline in the market value of higher gas or electric costs, could have an adverse effect those assets due to poor investment performance or on our, or BCE's, cash flow and financial position. other factors may increase our funding requirements for Energy legislation enacted in Maryland in June these obligations, which may have an adverse effect on 2006 and April 2007 mandated that the Maryland PSC our liquidity and financial results.

review Maryland's deregulated electricity market. In December 2007 and January 2008, the Maryland PSC War and threats of terrorism and catastrophic issued interim reports that addressed the costs and events that could result from terrorism may benefits of options for re-regulation and reviewed the impact our results of operations in unpredictable ways.

impact to customers resulting from Maryland's We cannot predict the impact that any future terrorist deregulation process. In addition, the Maryland PSC attacks may have on the energy industry in general and continues to review the relationship between on our business in particular. In addition, any Constellation Energy and BCE. Because reviews of the retaliatory military strikes or sustained military Maryland electric industry and market structure are campaign may affect our operations in unpredictable ongoing, we cannot at this time predict the final ways, such as changes in insurance markets and outcome of these reviews and proposals or how such disruptions of fuel supplies and markets, particularly oil.

22

The possibility alone that infrastructure facilities, such availability of qualified personnel, collective bargaining as electric generation, electric and gas transmission and agreements with union employees, and work stoppage distribution facilities, would be direct targets of, or that could affect our financial results. In particular, our indirect casualties of, an act of terror may affect our competitive energy businesses are dependent, in part, on operations. recruiting and retaining personnel with experience in Such activity may have an adverse effect on the sophisticated energy transactions and the functioning of United States economy in general. A lower level of complex wholesale markets.

economic activity might result in a decline in energy consumption, which may adversely affect our financial Our ability to successfully identify, complete and results or restrict our future growth. Instability in the integrate acquisitions is subject to significant financial markets as a result of terrorism or war may risks, including the effect of increased affect our stock price and our ability to raise capital.

competition.

I We are likely to encounter significant competition for We are subject to employee workforce factors acquisition opportunities that may become available. In that could affect our businesses and financial addition, we may be unable to identify attractive results. acquisition opportunities at favorable prices and to We are subject to employee workforce factors, including successfully and timely complete and integrate them.

loss or retirement of key executives or other employees, Item 2. Properties All of BGE's property is subject to the lien of Constellation Energy occupies approximately 900,000 BGE's mortgage securing its mortgage bonds. The square feet of leased office space in North America, generation facilities transferred to our subsidiaries by which includes its corporate offices in Baltimore, BGE on July 1, 2000, along with the stock we own in Maryland. We describe our electric generation properties certain of our subsidiaries, are subject to the lien of on the next page. We also have leases for other offices BGE's mortgage. We expect the assets to be released and services located in the Baltimore metropolitan from this lien following payment in March 2008 of the region, and for various real property and facilities last series of bonds outstanding under the mortgage and relating to our generation projects. the discharge of the mortgage.

BGE owns its principal headquarters building We believe we have satisfactory title to our power located in downtown Baltimore. In addition, BGE owns project facilities in accordance with standards generally propane air and liquefied natural gas facilities as accepted in the energy industry, subject to exceptions, discussed in Item 1. Business-Gas Business section. which in our opinion, would not have a material BGE also has rights-of-way to maintain 26-inch adverse effect on the use or value of the facilities.

natural gas mains across certain Baltimore City-owned Our merchant energy business owns several natural property (principally parks) which expired in 2004. gas producing properties. We also lease office space in BGE is in the process of renewing the rights-of-way the United Kingdom and Australia to support our with Baltimore City for an additional 25 years. The merchant energy business.

expiration of the rights-of-way does not affect BGE's ability to use the rights-of-way during the renewal process.

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

• in public streets and highways pursuant to franchises, and

• on rights-of-way secured for the most part by grants from owners of the property.

23

The following table describes our generating facilities:

0/0 Capacit Plant Location Capacity (MW) Owned Owned (MW) Primary Fuel (at December 31, 2007)

Mid-Atlantic Region Calvert Cliffs Calvert Co., MD 1,735 100.0 1,735 Nuclear Brandon Shores Anne Arundel Co., MD 1,286 100.0 1,286 Coal H. A. Wagner Anne Arundel Co., MD 963 100.0 963 Coal/Oil/Gas C. P. Crane Baltimore Co., MD 399 100.0 399 Oil/Coal Keystone Armstrong and Indiana'Cos., PA 1,711 21.0 359 (A) Coal Conemaugh Indiana Co., PA 1,711 10.6 181 (A) Coal Perryman Harford Co., MD 355 100.0 355 Oil/Gas Riverside Baltimore Co., MD 232 100.0 232 Oil/Gas Handsome Lake Rockland Twp, PA 268 100.0 268 Gas Notch Cliff Baltimore Co., MD 120 100.0 120 Gas Westport Baltimore City, MD 116 100.0 116 Gas Philadelphia Road Baltimore City, MD 64 100.0 64 Oil Safe Harbor Safe Harbor, PA 417 66.7 278 Hydro Total Mid-Atlantic Region 9,376 6,355 Plants with Power PurchaseAgreements Nine Mile Point Unit I Scriba, NY 620 100.0 620 Nuclear Nine Mile Point Unit 2 Scriba, NY 1,138 82.0 933 Nuclear R.E. Ginna Ontario, NY 581 100.0 581 Nuclear Total Plants with Power PurchaseAgreements 2,339 2,134 Other Panther Creek Nesquehoning, PA 80 50.0 40 Waste Coal Colver Colver Township, PA 104 25.0 26 Waste Coal Sunnyside Sunnyside, UT 51 50.0 26 Waste Coal ACE Trona, CA 102 31.1 32 Coal Jasmin Kern Co., CA 35 50.0 18 Coal POSO Kern Co., CA 35 50.0 18 Coal Mammoth Lakes G-1 Mammoth Lakes, CA 6 50.0 3 Geothermal Mammoth Lakes G-2 Mammoth Lakes, CA 13 50.0 7 Geothermal Mammoth Lakes G-3 Mammoth Lakes, CA 13 50.0 7 Geothermal Soda Lake I Fallon, NV 4 50.0 2 Geothermal Soda Lake II Fallon, NV 10 50.0 5 Geothermal Rocklin Placer Co., CA 24 50.0 12 Biomass Fresno Fresno, CA 24 50.0 12 Biomass Chinese Station Jamestown, CA 20 45.0 9 Biomass Malacha Muck Valley, CA 32 50.0 16 Hydro SEGS IV Kramer Junction, CA 33 12.2 4 Solar SEGS V Kramer Junction, CA 24 4.2 1 Solar SEGS VI Kramer Junction, CA 34 8.8 3 Solar Total Other 644 239 Total Generating Facilities 12,359 8,728 (A) Reflects our proportionate interest in and entitlement to capacity from Keystone and Conemaugh, which include 2 MW of diesel capacity for Keystone and 1 MW of diesel capacity for Conemaugh.

The sum of the individualplant capacity MWs may not equal the totals due to the effects of rounding.

In February 2008, we acquired a partially completed 774 MW gas-fired combined-cycle power generation facility located in Alabama, which we plan to complete and have ready for commercial operation in early 2010. We discuss this acquisition in more detail in Note 15 to Consolidated FinancialStatements.

24

The following table describes our processing facilities:

Primary Plant Location Owned Fuel Waste Coal A/C Fuels Hazelton, PA 50.0 Processing Gary PCI Gary, IN 24.5 Coal Processing Low Country Cross, SC 99.0 Synfuel Processing PC Synfuel VA I Norton, VA 16.7 Synfuel Processing PC Synfuel WV I Chelyan, WV 16.7 Synfuel Processing PC Synfuel WV II Mount Storm, WV 16.7 Synfuel Processing PC Synfuel WV III* Chester, VA 16.7 Synfuel Processing

• Facility to be decommissioned in 2008.

Item 3. Legal Proceedings We discuss our legal proceedings in Note 12 to ConsolidatedFinancial Statements.

Item 4. Submission of Matters to Vote of Security Holders Not applicable.

Executive Officers of the Registrant Other Offices or Positions Held Name Age Present Office During Past Five Years Mayo A. Shattuck III 53 Chairman of the Board (since July Chairman of the Board of BGE.

2002), President and Chief Executive Officer (since November 2001) of Constellation Energy John R. Collins 50 Executive Vice President (since July Chief Risk Officer-Constellation 2007) and Chief Financial Officer Energy and Senior Vice President-(since May 2007) of Constellation Constellation Energy.

Energy; Senior Vice President and Chief Financial Officer of Baltimore Gas and Electric Company (since May 2007); and member of Board of Managers of Constellation Energy Partners LLC (since September 2006)

Thomas V. Brooks 45 President of Constellation Energy Vice Chairman-Constellation Energy Resources (since May 2007); and President and Chief Executive Chairman of Constellation Energy Officer-Constellation Energy Commodities Group, Inc. (since Commodities Group, Inc.

August 2005); and Executive Vice President of Constellation Energy (since January 2004)

Michael J. Wallace 60 President (since January 2002) and None.

Chief Executive Officer (since May 2005) of Constellation Energy Nuclear Group, LLC (formerly known as Constellation Generation Group, LLC); and Executive Vice President of Constellation Energy (since January 2004)

Thomas E Brady 58 Executive Vice President of Senior Vice President, Corporate Constellation Energy (since January Strategy and Development-2004); and Chairman of the Board of Constellation Energy.

BGE (since April 2007) 25

Other Offices or Positions Held Name Age Present Office During Past Five Years Irving B. Yoskowitz 62 Executive Vice President and General Senior Counsel-Crowell & Moring Counsel of Constellation Energy (law firm); and Senior Partner-(since June 2005) Global Technology Partners, LLC (investment banking and consulting firm).

Felix J. Dawson 40 Co-Chief Commercial Officer of Co-Chief Commercial Officer-Constellation Energy Resources (since Constellation Energy Commodities August 2007); Senior Vice President Group, Inc.; and Managing of Constellation Energy (since Director-Constellation Energy October 2006); Co-President and Commodities Group, Inc.

Co-Chief Executive Officer of Constellation Energy Commodities Group, Inc. (since August 2005); and President and Chief Executive Officer of Constellation Energy Partners LLC (since May 2006)

George E. Persky 38 Co-Chief Commercial Officer of Co-Chief Commercial Officer-Constellation Energy Resources (since Constellation Energy Commodities August 2007); Senior Vice President Group, Inc.; and Managing of Constellation Energy (since Director-Constellation Energy October 2006); and Co-President and Commodities Group, Inc.

Co-Chief Executive Officer of Constellation Energy Commodities Group, Inc. (since August 2005)

Kenneth W DeFontes, Jr. 57 President and Chief Executive Officer of Vice President, Electric Transmission Baltimore Gas and Electric Company and Distribution-BGE.

and Senior Vice President of Constellation Energy (since October 2004)

Paul J. Allen 56 Senior Vice President, Corporate Affairs Vice President, Corporate Affairs-(since January 2004) and Chief Constellation Energy.

Environmental Officer (since June 2007) of Constellation Energy Beth S. Perlman 47 Senior Vice President (since January Vice President-Constellation Energy.

2004), Chief Administrative Officer (since June 2007) and Chief Information Officer (since April 2002) of Constellation Energy Marc L. Ugol 49 Senior Vice President, Human Resources Vice President, Human Resources-of Constellation Energy (since January Constellation Energy.

2004)

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

26

PART 11 Item S. Market for Registrant's Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities Stock Trading payable April 1, 2008 to holders of record on Constellation Energy's common stock is traded under March 10, 2008. This is equivalent to an annual rate of the ticker symbol CEG. It is listed on the New York $1.91 per share.

and Chicago stock exchanges. Quarterly dividends were declared on our common As of January 31, 2008, there were 39,186 stock during 2007 and 2006 in the a-mounts set forth common shareholders of record. below.

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

are no contractual limitations on Constellation Energy " BCE elects to defer interest payments on the paying common stock dividends. 6.20% Deferrable Interest Subordinated Dividends have been paid continuously since 1910 Debentures due 2043, and any deferred interest on the common stock of Constellation Energy, BCE, remains unpaid; or and their predecessors. Future dividends depend upon " any dividends (and any redemption payments) future earnings, our financial condition, and other due on BCE's preference stock have not been factors. paid.

In January 2008, we announced an increase in our quarterly dividend from $0.435 to $0.4775 per share Common Stock Dividends and Price Ranges 2007 2006 Dividend Dividend Price Prc Declared High LOW Declared High LOW First Quarter ................................. $0.435 $ 88.20 $68.78 $0.3775 $60.55 $54.01 Second Quarter ............................... 0.435 95.57 82.71 0.3775 55.68 50.55 Third Quarter................................. 0.435 98.20 76.64 0.3775 60.79 53.70 Fourth Quarter................................ 0.435 104.29 85.81 0.3775 70.20 59.00 Total ...................................... $ 1.74 $ 1.51 27

Purchases of Equity Securities by the Issuer and Affiliated Purchases The following table discloses purchases of shares of our common stock made by us or on our behalf for the periods shown below.

Total Number of Shares Maximum Dollar Purchased as Amount of Shares Part of Publicly that May Yet Be Total Number Announced Purchased Under of Shares Average Price Plans or the Plans and Programs Period Purchased(1) Paid for Shares Programs (at month end)(2)

October 1 - October 31, 2007 - $ - -$ 1.0 billion November 1 - November 30, 2007 200,000 96.31 2,023,527(3) 750 million December 1 - December 31, 2007 250,218 103.24 -750 million Total 450,218 $100.16 [ 2,023,527 (1) Represents shares surrendered by employees to exercise stock options and to satisfy, tax withholding obligations on vested restricted stock and stock option exercises and shares repurchased by us in the open market to satisfy employee stock option exercises and restricted stock grants.

(2) In October 2007, our board of directors approved a common share repurchase program for up to $1 billion of our outstanding common shares. The program is expected to be executed over the 24 months following approval in a manner that preserves flexibility to pursue additional strategic investment opportunities.

(3) Represents shares repurchased pursuant to an accelerated share repurchase agreement entered into with a financial institution. The final price of the shares repurchased was determined based on a discount to the volume-weighted average trading price of $100.53 per share of our common stock. In January 2008, the financial institution delivered 514,376 additional shares to us at the completion of the transaction.

See Note 9 to Consolidated Financial Statements for a further description of our common share repurchase program and the accelerated share repurchase agreement.

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Item 6. Selected Financial Data Constellation Energy Group, Inc. and Subsidiaries 2007 2006 2005 2004 2003 (In millions, except per share amounts)

Summary of Operations Total Revenues $21,193.2 $19,284.9 $16,968.3 $12,127.2 $ 9,342.8 Total Expenses 19,858.8 18,025.2 16,023.8 11,209.1 8,395.5 Gain on Sale of Gas-Fired Plants - 73.8 - - -

Income From Operations 1,334.4 1,333.5 944.5 918.1 947.3 Gain on sales of CEP equity 63.3 28.7 - - -

Other Income 158.6 66.1 65.5 25.5 20.6 Fixed Charges 305.6 328.7 310.2 326.8 336.3 Income Before Income Taxes 1,250.7 1,099.6 699.8 616.8 631.6 Income Taxes 428.3 351.0 163.9 118.4 222.2 Income from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles 822.4 748.6 535.9 498.4 409.4 (Loss) Income from Discontinued Operations, Net of Income Taxes (0.9) 187.8 94.4 41.3 66.3 Cumulative Effects of Changes in Accounting Principles, Net of Income Taxes - - (7.2) - (198.4)

Net Income $ 821.5 $ 936.4 $ 623.1 $ 539.7 $ 277.3 Earnings Per Common Share from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles Assuming Dilution $ 4.51 $ 4.12 $ 2.98 $ 2.88 $ 2.45 (Loss) Income from Discontinued Operations (0.01) 1.04 0.53 0.24 0.40 Cumulative Effects of Changes in Accounting Principles - - (0.04) - (1.19)

Earnings Per Common Share Assuming Dilution $ 4.50 $ 5.16 $ 3.47 $ 3.12 $ 1.66 Dividends Declared Per Common Share $ 1.74 $ 1.51 $ 1.34 $ 1.14 $ 1.04 Summary of Financial Condition Total Assets $21,945.7 $21,801.6 $21,473.9 $17,347.1 $15,593.0 Current Portion of Long-Term Debt $ 380.6 $ 878.8 $ 491.3 $ 480.4 $ 343.2 Capitalization Long-Term Debt $ 4,660.5 $ 4,222.3 $ 4,369.3 $ 4,813.2 $ 5,039.2 Minority Interests 19.2 94.5 22.4 90.9 113.4 Preference Stock Not Subject to Mandatory Redemption 190.0 190.0 190.0 190.0 190.0 Common Shareholders' Equity 5,340.2 4,609.3 4,915.5 4,726.9 4,140.5 Total Capitalization $10,209.9 $ 9,116.1 $ 9,497.2 $ 9,821.0 $ 9,483.1 Financial Statistics at Year End Ratio of Earnings to Fixed Charges 3.84 4.05 3.04 2.71 2.69 Book Value Per Share of Common Stock $ 29.93 $ 25.54 $ 27.57 $ 26.81 $ 24.68 We discuss items that affect comparability between years, including acquisitions and dispositions, accounting changes and other items, in Item 7. Managements Discussion and Analysis.

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Baltimore Gas and Electric Company and Subsidiaries 2007 2006 2005 2004 2003 (In millions)

Summary of Operations Total Revenues $3,418.5 $3,015.4 $3,009.3 $2,724.7 $2,647.6 Total Expenses 3,084.2 2,646.3 2,612.8 2,353.3 2,262.6 Income From Operations 334.3 369.1 396.5 371.4 385.0 Other Income (Expense) 26.8 6.0 5.9 (6.4) (5.4)

Fixed Charges 125.3 102.6 93.5 96.2 111.2 Income Before Income Taxes 235.8 272.5 308.9 268.8 268.4 Income Taxes 96.0 102.2 119.9 102.5 105.2 Net Income 139.8 170.3 189.0 166.3 163.2 Preference Stock Dividends 13.2 13.2 13.2 13.2 13.2 Earnings Applicable to Common Stock, $ 126.6 $ 157.1 $ 175.8 $ 153.1 $ 150.0 Summary of Financial Condition Total Assets $5,783.0 $5,140.7 $4,742.1 $4,662.9 $4,706.6 Current Portion of Long-Term Debt $ 375.0 $ 258.3 $ 469.6 $ 165.9 $ 330.6 Capitalization Long-Term Debt $1,862.5 $1,480.5 $1,015.1 $1,359.5 $1,343.7 Minority Interest 16.8 16.7 18.3 18.7 18.9 Preference Stock Not Subject to Mandatory Redemption 190.0 190.0 190.0 190.0 190.0 Common Shareholder's Equity 1,671.7 1,651.5 1,622.5 1,566.0 1,487.7 Total Capitalization $3,741.0 $3,338.7 $2,845.9 $3,134.2 $3,040.3 Financial Statistics at Year End Ratio of Earnings to Fixed Charges 2.84 3.60 4.22 3.75 3.36 Ratio of Earnings to Fixed Charges and Preferred and Preference Stock Dividends 2.42 2.99 3.45 3.08 2.82 30

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations Introduction and Overview cooperatives, and industrial, commercial, and governmental Constellation Energy Group, Inc. (Constellation Energy) is an customers.

energy company that conducts its business through various We obtain this energy through both owned and contracted subsidiaries including a merchant energy business and Baltimore supply resources. Our generation fleer is strategically located in Gas and Electric Company (BCE). We describe our operating deregulated markets and includes various fuel types, such as segments in Note 3. nuclear, coal, gas, Oil, and renewable sources. In addition to This report is a combined report of Constellation Energy owning generating facilities, we contract for power from other and BCE. References in this report to "we" and "our" are to merchant providers, typically through power purchase Constellation Energy and its subsidiaries, collectively. References agreements. We will use both our owned generation and our in this report to the "regulated business(es)" are to BCE. We contracted generation to support our competitive supply discuss our business in more detail in Item 1. Business section operations.

and the risk factors affecting our business in Item IA. Risk In addition, our merchant energy business is active in both Factors sectioni. upstream and downstream natural gas areas as well as coal In this discussion and analysis, we will explain the general sourcing and logistics services for the variable and fixed supply financial condition and the results of operations for needs of global customers.

Constellation Energy and BCE including: We are a leading national competitive supplier of energy. In

" factors which affect our businesses, our wholesale and commercial and industrial retail marketing

" our earnings and costs in the periods presented, activities we are leveraging our recognized expertise in providing

" changes in earnings and costs between periods, full requirements energy and energy-related services to enter

• sources of earnings, markets, capture market share, and organically grow these

" impact of these factors on our overall financial businesses. Through the application of technology, intellectual condition, capital, process improvement, and increased scale, we are seeking

" expected future expenditures for capital projects, and to reduce the cost of delivering full requirements energy and

" expected sources of cash for future capital expenditures. energy related services and managing risk.

As you read this discussion and analysis, refer to our We are also responding proactively to customer needs by Consolidated Statements of income, which present the results of expanding the variety of products we offer. Our wholesale our operations for 2007, 2006, and 2005. We analyze and competitive supply activities include a growing operation that explain the differences between periods in the specific line items markets physical energy products and risk management and of our Consolidated Statements of Income. logistics services to generators, distributors, producers of coal, We have organized our discussion and analysis as follows: natural gas and fuel oil, and other consumers.

" First, we discuss our strategy. I We trade energy and energy-related commodities and

" We then describe the business environment in which we deploy risk capital in the management of our portfolio in order operate including how regulation, weather, and other to earn additional returns. These activities are managed through factors affect our business. daily value at risk and stop loss limits and liquidity guidelines.

" Next, we discuss our critical accounting policies. These Within our retail competitive supply activities, we are are the accounting policies that are most important to marketing a broader array of products and expanding our both the portrayal of our financial condition and results markets. Over time, we may consider integrating the sale of of operations and require management's most difficult, electricity and natural gas to provide one energy procurement subjective or complex judgment. solution for our customers.

" We highlight significant events that are important to Collectively, the integration of owned and contracted understanding our results of operations and Financial electric generation assets with origination, fuel procurement, and condition. risk management expertise, allows our merchant energy business

" We then review our results of operations beginning with to earn incremental margin and more effectively manage energy an overview of our total company results, followed by a and commodity price risk over geographic regions and over time.

more detailed review of those results by operating Our focus is on providing solutions to customers' energy needs, segment. and our wholesale marketing, risk management, and trading

• We review our financial condition addressing our operation adds value to our owned and contracted generation sources and uses of cash, security ratings, capital assets by providing national market access, market infrastructure, resources, capital requirements, commitments, and real-time market intelligence, risk management and arbitrage off-balance sheet arrangements. opportunities, and transmission and transportation expertise.

• We conclude with a discussion of our exposure to Generation capacity supports our wholesale marketing, risk various market risks. management, and trading operation by providing a source of reliable power supply.

Strategy To achieve our strategic objectives, we expect to continue to We are pursuing a strategy of providing energy and energy pursue opportunities that expand our access to customers and to related services through our competitive supply activities and support our wholesale marketing, risk management, and trading BCE, our regulated utility located in Maryland. Our merchant operation with generation assets that have diversified geographic, energy business focuses on short-term and long-term purchases fuel, and dispatch characteristics. We also expect to grow and sales of energy, capacity, and related products to various through buying and selling a greater number of physical energy customers, including distribution utilities, municipalities, products and services to large energy customers. We expect to 31

achieve operating efficiencies within our competitive supply provider-of-last-resort requirements. Both the reconsideration of operation and our generation fleet by selling more products retail choice and possible new methodologies for wholesale through our existing sales force, benefiting from efficiencies of procurement could affect our customer supply group's future scale, adding to the capacity of existing plants, and making our opportunities to service commercial and industrial customers and business processes more efficient. the ability to provide wholesale products to utilities. The We expect BGE and our other retail energy service outcome of these efforts cannot be predicted, but they could businesses to grow through focused and disciplined expansion have a material effect on our financial results.

primarily from new customers. At BGE, we are also focused on All BGE electricity and gas customers have the option to enhancing reliability, customer satisfaction and customer demand purchase electricity and gas from alternate suppliers.

response initiatives. We discuss merchant competition in more detail in Item 1.

Customer choice, regulatory change, and energy market Business-Competition section.

conditions significantly impact our business. In response, we The impacts of electric deregulation on BGE in Maryland regularly evaluate our strategies with these goals in mind: to are discussed in Item 1. Business-Baltimore Gas and Electric improve our competitive position, to anticipate and adapt to the Company-Electric Business-Electric Competition section.

business environment and regulatory changes, and to maintain a strong balance sheet and investment-grade credit quality. Regulation-Maryland We are constantly reevaluating our strategies and might Maryland PSC consider: In addition to electric restructuring, which is discussed in

" acquiring or developing additional generating facilities Item 1. Business-Electric Competition section, regulation by the and gas properties to support our merchant energy Maryland PSC significantly influences BGE's businesses. The business, Maryland PSC determines the rates that BGE can charge

" renovating or extending the life of existing generation customers of its electric distribution and gas businesses. The facilities, Maryland PSC incorporates into BGE's standard offer service

• mergers or acquisitions of utility or non-utility rates the transmission rates determined by the Federal Energy businesses or assets, and Regulatory Commission (FERC). BGE's electric rates are

" sale of assets of one or more businesses. unbundled in customer billings to show separate components for delivery service (i.e. base rates), electric supply (commodity Business Environment charge), transmission, a universal service surcharge, and certain With the evolving regulatory environment surrounding customer taxes. The rates for BGE's regulated gas business continue to choice, increasing competition, and the growth of our merchant consist of a delivery charge (base rate) and a commodity charge.

energy business, various factors affect our financial results. We discuss some of these factors in more detail in the Item 1. Senate Bills 1 and 400 Business-Competition section. We also discuss these various In June 2006, Senate Bill 1 was enacted, which among other factors in the ForwardLooking Statements and Item ]A. Risk things:

Factors sections. " imposed rate stabilization measures that (i) capped rate Over the last several years, the energy, markets have been increases by BGE for residential SOS service at 15%

highly volatile with significant changes in natural gas, power, oil, from July 1, 2006 to May 31, 2007, (ii) gave residential coal, and emission allowance prices. The volatility of the energy SOS customers the option from June 1, 2007 until markets impacts our credit portfolio, and we continue to actively December 31, 2007 of paying a full market rate or manage our credit portfolio to attempt to reduce the impact of a choosing a short term rate stabilization plan in order to potential counterparty default. We discuss our customer provide a smooth transition to market rates without (counterparty) credit and other risks in more detail in the adversely affecting the creditworthiness of BGE, and Market Risk section. (iii) provided for full market rates for all residential SOS In addition; the volatility of the energy markets impacts our service starting January 1, 2008; liquidity and collateral requirements. We discuss our liquidity in

• allowed BGE to recover the costs deferred from July 1, the FinancialCondition section. 2006 to May 31, 2007 from its customers over a period not to exceed 10 years, on terms and conditions to be Competition determined by the Maryland PSC, including through We face competition in the sale of electricity, natural gas, and the issuance of rate stabilization bonds that securitize coal in wholesale energy markets and to retail customers. the deferred costs; and Various states have moved to restructure their retail " required BGE to reduce residential electric rates by electricity and gas markets. The pace of d&regulation in these approximately $39 million per year for 10 years, states varies based on historical moves to competition and beginning January 1, 2007, through suspension of the responses to recent market events. While many states continue collection of the residential return component of the to support or expand retail competition and industry administrative charge for SOS service through May 31, restructuring, other states that were considering deregulation 2007 and by providing to all residential electric have slowed their plans or postponed consideration. In addition, customers a credit equal to the amounts collected from other states are reconsidering deregulation.. all BGE customers for the nuclear decommissioning Specifically, legislatures in a number of states are trust for Calvert Cliffs. We provide further details in considering, to varying degrees, legislation currently to either Item 1. Business-Costfir Decommissioning Nuclear eliminate or expand retail choice programs. In addition, many Facilities section and in Item 7. Management's Discussion states have initiated proceedings to reconsider the method of and Analysis-Regulated Electric Business-Senate Bill 1 wholesale procurement for meeting their utilities' default/ Credits section.

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In connection with these provisions of Senate Bill 1: decommissioning funds and consider legislation that would

" In May 2007, the Maryland PSC approved a plan to provide the Maryland PSC with the authority to consider allow residential electric customers to defer the transition reallocation of the liability for nuclear decommissioning among to full market rates from June 1, 2007 to January 1, Constellation Energy, BGE and customers or to otherwise order 2008. The 4 percent of customers who chose to defer relief for customers. Similarly, the interim report also will repay the deferred amounts over a twenty-one month recommended that the Maryland legislature consider legislation period starting April 1, 2008 without interest. to order relief for customers depending on the outcome of the

" In June 2007, a subsidiary of BGE issued an aggregate Maryland PSC's stranded cost proceeding.

principal amount of $623.2 million of rate stabilization The Maryland PSC is required to issue a final report in bonds to recover costs relating to the residential rate December 2008. We cannot at this time predict the ultimate deferral from July 1, 2006 to May 31, 2007. We discuss outcome of these inquiries, studies, and recommendations or the rate stabilization bond issuance in more detail in their actual effect on our, or BGE's financial results, but it could Note 9. be material. In addition, one or more parties may challenge in

" In June 2007, the Maryland PSC required BGE to court one or more provisions of Senate Bills 1 and 400. The reinstate collection of the residential return component outcome of any challenges and the uncertainty that could result of the POLR administration charge in POLR rates and cannot be predicted.

to provide all residential electric customers a credit for We discuss the market risk of our regulated electric business the residential return component of the administrative in more detail in the Market Risk section.

charge.

In connection with implementing the approximately Base Rates

$39 million in credits to residential electric customers discussed Base rates are the rates the Maryland PSC allows BGE to charge above, BGE and Calvert Cliffs had notified the Maryland PSC its customers for the cost of providing them delivery service, that they had entered into a standstill agreement with the plus a profit. BGE has both electric base rates and gas base rates.

Attorney General of the State of Maryland with respect to Higher electric base rates apply during the summer when the potential challenges to the provisions of Senate Bill 1 relating to demand for electricity is higher. Gas base rates are not affected the credits. In January 2008, BGE and Calvert Cliffs provided by seasonal changes.

the Attorney General with notice of their termination of the BGE may ask the Maryland PSC to increase- base rates standstill agreement and their intent to file a federal action to from time to time. In 2008, BGE plans to file a combination enforce their rights under the 1999 Maryland electric electric and gas base rate case. The Maryland PSC historically deregulation settlement and to challenge the constitutionality of has allowed BGE to increase base rates to recover its utility plant the residential customer credits set forth in Senate Bill 1. We investment and operating costs, plus a profit. Generally, rate may incur significant costs to litigate this action and we cannot increases improve the earnings of our regulated business because provide any assurances that it will be resolved in our favor. If the they allow us to collect more revenue. However, rate increases action is resolved in a manner adverse to us, which may include are normally granted based on historical data and those increases a court determining that Senate Bill 1 appropriately required the may not always keep pace with increasing costs. Other parties residential rate credits or overturning aspects of the 1999 electric may petition the Maryland PSC to decrease base rates.

deregulation settlement, the impact on our, or BGE's, financial BGE's most recently approved return on electric results could be material. distribution rate base was 9.4% (approved in 1993). BGE's most Further, in April 2007, Senate Bill 400 was enacted, which recently approved return on gas rate base was 8.49% (approved made certain modifications to Senate Bill 1. Pursuant to Senate in 2005).

Bill 400, the Maryland PSC was required to initiate several In December 2005, the Maryland PSC issued an order studies, including studies relating to stranded costs, the costs and granting BGE a $35.6 million annual increase in its gas base benefits of various options for reregulation; and the structure of rates. In December 2006, the Baltimore City Circuit Court the electric industry in Maryland. In addition, the Maryland upheld the rate order. However, certain parties have filed an PSC has indicated that they are studying the relationship appeal with the Court of Special Appeals. We cannot provide between Constellation Energy and BGE. assurance that the Maryland PSC's order will not be reversed in In December 2007, the Maryland PSC issued an interim whole or part or that certain issues will not be remanded to the report addressing the costs and benefits of various options for Maryland PSC for reconsideration.

reregulation and recommending actions to be taken to address an anticipated shortage of generation and transmission capacity Revenue Decoupling in Maryland, which included implementation of demand Beginning in 2008, BGE will record a monthly adjustment to response initiatives and requiring utilities to enter into long-term its electric distribution revenues from residential and small power purchase contracts with suppliers. commercial customers to eliminate the effect of abnormal In January 2008, the Maryland PSC issued another interim weather and usage patterns per customer on its electric report that indicated that the Maryland PSC would initiate distribution volumes in accordance with Maryland PSC proceedings into payments made by BGE customers for stranded requirements. This means that BGE's monthly electric costs resulting from BGE's transfer of generation assets to certain distribution revenues from residential and small commercial Constellation Energy affiliates in connection with deregulation customers will be based on weather and usage that is considered and into Constellation Energy's management of its nuclear normal for the month. Therefore, these revenues are affected by decommissioning funds. This interim report also recommended customer growth and will not be affected by actual weather or that the Maryland legislature enact legislation to provide the usage conditions. We have a similar revenue decoupling Maryland PSC with the authority to regulate nuclear mechanism in our gas business.

33

DemandResponse and Advanced Metering Programs be used to determine the extent to which companies may have In order to implement advanced metering and demand response market power in certain regions. Where market power is found programs, BGE will defer costs associated with these programs as to exist, FERC may require companies to implement measures a regulatory asset and recover these costs from customers in to mitigate the market power in order to maintain market-based future periods. We discuss the advanced metering and demand rate authority. We believe that our entities selling wholesale response programs in more detail in Item 1. Business-Baltimore power continue to satisfy FERC's test for determining whether Gas and Electric Company-Electric Load Management. to grant a public utility market-based rate authority.

In November 2004, FERC eliminated through and out Electric Commodity and Transmission Charges transmission rates between the Midwest Independent System BGE electric commodity and transmission charges (standard Operator (MISO) and PJM and put in place Seams Elimination offer service), including the impact of the enactment of Senate Charge/Cost Adjustment/Assignment (SECA) transition rates, Bill 1 in Maryland, are discussed in Business Environment- which are paid by the transmission customers of MISO and Regulation-Maryland--SenateBills I and 400 section. PJM and allocated among the various transmission owners in PJM and MISO. The SECA transition rates were in effect from Gas Commodity Charge December 1, 2004 through March 31, 2006. FERC set for BGE charges its gas customers separately for the natural gas they hearing the various compliance filings that established the level purchase. The price BGE charges for the natural gas is based on of the SECA rates and has indicated that the SECA rates are a market-based rates incentive mechanism approved by the being recovered from the MISO and PJM transmission Maryland PSC. We discuss market-based rates in more detail in customers subject to refund by the MISO and PJM transmission the Regulated Gas Business-Gas Cost Adjustments section and in owners.

Note 6 We are a recipient of SECA payments, payer of SECA charges, and supplier to whom such charges may be shifted.

Federal Regulation Administrative hearings regarding the SECA charges concluded FERC in May 2006, and an initial decision from the FERC The FERC has jurisdiction over various aspects of our business, administrative law judge (ALJ) was issued in August 2006. The including electric transmission and wholesale natural gas and decision of the ALJ generally found in favor of reducing the electricity sales. BGE transmission rates are updated annually overall SECA liability. The decision, if upheld, is expected to based on a formula methodology approved by FERC. The rates significantly reduce the overall SECA liability at issue in this also include transmission investment incentives approved by proceeding. However, the ALJ also allowed SECA charges to be FERC in orders issued in July and November of 2007. We shifted to upstream suppliers, subject to certain adjustments.

believe that FERC's continued commitment to fair and efficient Therefore, certain charges could be shifted to our wholesale wholesale energy markets should continue 'to result in marketing, risk management, and trading operation. This improvements to competitive markets across various regions. decision will be reviewed by FERC. We are unable to predict the Since 1997, operation of BGE's transmission system has timing or final outcome of FERC's SECA rate proceeding.

been under the authority of PJM Interconnection (PJM), the However, as the amounts collected under the SECA rates are Regional Transmission Organization (RTO) for the Mid-Atlantic subject to refund and the ultimate outcome of the proceeding region, pursuant to FERC oversight. As the transmission establishing SECA rates is uncertain, the result of this operator, PJM operates the energy markets and conducts proceeding may have a material effect on our financial results.

day-to-day operations of the bulk power system. The liability of In April 2006, FERC issued an initial order approving transmission owners,. including BGE, and power generators is PJM's proposal to restructure its capacity market, which limited to those damages caused by the gross negligence of such establishes the method by which we are paid for making entities. generating plant capacity available to PJM. The capacity market In addition to PJM, RTOs exist in other regions of the or Reliability Pricing Model (RPM) was approved by FERC in country such as the Midwest, New York, and New England. In December 2006 after settlement proceedings. FERC in June and addition to operation of theltransmission system and November 2007 upheld the RPM settlement in response to responsibility for transmission system reliability, these RTOs also requests for rehearing. An appeal of FERC's decisions on RPM operate energy markets for their region pursuant to FERC's was filed in January 2008 in the United States Court of Appeals oversight. Our merchant energy business participates in these for the District of Columbia Circuit. Currently, we cannot regional energy markets. These markets are continuing to predict with certainty what effect the results of these challenges develop, and revisions to market structure are subject to review will have on our, or BGE's, financial results.

and approval by FERC. We cannot predict the outcome of any Also in January 2008 in connection with RPM, PJM filed reviews at this time. However, changes to the structure of these revisions to its capacity market rules to reflect increased markets could have a material effect on our financial results. construction costs for new entry of generation (CONE). CONE Ongoing initiatives at FERC have included a review of its is used in determining the price paid to capacity resources that methodology for the granting of market-based rate authority to clear in the PJM capacity auction. The outcome of this pending sellers of electricity. FERC has established interim tests that will filing at FERC is uncertain, but it could have a material effect on our financial results.

34

Three major, high-voltage transmission lines have been " location of our generating facilities relative to the announced that could enhance significantly the transfer capacity location of our load-serving obligations, of the PJM transmission system from west to east. The siting

• implementation of new market rules governing process either in the states or at FERC is uncertain, as is the operations of regional power pools, likelihood that one or more of the transmission lines will be

• procedures used to maintain the integrity of the physical ultimately constructed. The construction of the transmission electricity system during extreme conditions, lines, which could depress both capacity and energy prices for " changes in the nature and extent of federal and state generation located in Maryland and elsewhere in the eastern part regulations, and of PJM, could have a material effect on our financial results. " international supply and demand.

Other market changes are routinely proposed and These factors can affect energy commodity and derivative considered on an ongoing basis. Such changes will be subject to prices in different ways and to different degrees. These effects FERC's review and approval. We cannot predict the outcome of may vary throughout the country as a result of regional these proceedings or the possible effect on our, or BCE's, differences in:

Financial results at this time.

• weather conditions,

• market liquidity, Weather " capability and reliability of the physical electricity and Merchant Energy Business gas systems, Weather conditions in the different regions of North America

• local transportation systems, and influence the financial results of our merchant energy business. " the nature and extent of electricity deregulation.

Weather conditions can affect the supply of and demand for Other factors also impact the demand for electricity and gas electricity, gas, and fuels. Changes in energy supply and demand in our regulated businesses. These factors include the number of may impact the price of these energy commodities in both the customers and usage per customer during a given period. We use spot market and the forward market, which may affect our these terms later in our discussions of regulated electric and gas results in any given period. Typically, demand for electricity and operations. In those sections, we discuss how these and other its price are higher in the summer and the winter, when weather factors affected electric and gas sales during the periods is more extreme. The demand for and price of natural gas and presented.

oil are higher in the winter. However, all regions of North The number of customers in a given period is affected by America typically do not experience extreme weather conditions new home and apartment construction and by the number of at the same time, thus we are not typically exposed to the effects businesses in our service territory.

of extreme weather in all parts of our business at once. Usage per customer refers to all other items impacting customer sales that cannot be measured separately. These factors BGE include the strength of the economy in our service territory.

Weather affects the demand for electricity and gas for our When the economy is healthy and expanding, customers tend to regulated businesses. Very hot summers and very cold winters consume more electricity and gas. Conversely, during an increase demand. Mild weather reduces demand. Weather affects economic downturn, our customers tend to consume less residential sales more than commercial and industrial sales, electricity and gas.

which are mostly affected by business needs for electricity and gas. The Maryland PSC has approved reve'nue decoupling Environmental Matters and Legal Proceedings mechanisms which allow BCE to record monthly adjustments to We discuss details of our environmental matters in Note 12 and our regulated electric and gas business distribution revenues to Item 1. Business-EnvironmentalMatters section. We discuss eliminate the effect of abnormal weather and usage patterns. We details of our legal proceedings in Note 12. Some of this discuss this further in the Regulation-MarylandPSC-Revenue information is about costs that may be material to our financial Decoupling and Regulated Gas Business-Gas Revenue Decoupling results.

sections.

Accounting Standards Adopted and Issued Other Factors We discuss recently adopted and issued accounting standards in A number of other factors significantly influence the level and Note 1.

volatility of prices for energy commodities and related derivative products for our merchant energy business. These factors Critical Accounting Policies include: Our discussion and analysis of financial condition and results of

• seasonal, daily, and hourly changes in demand, operations is based on our consolidated financial statements that

" number of market participants, were prepared in accordance with accounting principles generally

" extreme peak demands, accepted in the United States of America. Management makes

" available supply resources, estimates and assumptions when preparing financial statements.

" transportation and transmission availability and reliability within and between regions, 35

These estimates and assumptions affect various matters, ongoing compliance with specific, detailed documentation and including: other requirements that may be unrelated to the economics of

" our reported amounts of revenues and expenses in our the transactions or how the associated risks are managed. While Consolidated Statements of Income, we believe we have appropriate controls in place to comply with

" our reported amounts of assets and liabilities in our these requirements, the failure to meet all of those requirements, Consolidated Balance Sheets, and even inadvertently, may result in disqualifying the use of these

• our disclosure of contingent assets and liabilities. accounting treatments for those transactions for any affected These estimates involve judgments with respect to period until all such requirements are satisfied.

numerous factors that are difficult to predict and are beyond The exercise of management's judgment in using cash-flow management's control. As a result, actual amounts could hedge accounting or electing the normal purchase and sale materially differ from these estimates. exception versus mark-to-market accounting, including Management believes the following accounting policies compliance with all of the associated qualification and represent critical accounting policies as defined by the Securities documentation requirements, materially impacts our financial and Exchange Commission (SEC). The SEC defines critical results with respect to timing of the recognition of earnings. In accounting policies as those that are both most important to the addition, interpretations of SFAS No. 133 could continue to portrayal of a company's financial condition and results of evolve. If there is a future change in interpretation or a failure to operations and require management's most difficult, subjective, meet the qualification and documentation requirements, or complex judgment, often as a result of the need to make contracts that currently are excluded from the provisions of estimates about the effect of matters that are inherently SFAS No. 133 under the normal purchase and normal sale uncertain and may change in subsequent periods. We discuss our exception or for which changes in fair value are recorded in significant accounting policies, including those that do not other comprehensive income under cash-flow hedge accounting require management to make difficult, subjective, or complex could be deemed to no longer qualify for those accounting judgments or estimates, in Note 1. treatments. If that were to occur, normal purchase and normal sale contracts could be required to be recorded on the balance Accounting for Derivatives sheet at fair value with changes in value recorded in the income Our merchant energy business originates and acquires contracts statement, and changes in value of derivatives previously for energy, other energy-related commodities, and related designated as cash-flow hedges could be required to be recorded derivatives. We record merchant energy business revenues using in the income statement rather than in other comprehensive two methods of accounting: accrual accounting and income.

mark-to-market accounting. The accounting requirements for We record revenues and fuel and purchased energy expenses derivatives are governed by Statement of Financial Accounting from the sale or purchase of energy, energy-related products, and Standard (SFAS) No. 133, Accountingfor Derivative Instruments energy services under the accrual method of accounting in the and Hedging Activities, as amended, and applying those period when we deliver or receive energy commodities, products, requirements involves the exercise of judgment in evaluating and services, or settle contracts. We use accrual accounting for these provisions, as well as related implementation guidance and our merchant energy and other nonregulated business applying those requirements to complex contracts in a variety of transactions, including the generation or purchase and sale of commodities and markets. We record all derivatives subject to electricity, gas, and coal as part of our physical delivery activities the accounting requirements of SFAS No. 133 as "Derivative and for power, gas, and coal sales contracts that are not subject assets or liabilities" in our Consolidated Balance Sheets. Within to mark-to-market accounting. Contracts that are eligible for derivative assets and liabilities, we include 'derivative contracts accrual accounting include non-derivative transactions and subject to mark-to-market accounting and derivative contracts derivatives that qualify for and are designated as normal that qualify for designation as hedges under SFAS No. 133. purchases and normal sales of commodities that will be Many fundamental customer contracts in our business, such physically delivered. While we generally elect accrual accounting as those associated with our load-serving activities, must be whenever permitted, we sometimes use mark-to-market accounted for on an accrual basis. We majs economically hedge accounting for physical delivery activities that are managed using these contracts with derivatives and elect cash-flow hedge economic hedges that do not qualify for accrual accounting.

accounting or apply the normal purchase and normal sale The use of accrual accounting requires us to analyze exception in order to match more closely the timing of the contracts to determine whether they are non-derivatives or, if recognition of earnings from these transactions. We make these they are derivatives, whether they meet the requirements for elections because we believe that accrual accounting provides the designation as normal purchases and normal sales. For those most transparent presentation to our shareholders of these derivative contracts that do not meet these criteria, we may also business activities. If our commercial transactions or related analyze whether they qualify for hedge accounting, including hedges meet the definition of a derivative, we must comply with performing an evaluation of historical forward market price the provisions of SFAS No. 133 in order to use cash-flow hedge information to determine whether such contracts are expected to accounting or the normal purchase and normal sale exception. be highly effective in offsetting changes in cash flows from the Qualifying for either of these accounting treatments requires risk being hedged.

36

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We use the mark-to-market method of accounting for No. 157 on January 1, 2008, to the extent that we are derivative contracts for which we do not elect to use accrual not able to obtain observable market information for accounting or hedge accounting. These mark-to-market activities similar contracts, the close-out adjustment is equivalent include derivative contracts for energy and other energy-related to the initial contract margin, thereby resulting in no commodities. Under the mark-to-market method of accounting, gain or loss at inception. In the absence of observable we record the fair value of these derivatives as assets and market information, there is a presumption that the liabilities at the time of contract execution. We record the transaction price is equal to the market value of the changes in these derivative assets and liabilities in our contract, and therefore we do not recognize a gain or Consolidated Statements of Income. loss at inception. We recognize such gains or losses in Derivative assets and liabilities accounted for under the earnings as we realize cash flows under the contract or mark-to-market method of accounting consist of a combination when observable market data becomes available.

of energy and energy-related derivative contracts. While some of

• Unobservable input valuation adjustment-upon these contracts represent commodities or instruments for which adoption of SFAS No. 157, this adjustment is necessary prices are available from external sources, other commodities and when we are required to determine fair value for certain contracts are not actively traded and are valued using derivative positions using internally developed models modeling techniques to determine expected future market prices, that use unobservable inputs due to the absence of contract quantities, or both. The market prices and quantities observable market information. Unobservable inputs to used to determine fair value reflect management's best estimate fair value may arise due to a number of factors, considering various factors. However, future market prices and including but not limited to, the term of the actual quantities will vary from those used in recording the transaction, contract optionality, delivery location, or related derivative assets and liabilities, and it is possible that such product type. In the absence of observable market variations could be material. information that supports the model inputs, there is a We record valuation adjustments to reflect uncertainties presumption that the transaction price is equal to the associated with certain estimates inherent in the determination market value of the contract when we transact in our of the fair value of these derivative assets and liabilities. The principal market and SFAS No. 157 requires us to effect of these uncertainties is not incorporated in market price recalibrate our estimate of fair value to equal the information or other market-based estimates used to determine transaction price. Therefore we do not recognize a gain fair value of our mark-to-market energy contracts. To the extent or loss at contract inception on these transactions. We possible, we utilize market-based data together with quantitative will recognize such gains or losses in earnings as we methods for both measuring the uncertainties for which we realize cash flows under the contract or when observable record valuation adjustments and determining the level of such market data becomes available.

adjustments and changes in those levels. " Credit-spread adjustment-for risk management We describe below the main types of valuation adjustments purposes, we compute the value of our derivative assets we record and the process for establishing each. Generally, and liabilities using a risk-free discount rate. In order to increases in valuation adjustments reduce our earnings, and compute fair value for financial reporting purposes, we decreases in valuation adjustments increase our earnings. adjust the value of our derivative assets to reflect the However, all or a portion of the effect on earnings of changes in credit-worthiness of each counterparty based upon either valuation adjustments may be offset by changes in the value of published credit ratings, or equivalent internal credit the underlying positions. As discussed below and more fully in ratings and associated default probability percentages.

Note 1, our valuation adjustments will be affected by the We compute this adjustment by applying a default adoption of SFAS No. 157, Fair Value Measurements, in 2008. probability percentage to our outstanding credit

• Close-out adjustment-represents the estimated cost to exposure, net of collateral, for each counterparty. The close out or sell to a third-party open mark-to-market level of this adjustment increases as our credit exposure positions. This valuation adjustment has the effect of to counterparties increases, the maturity terms of our valuing "long" positions (the purchase of a commodity) transactions increase, or the credit ratings of our at the bid price and "short" positions (the sale of a counterparties deteriorate, and it decreases when our commodity) at the offer price. We compute this credit exposure to counterparties decreases, the maturity adjustment using a market-based estimate of the bid/ terms of our transactions decrease, or the credit ratings offer spreadfor each commodity and option price and of our counterparties improve. Upon adoption of SFAS the absolute quantity of our net open positions for each No. 157, we will also use a credit-spread adjustment in year. The ievel of total close-out valuation adjustments order to reflect our own credit risk in determining the increases as we have larger unhedged positions, bid-offer fair value of our derivative liabilities.

spreads increase, or market information is not available, Market prices for energy and energy-related commodities and it decreases as we reduce our unhedged positions, vary based upon a number of factors, and changes in market bid-offer spreads decrease, or market information prices affect both the recorded fair value of our mark-to-market becomes available. Prior to the adoption of SFAS energy contracts and the level of future revenues and costs 37

associated with accrual-basis activities. Changes in the value of be sold or disposed of before the end of its previously our mark-to-market energy contracts will affect our earnings in estimated useful life.

the period of the change, while changes in forward market prices For long-lived assets that are expected to be held and used, related to accrual-basis revenues and costs will affect our earnings SFAS No. 144 provides that an impairment loss shall only be in future periods to the extent those prices are realized. We recognized if the carrying amount of an asset is not recoverable cannot predict whether, or to what extent, the factors affecting and exceeds its fair value. The carrying amount of an asset is market prices may change, but those changes could be material not recoverable under SFAS No. 144 if the carrying amount and could affect us either favorably or unfavorably. We discuss exceeds the sum of the undiscounted future cash flows expected our market risk in more detail in the Market Risk section. to result from the use and eventual disposition of the asset.

The impact of derivative contracts on our revenues and Therefore, when we believe an impairment condition may have costs is material and is affected by many factors, including: occurred, we are required to estimate the undiscounted future

" our ability to continue to designate and qualify cash flows associated with a long-lived asset or group of derivative contracts for normal purchase and normal sale long-lived assets at the lowest level for which identifiable cash accounting or, hedge accounting under the requirements flows are largely independent of the cash flows of other assets of SFAS No. 133, as amended and as interpreted in and liabilities. This necessarily requires us to estimate uncertain supplemental guidance, future cash flows.

" potential volatility in earnings from ineffectiveness In order to estimate future cash flows, we consider associated with derivatives subject to hedge accounting, historical cash flows and changes in the market environment and

" potential volatility in earnings from derivative contracts other factors that may affect future cash flows. To the extent that serve as economic hedges for which we do not elect applicable, the assumptions we use are consistent with forecasts or do not meet the accounting requirements to qualify that we are otherwise required to make (for example, in for normal purchase and normal sale accounting or preparing our other earnings forecasts). If we are considering hedge accounting, alternative courses of action to recover the carrying amount of a

" our ability to enter into new mark-to-market derivative long-lived asset (such as the potential sale of an asset), we origination transactions, and probability-weight the alternative courses of action to estimate

" sufficient liquidity and transparency in the energy the cash flows.

markets to permit us to record gains at inception of new We use our best estimates in making these evaluations and derivative contracts because fair value is evidenced by consider various factors, including forward price curves for quoted market prices, current market transactions, or energy, fuel costs, and operating costs. However, actual future other observable market information. market prices and project costs could vary from the assumptions used in our estimates, and the impact of such variations could Evaluation of Assets for Impairment and Other Than be material.

Temporary Decline in Value For long-lived assets that can be classified as assets held for Long-Lived Assets sale under SFAS No. 144, an impairment loss is recognized to We are required to evaluate certain assets that have long lives the extent their carrying amount exceeds their fair value less (for example, generating property and equipment and real estate) costs to sell.

to determine if they are impaired when certain conditions exist. If we determine that the undiscounted cash flows from an SFAS No. 144, Accountingfor the Impairment or Disposal of asset to be held and used are less than the carrying amount of Long-Lived Assets, provides the accounting requirements for the asset, or if we have classified an asset as held for sale, we impairments of long-lived assets. We are required to test our must estimate fair value to determine the amount of any long-lived assets for recoverability whenever events or changes in impairment loss. The estimation of fair value under SFAS circumstances indicate that their carrying amount may not be No. 144, whether in conjunction with an asset to be held and recoverable. Examples of such events or changes are: used or with an asset held for sale, also involves judgment. We

" a significant decrease in the market price of a long-lived consider quoted market prices in active markets to the extent asset, they are available. In the absence of such information, we may

" a significant adverse change in the manner an asset is consider prices of similar assets, consult with brokers, or employ being used or its physical condition, other valuation techniques. Often, we will discount the

" an adverse action by a regulator or legislature or an estimated future cash flows associated with the asset using a adverse change in the business climate, single interest rate that is commensurate with the risk involved

" an accumulation of costs significantly in excess of the with such an investment or employ an expected present value amount originally expected for the construction or method that probability-weights a range of possible outcomes.

acquisition of an asset, The use of these methods involves the same inherent uncertainty

" a current-period loss combined with a history of losses of future cash flows as discussed above with respect to or the projection of future losses, or undiscounted cash flows. Actual future market prices and project

• a change in our intent about an asset from an intent to costs could vary from those used in our estimates, and the hold to a greater than 50% likelihood that an asset will impact of such variations could be material.

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We are also required to evaluate our equity-method and events and circumstances indicate the business might be cost-method investments (for example, in partnerships that own impaired. Goodwill is impaired if the carrying value of the power projects) to determine whether or not they are impaired. business exceeds fair value. Annually, we estimate the fair value Accounting Principles Board (APB) Opinion No. 18, The Equity of the businesses we have acquired using techniques similar to Method of Accountingfor Investments in Common Stock, provides those used to estimate future cash flows for long-lived assets as the accounting requirements for these investments. The standard discussed on the previous page, wi.hich involves judgment. If the for determining whether an impairment must be recorded under estimated fair value of the business is less than its carrying value, APB No. 18 is whether the investment has experienced a loss in an impairment loss is required to be recognized to the extent value that is considered an 'other than a temporary"' decline in that the carrying value of goodwill is greater than its fair value.

value.

The evaluation and measurement of impairments under the Asset Retirement Obligations APB No. 18 standard involves the same uncertainties as We incur legal obligations associated with the retirement of described above for long-lived assets that we own directly and certain long-lived assets. SFAS No. 143, Accounting for Asset account for in accordance with SFAS No. 144. Similarly, the Retirement Obligations, provides the accounting for legal estimates that we make with respect to our equity and obligations associated with the retirement of long-lived assets.

cost-method investments are subject to variation, and the impact We incur such legal obligations as a result of environmental and of such variations could be material. Additionally, if the projects other government regulations, contractual agreements, and other in which we hold these investments recognize an impairment factors. The application of this standard requires significant under the provisions of SFAS No. 144, we would record our judgment due to the large number and diverse nature of the proportionate share of that impairment loss and would evaluate assets in our various businesses and the estimation of future cash our investment for an other than temporary decline in value flows required to measure legal obligations associated with the under APB No. 18. retirement of specific assets. FASB Interpretation (FIN) 47, Accounting for ConditionalAsset Retirement Obligations-an Gas Properties interpretation of FASB Statement No. 143, clarifies that We evaluate unproved property at least annually to determine if obligations that are conditional upon a future event are subject it is impaired under SFAS No. 19, FinancialAccounting and to the provisions of SFAS No. 143.

Reporting by Oil and Gas ProducingProperties. Impairment for SFAS No. 143 requires the use of an expected present value unproved property occurs if there are no firm plans to continue methodology in measuring asset retirement obligations that drilling, lease expiration is at risk, or historical experience involves judgment surrounding the inherent uncertainty of the necessitates a valuation allowance. probability, amount and timing of payments to settle these obligations, and the appropriate interest rates to discount future Debt and Equity Securities cash flows. We use our best estimates in identifying and Our investments in debt and equity securities, primarily our measuring our asset retirement obligations in accordance with nuclear decommissioning trust fund assets, are subject to SFAS No. 143.

impairment evaluations under FASB Staff Positions SFAS 115-1 Our nuclear decommissioning costs represent our largest and SFAS 124-1 (FSP 115-1 and 124- 1), The Meaning of asset retirement obligation. This obligation primarily results from Other-Than-Temporary Impairment and Its Application to Certain the requirement to decommission and decontaminate our Investments. FSP 115-1 and 124-1 require us to determine nuclear generating facilities in connection with their future whether a decline in fair value of an investment below book retirement. We utilize site-specific decommissioning cost value is other than temporary. If we determine that the decline estimates to determine our nuclear asset retirement obligations.

in fair value is judged to be other than temporary, the cost basis However, given the magnitude of the amounts involved, of the investment must be written down to fair value as a new complicated and ever-changing technical and regulatory cost basis. For securities held in our nuclear decommissioning requirements, and the long time horizons involved, the actual trust fund for which the market value is below book value, the obligation could vary from the assumptions used in our decline in fair value for these securities is considered other than estimates, and the impact of such variations could be material.

temporary and must be written down to fair value. In view of the significant number of assumptions underlying the decommissioning cost estimate, our estimate of Goodwill the future cost of decommissioning is likely to continue to Goodwill is the excess of the purchase price of an acquired change over time. For perspective, a 10% increase or decrease in business over the fair value of the net assets acquired. We our estimate of the future cost of decommissioning would account for goodwill and other intangibles under the provisions produce an approximately $80 million change to our asset of SFAS No. 142, Goodwill and Other Intangible Assets. We do retirement obligation and an approximately $10 million change not amortize goodwill. SFAS No. 142 requires us to evaluate in our total annual amortization and accretion expenses.

goodwill for impairment at least annually or more frequently if 39

Significant Events Electricite de France Joint Venture Common Share Repurchase Program In August 2007, we formed a joint venture, UniStar Nuclear In October 2007, our board of directors approved a common Energy, LLC (UNE) with an affiliate of Electricite de France, SA share repurchase program for up to $1 billion of our (EDF). We discuss this joint venture in more detail in Note 4.

outstanding common stock. We discuss this common share repurchase program in more detail in Note 9. Rate Stabilization Bonds In 2007, BGE formed a special purpose bankruptcy-remote Dividend Increase limited liability company to purchase rate stabilization property In January 2008, we announced an increase in our quarterly from BGE and to issue rate stabilization bonds. We discuss this dividend to $0.4775 per share on our common stock. This is entity and the related financing in more detail in Note 4 and equivalent to an annual rate of $1.91 per share. Previously, our Note 9.

quarterly dividend on our common stock was $0.435 per share, equivalent to an annual rate of $1.74 per share. Synthetic Fuel Facilities Our merchant energy business has investments in facilities that CEP manufacture solid synthetic fuel produced from coal as defined CEP, a limited liability company formed in 2006 by under the Internal Revenue Code (IRC) for which we can claim Constellation Energy, issued additional eqdiity to the public in tax credits on our Federal income tax return through 2007. The 2007. As a result, in the second quarter of 2007, our ownership IRC provides for a phase-out of synthetic fuel tax credits if percentage in CEP fell below 50 percent, and we deconsolidated average annual wellhead oil prices increase above certain levels.

CEP and began accounting for our investment using the equity For 2007, we estimate the tax credit reduction would begin if method of accounting. the reference price exceeds approximately $56 per barrel and We discuss the issuances of CEP's equity and their impact would be fully phased-out if the reference price exceeds on our financial results in more detail in Note 2. approximately $71 per barrel. Based on monthly EIA published wellhead oil prices for the ten months ended October 31, 2007 Acquisitions and November and December NYMEX prices for light, sweet, During 2007, we acquired working interests in gas and oil crude oil (adjusted for the 2007 difference between EIA and producing fields, and an entity that expanded our retail NYMEX prices), we estimate a 70% tax credit phase-out in competitive supply operations. In February 2008, we acquired a 2007. We recorded the effect of this phase-out estimate as a partially completed 774 MW gas-fired combined-cycle power reduction in tax credits of $110.3 million during 2007. We generation facility located in Alabama. We discuss these discuss how we determine the amount of phase-out in more acquisitions in more detail in the Note 15.' detail in Note 10.

We also acquired a portfolio of energy contracts during 2007. We discuss these energy contracts in more detail in the FinancialCondition section.

Shipping Joint Venture During 2007, we made cash contributions totaling $57 million to a shipping joint venture in which we have a 50% ownership interest. We discuss this joint venture in more detail in Note 4.

40

Results of Operations " We had lower earnings of $9.3 million after-tax at our In this section, we discuss our earnings and the factors affecting retail competitive supply operation due primarily to them. We begin with a general overview, and then separately higher operating expenses, partially offset by higher gross discuss earnings for our operating segments. Significant changes margin. We discuss our retail gross margin in more in other income and expense, fixed charges, and income taxes detail in the Competitive Supply section.

are discussed in the aggregate for all segments in the " We had lower earnings due to a $12.2 million after-tax ConsolidatedNonoperating Income and Expenses section. charge related to a cancelled wind development project.

We discuss this charge in more detail in Note 2.

Overview " We had lower earnings of approximately $6 million Results after-tax at our wholesale competitive supply operation 2007 2006 2005 due to higher expenses and the absence of income from

. (In millions, after-tax) our gas plants that were sold in December 2006, mostly Merchant energy $679.2 $580.1 $359.4 offset by higher gross margin. We discuss our Regulated electric ,97.9 120.2 149.4 mark-to-market and wholesale accrual results in more Regulated gas ,28.8 37.0 26.7 detail in the Competitive Supply section.

Other nonregulated 16.5 11.3 0.4 These decreases were partially offset by the following:

Income from continuing operations and " We had higher earnings of approximately $98 million before cumulative effects of changes in after-tax at our merchant energy business due to higher accounting principles 822.4 748.6 535.9 gross margin from the Mid-Atlantic Region. We discuss (Loss) income from discontinued this increase in gross margin in more detail in the operations (0.9) 187.8 94.4 Mid-Atlantic Region section.

Cumulative effects of changes in " We had higher earnings of approximately $70 million accounting principles - - (7.2) after-tax from an increase in other income mostly due to Net Income $821.5 $936.4 $623.1 interest income resulting from a higher cash balance Other Irems Included in Operations (after-tax) primarily from proceeds from the sale of gas-fired plants in Gain on sale of gas-fired plants $ - $ 47.1 $ - December 2006, and lower fixed charges due to the Non-qualifying hedges 2.0 39.2 (24.9) repayment of $600 million of long-term debt in April 2007.

Impairment losses and other costs (12.2) - - " We had higher earnings of approximately $21 million Workforce reduction costs (1.4) (17.0) (2.6) after-tax due to gains on the sales of equity by CEP. We Merger-related costs - (5.7) (15.6) discuss these sales in more detail in Note 2.

Total Other Items $ (11.6) $ 63.6 $ (43.1) " We had higher earnings of $15.6 million after-tax related to lower workforce reduction costs.

2007 " We had higher earnings of $5.7 million after-tax due to.

the absence of merger-related costs associated with our Our total net income for 2007 decreased $114.9 million, or

$0.66 per share, compared to 2006 mostly because of the cancelled merger with FPL Group.

following:

" We had lower earnings from discontinued operations of 2006

$188.7 million after-tax mostly due to the absence of Our total net income for 2006 increased $313.3 million, or the gain on sale of our High Desert facility in 2006. In $1.69 per share, compared to 2005 mostly because of the addition, we had lower earnings of $47.1 million following:

after-tax resulting from the recognition of a gain on sale " We had higher earnings of approximately $144 million of five other gas-fired generating facilities in 2006. We after-tax at our merchant energy business due to higher discuss the sale of these plants in more detail in Note 2. gross margin from the Mid-Atlantic Region. We discuss

" We had lower earnings of $34.0 million after-tax at our this increase in gross margin in more detail in the synthetic fuel processing facilities mostly due to a higher Mid-Atlantic Region section.

phase-out of tax credits. We discuss synthetic fuel tax " We had higher earnings from discontinued operations of credits in more detail in Note 10. $93.4 million after-tax mostly due to the gain on sale of

" We had lower earnings of $30.5 million after-tax at our our High Desert facility. In addition, we had higher regulated businesses primarily due to the impact of earnings of $47.1 million after-tax resulting from the residential credits required by Senate Bill 1 and higher recognition of a gain on sale of five other gas-fired operations and maintenance expenses. We discuss Senate generating facilities. We discuss the sale of these plants Bill 1 in more detail iii Business Environment-Regulaion-- in more detail in Note 2.

Maryland-Senate Bills I and 400 section.

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" We had higher wholesale competitive supply gross margin Our merchant energy business focuses on delivery of of approximately $105 million after-tax. This increase was physical, customer-oriented products to producers and partially offset by approximately $68 million after-tax of consumers, manages the risk and optimizes the value of our higher operating expenses mostly because of higher labor owned generation assets, and uses our portfolio management and and benefit costs due to the growth of our wholesale trading capabilities both to manage risk and to deploy risk competitive supply operation. We discuss our capital to generate additional returns. We continue to identify mark-to-market and wholesale accrual results in more detail and pursue opportunities which can generate additional returns in the Competitive Supply section. through portfolio management and trading activities within our

" We had higher earnings of $67.7 million after-tax at our business. These opportunities have increased due to the retail competitive supply operation primarily due to an significant growth in scale of our competitive supply operations.

increase in gross margin, partially offset by higher We record merchant energy revenues and expenses in our operating expenses to support the growth of this financial results in different periods depending upon which operation. We discuss our retail gross margin in more portion of our business they affect. We discuss our revenue detail in the Competitive Supply-Retail section. recognition policies in the CriticalAccounting Policies section and

" We had higher earnings of approximately $18 million in Note 1. We summarize our revenue and expense recognition after-tax due to the gain on the CEP initial public policies as follows:

offering. This gain was partially offset by cash-flow " We record revenues as they are earned and fuel and hedge losses of approximately $10 million after-tax purchased energy expenses as they are incurred for reclassified from "Accumulated other comprehensive contracts and activities subject to accrual accounting, income" to revenues as a result of the initial public including certain load-serving activities.

offering. We discuss the CEP transaction in more detail " Prior to the settlement of the forecasted transaction in Note 2. being hedged, we record changes in the fair value of

• We had higher earnings of $10.3 million after-tax from contracts designated as cash-flow hedges in other our regulated gas business primarily due to the favorable comprehensive income to the extent that the hedges are impact of the increase in gas base rates that was effective. We record the effective portion of the changes approved in December 2005. in fair value of hedges in earnings in the period the These increases were partially offset by the following: settlement of the hedged transaction occurs. We record

" We had lower earnings of $30.1 million after-tax at our the ineffective portion of the changes in fair value of synthetic fuel facilities mostly due to the expected hedges, if any, in earnings in the period in which the phase-out of tax credits as a result of the high price of change occurs.

oil. We discuss the phase-out of tax credits in more

• We record changes in the fair value of contracts that are detail in Note 10. subject to mark-to-market accounting in revenues or fuel

" We had lower earnings of $29.2 million after-tax from and purchased energy expenses in the period in which our regulated electric business primarily due to higher the change occurs.

operations and maintenance expenses and lower revenues Mark-to-market accounting requires us to make estimates less electricity purchased for resale expenses. and assumptions using judgment in determining the fair value of

" We had lower earnings of $14.4 million after-tax due to certain contracts and in recording revenues from those contracts.

workforce reduction costs associated with workforce We discuss the effects of mark-to-market accounting on our restructurings at our nuclear generating facilities. We results in the Competitive Supply-Mark-to-Market section. We discuss these costs in more detail in Note 2. discuss mark-to-market accounting and the accounting policies

" We had lower earnings of approximately $11 million for the merchant energy business further in the Critical after-tax due to higher fixed charges and lower other Accounting Policies section and in Note 1.

income. We discuss these items in more detail in the Our merchant energy business actively transacts in energy Consolidated NonoperatingIncome and Expenses section. and energy-related commodities in order to manage our portfolio of energy purchases and sales to customers through Merchant Energy Business structured transactions. As part of these activities we trade Background energy and energy-related commodities and deploy risk capital in Our merchant energy business is a competitive provider of the management of our portfolio in order to earn additional energy solutions for various customers. We discuss the impact of returns. These activities are managed through daily value at risk deregulation on our merchant energy business in Item 1. and stop loss limits and liquidity guidelines, and may have a Business-Competition section. material impact on our financial results. We discuss the impact of our trading activities and value at risk in more detail in the Competitive Supply-Mark-to-Market and Market Risk sections.

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Results The difference between revenues and fuel and purchased 2007 2006 2005 energy expenses, including all direct expenses, is the gross margin of (In millions) our merchant energy business, and this measure is a useful tool for Revenues $ 18,744.5 $ 17,166.2 $ 14,622.4 assessing the profitability of our merchant energy business.

Fuel and purchased energy Accordingly, we believe it is appropriate to discuss the operating expenses (15,501.8) (14,256.3) (12,301.8) results of our merchant energy business by analyzing the changes in Operating expenses (1,791.8) (1,549.4) (1,346.1) gross margin between periods. In managing our portfolio, we may Impairment losses and other costs (20.2) - -

terminate, restructure, or acquire contracts. Such transactions are Workforce reduction costs (2.3) (28.2) (4.4)

Merger-related costs - (13.1) (11.2) within the normal course of managing our portfolio and may Depreciation, depletion, and materially impact the timing of our recognition of revenues, fuel amortization (269.9) (258.7) (250.4) and purchased energy expenses, and cash flows.

Accretion of asset retirement We analyze our merchant energy gross margin in the obligations (68.3) (67.6) (62.0) following categories because of the risk profile of each category, Taxes other than income taxes (110.2) (120.0) (106.7) differences in the revenue sources, and the nature of fuel and Gain on sale of gas-fired plants - 73.8 -

purchased energy expenses. With the exception of a portion of Income from Operations $ 980.0 $ 946.7 $ 539.8 our competitive supply activities that we are required to account Income from continuing for using the mark-to-market method of accounting, all of these operations and before activities are accounted for on an accrual basis.

cumulative effects of changes in

• Mid-Atlantic Region-our fossil, nuclear, and hydroelectric accounting principles (after-tax) $ 679.2, $ 580.1 $ 359.4 generating facilities and load-serving activities in the PJM (Loss) Income from Interconnection (PJM) region. This also includes active discontinued operations portfolio management of the generating assets and other (after-tax) (0.9) 186.9 73.8 physical and financial contractual arrangements, as well as Cumulative effects of changes in accounting principles other PJM competitive supply activities. In addition, due to (after-tax) - - (7.4) the expiration of its power purchase agreement, beginning in June 2006 until its sale in December 2006, the results of Net Income $ 678.3 $ 767.0 $ 425.8 our University Park generating facility were induded in the Other Items Included in Operations Mid-Atlantic Region. University Park was previously (after-tax) included in Plants with Power Purchase Agreements.

Gain on sale of gas-fired plants $ - $ 47.1 $ -

• Plants with Power Purchase AgreementsT-our generating Non-qualifying hedges 2.0 39.2 (24.9) facilities outside the Mid-Atlantic Region with long-term Impairment losses and other costs (12.2) - - power purchase agreements. As discussed in Note 2, the Workforce reduction costs (1.4) (17.0) (2.6) sale of the High Desert facility resulted in a Merger-related costs - (4.3) (10.4) reclassification of its results of operations to Total Other Items $ (11.6) $ 65.0 $ (37.9) discontinued operations.

• Wholesale Competitive Supply-our marketing, risk Above amounts include intercompany transactions eliminated in our management, and trading operation that provides energy ConsolidatedFinancialStatements. Note 3 provides a reconciliation of products and services primarily to distribution utilities, operating results by segment to our ConsolidatedFinancialStatements.

power generators, and other wholesale customers. We also provide global energy and related services and Revenues and Fuel and PurchasedEnergy Expenses upstream and downstream natural gas services.

Our merchant energy business manages the revenues we realize

+ Retail Competitive Supply-our operation that provides from the sale of energy to our customers and our costs of electric and gas energy products and services to procuring fuel and energy. As previously discussed, our merchant commercial, industrial, and governmental customers.

energy business uses either accrual or mark-to-market accounting

• Other-our investments in qualifying facilities and to record our revenues and expenses. Mark-to-market results domestic power projects and our generation operations reflect the net impact of amounts recorded in either revenues or and maintenance services.

fuel and purchased energy expenses to recognize changes in fair In December 2006, we completed the sale of these gas-fired value of derivative contracts subject to mark-to-market plants:

accounting during the reporting period.

Capacity Facility (MW) Unit Type Location High Desert 830 Combined Cycle California Rio Nogales 800 Combined Cycle Texas Holland 665 Combined Cycle Illinois University Park 300 Peaking Illinois Big Sandy 300 Peaking West Virginia Wolf Hills 250 Peaking Virginia 43

We discuss the sale of these gas-fired generating facilities in The merchant energy gross margin impact for 2007 from Note 2. the effect of market price changes on derivatives designated as We provide a summary of our revenues, fuel and purchased cash-flow and fair value hedges is summarized as follows:

energy expenses, and gross margin as follows: 2007 2007 2006 2005 (In millions)

(Doll~ar amounts in millions) Ineffectiveness on derivatives that qualified for hedge Revenues: accounting treatment $(10.8)

Mid-Atlantic Region $ 3,462.2 $ 2,813.5 $ 2,283.9 Effect of reduced price correlation on derivatives that did Plants with Power not qualify for hedge accounting treatment Pfrchase Agreements 657.3 650.5 665.9 Derivatives that were redesignated as hedges Competitive Supply prospectively (7.3)

Retail 9,086.3 8,014.7 6,942.3 Wholesale 5,469.4 5,612.7 4,672.3 Derivatives not eligible for designation as hedges Other 69.3 74.8 58.0 prospectively (70.8)

Total $ 18,744.5 $ 17,166.2 $ 14,622.4 Total $(88.9)

Fuel and puechased We discuss below the impact of these items on the applicable energy expenses: categories of merchant energy gross margin for 2007 compared Mid-Atlantic Region $ (2,214.4) $ (1,727.6) $ (1,436.5) to 2006. We discuss our hedging activities in more detail in Plants with Power Purchase Agreements (78.5) (67.9) (72.5) Note 13.

Competitive Supply Retail (8,590.8) (7,570.2) (6,668.) Mid-Atlantic Region Wholesale (4,618.1) (4,890.6) (4,124.6) 2007 2006 2005 Other---

$(14,256.3) $(12,301.8)

(In millions)

Total $(15,501.8)

Revenues $ 3,462.2 $ 2,813.5 '$ 2,283.9

% of  % of  % of Fuel and purchased energy Total Total Total Gross margin: expenses (2,214.4) (1,727.6) (1,436.5)

Mid-Atlantic Region $ 1,247.8 39% $ 1,085.9 37% $ 847.4 36%

Plants with PowerI Gross margin $ 1,247.8 $ 1,085.9 $ 847.4 Purchase Agreements 578.8 18 582.6 20 593.4 25 The $161.9 million increase in gross margin in 2007 compared Competitive Supply Retail 495.5 15 444.5 15 274.1 12 to 2006 is primarily due to approximately $249 million in Wholesale 851.3 26 722.1 25 547.7 24 higher margins on new and existing contracts. The increase in Other 69.3 2 74.8 3 58.0 3 gross margin was partially offset by the following:

Total $ 3,242.7 100% $ 2,909.9 100% $ 2,320.6 100% " the unfavorable impact of approximately $46 million related to losses recognized on cash-flow hedges due to Merchant energy gross margin for 2007 includes certain effects ineffectiveness and certain cash-flow hedges that no of market price changes on derivatives designated as cash-flow longer qualify for hedge accounting, and and fair value hedges. These market price changes had two

" the absence of competitive transition charge (CTC) primary impacts on 2007:

revenue of $41.0 million related to the deregulation of

" We experienced a significant increase in the level of the Maryland electricity markets, which ended June 30, ineffectiveness associated with derivatives that qualified 2006.

for hedge accounting treatment.

The increase of $238.5 million in gross margin in 2006

" Additionally, we were required to'discontinue the compared to 2005 is primarily due to approximately application of hedge accounting treatment for certain

$340 million in higher gross margin mostly from favorable derivatives due to insufficient price correlation between portfolio management, including higher margins on existing the hedge and the risk being hedged. As a result, the contracts and new contracts that began in 2006.

full change in the fa-ir value of these derivatives has been recorded in earnings.

44

Our wholesale marketing, risk management, and trading Competitive Supply operation was awarded contracts in 2006 to supply a substantial We analyze our retail accrual, wholesale accrual, and portion of BGE's standard offer service obligation to residential mark-to-market competitive supply activities below.

customers beginning July 1, 2006 through May 31, 2007. The increase in gross margin included higher revenues from BGE of Retail 2007 2006 2005 approximately $256 million mostly from these new contracts (In millions) during 2006 compared to 2005. This increase in gross margin Accrual revenues $ 9,080.5 $ 8,000.6 $ 6,944.2 was partially offset by the negative impact of higher expenses Fuel and purchased energy expenses (8,590.8) (7,577.0) (6,688.4) from serving the original BGE standard offer service obligation Retail accrual activities 489.7 423.6 255.8 during the first six months of 2006 as variable costs, including Mark-to-market activities 5.8 20.9 18.3 emissions and coal, continued to increase. We discuss the expiration of the BGE residential rate freeze in more detail in Gross margin $ 495.5 $ 444.5 $ 274.1 the Item 1.-Business-Baltimore Gas and Electric Company-- The $66.1 million increase in accrual gross margin from our Electric Competition section. Our wholesale marketing, risk retail competitive supply activities during 2007 compared to management, and trading operation served fixed-price standard 2006 is primarily due to approximately $104 million related to offer service obligations to BGE residential customers during the the positive impact of higher volumes served at higher contract period from July 1, 2000 until July 1, 2006. rates per megawatt hour and lower costs to serve load in our These increases in gross margin were partially offset by: retail electric operations. This increase in gross margin was

" lower CTC revenues of approximately $64 million due partially offset by approximately $38 million related to losses at to customers that completed their obligation and the our retail gas operations recognized during 2007 on hedges due continued decline in the CTC rate, and to ineffectiveness and on certain hedges that did not qualify for

" lower generation at Calvert Cliffs, which resulted in hedge accounting compared to 2006.

lower gross margin of approximately $37 million, mostly The increase in accrual gross margin of $167.8 million because of a longer planned 2006, refueling outage that from our retail activities during 2006 compared to 2005 is included replacement of the reactor vessel head. primarily due to:

" approximately $158 million in higher margins primarily Plants with Power Purchase Agreements due to higher electric rates and lower costs related to our fixed-price load-serving obligations as a result of 2007 2006 2005 milder weather in 2006 compared to the prior year, and (In millions) " approximately $13 million in higher gross margin due Revenues $657.3 $650.5 $665.9 to higher volumes, including 3.6 million more megawatt Fuel and purchased energy expenses (78.5) (67.9) (72.5) hours of electricity and 55 billion cubic feet more of Gross margin $578.8 $582.6 $593.4 natural gas served to retail customers during the year Gross margin from our Plants with Power Purchase Agreements ended December 31, 2006 compared to 2005.

was about the same in 2007 compared to 2006. Wholesale Gross margin from our Plants with Power Purchase 2007 2006 2005 Agreements decreased slightly in 2006 compared to the same (In millions) periods of 2005. This was mostly due to approximately Accrual revenues $ 4,932.5 $ 5,232.7 $ 4,281.8

$14 million in lower gross margin from the University Park Fuel and purchased energy facility, which effective June 2006 until its' sale in December expenses (4,618.1) (4,890.6) (4,124.6) 2006 was included in the Mid-Atlantic Region after the Wholesale accrual activities 314.4 342.1 157.2 expiration of its power purchase agreement in May 2006. Mark-to-market activities 536.9 380.0 390.5 Gross margin $ 851.3 $ 722.1 $ 547.7 Our wholesale marketing, risk management, and trading operation had $27.7 million of lower accrual gross margin during 2007 compared to 2006, primarily due to:

• the absence of approximately $67 million of gross margin associated with the gas plants that were sold in December 2006,

• lower gross margin related to the unfavorable impact of approximately $55 million of losses recognized on hedges due to ineffectiveness and on certain cash-flow hedges that did not qualify for hedge accounting,

• lower gross margin related to contract terminations and sales of approximately $39 million during 2007 compared to 2006, and 45

• approximately $34 million in losses in 2007 reclassified As a result of the nature of our operations and the use of from "Accumulated other comprehensive loss" to mark-to-market accounting for certain activities, mark-to-market earnings related to: earnings will fluctuate. We cannot predict these fluctuations, but

" the April 2007 CEP equity issuance and subsequent the impact on our earnings could be material. We discuss our deconsolidation, as discussed in'more detail in Note 2 market risk in more detail in the Market Risk section. The and Note 13. As a result of those transactions, we primary factors that cause fluctuations in our mark-to-market determined that certain hedged forecasted sales were results are:

probable of not occurring, which resulted in the

• the number, size, and profitability of new transactions reclassification of losses of approximately $22 million including terminations or restructuring of existing from "Accumulated other comprehensive loss" into contracts, earnings, and " the number and size of our open derivative positions, and

" certain amended nonderivative contracts which are

• changes in the level and volatility of forward commodity now derivatives accounted for as mark-to-market. prices and interest rates.

This resulted in the recognition' of approximately Mark-to-market results were as follows:

$12 million in losses from related cash-flow hedges 2007 2006 2005 previously deferred in "Accumulated other (In millions) comprehensive loss." We discuss these contracts in Unrealized mark-to-market results more detail in the Mark-to-Market section on the next Origination gains $ 41.9 $ 13.5 $ 61.6 page, Risk management and trading-These decreases were partially offset by approximately mark-to-market

$167 million of gross margin from new contracts executed, Unrealized changes in fair value 500.8 387.4 347.2 Changes in valuation techniques - - -

including the portfolio of contracts acquired in the southeast Reclassification of settled contracts region during 2007, and higher gross margin associated with to realized (369.3) (372.1) (257.7) existing contracts. Total risk management and trading--

Our wholesale marketing, risk management, and trading mark-to-market 131.5 15.3 89.5 operation had $184.9 million of higher gross margin from Total unrealized mark-to-market* 173.4 28.8 151.1 accrual activities during 2006 compared to 2005 due to: Realized mark-to-market 369.3 372.1 257.7

" an increase of approximately $145 million, primarily Total mark-to-market results $ 542.7 $ 400.9 $ 408.8 due to new contracts entered into during 2006 and

• Total unrealized mark-to-market is the sum of origination transactions and higher realized gross margin on existing contracts, and total risk management and trading-mark-to-market.

" an increase of approximately $85 million, primarily Origination gains arise primarily from contracts that our related to the growth in our coal and natural gas wholesale marketing, risk management, and trading operation activities. structures to meet the risk management needs of our customers These increases in gross margin were partially offset by the or relate to our trading activities. Transactions that result in following: origination gains may be unique and provide the potential for

" a decrease of $24.8 million as a result of the initial individually significant gains from a single transaction.

public offering of CEP and the sale of our gas-fired Origination gains represent the initial fair value recognized plants. As a result of these transactions, certain on these structured transactions. The recognition of origination forecasted transactions associated with cash-flow hedges gains is dependent on the existence of observable market data were determined to be probable of not occurring, and that validates the initial fair value of the contract. Origination the associated amounts previously recorded in gains arose primarily from:

'Accumulated other comprehensive loss" were reclassified

• 1 transaction in 2007, which is discussed in more detail into earnings, and below,

" a decrease of approximately $20 million from contract

• 3 transactions completed in 2006, of which no transaction restructurings related to unit contingent power purchase contributed in excess of $10 million pre-tax, and agreements during the year ended December 2006

• 6 transactions completed in 2005, one of which compared to 2005. The termination and sale of these contributed approximately $35 million pre-tax.

contracts has allowed us to eliminate our exposure to As noted above, the recognition of origination gains is performance risk under these contracts.

dependent on sufficient observable market data that validates the initial fair value of the contract. Liquidity and market conditions Mark-to-Market impact our ability to identify sufficient, objective market-price Mark-to-market results include net gains and losses from information to permit recognition of origination gains. As a result, origination, trading, and risk management activities for which while our strategy and competitive position provide the opportunity we use the mark-to-market method of accounting. We discuss to continue to originate such transactions, the level of origination these activities and the mark-to-market method of accounting in gains we are able to recognize may vary from year to year as a more detail in the CriticalAccounting Policies section and in result of the number, size, and market-price transparency of the Note 1. individual transactions executed in any period.

46

During 2007, our wholesale marketing, risk management, The close-out adjustments are determined by the change in and trading operation amended certain nonderivative power sales open positions, new transactions where we did not have contracts such that the new contracts became derivatives subject observable market price information, and existing transactions to mark-to-market accounting under SFAS No. 133. where we have now observed sufficient market price information Simultaneous with the amending of the nonderivative contracts, and/or we realized cash flows since the transactions' inception.

we executed at current market prices several new offsetting We discuss the close-out adjustment in more detail in the derivative power purchase contracts subject to mark-to-market CriticalAccounting Policies section.

accounting. The combination of these transactions resulted in Total mark-to-market results decreased $7.9 million in substantially all of the origination gains presented for 2007 in 2006 compared to 2005 because of a decrease in origination the table on the preceding page, as well as mitigated our risk gains of $48.1 million, mostly offset by an increase in unrealized exposure under the amended contracts. changes in fair value of $40.2 million. Unrealized changes in fair The origination gain from these transactions was partially value increased, primarily due to higher pre-tax gains of offset by approximately $12 million of losses in our accrual approximately $105 million related to the positive impact of portfolio due to the reclassification of losses related to cash-flow certain economic hedges primarily related to gas transportation hedges previously established for the amended nonderivative and storage contracts.

contracts from "Accumulated other comprehensive loss" into This increase in unrealized changes in fair value was earnings as discussed in our Competitive Supply-Wholesale Accrual partially offset by:

section on the previous page. In the absence of these " a lower level of gains from risk management and transactions, the economic value represented by the origination trading-mark-to-market activities of approximately gain and the losses associated with cash-flow hedges would have $45 million, and been recognized over the remaining term of the contracts, which " the absence of a $19.5 million favorable impact related extended through the first quarter of 2009. to changes in the close-out adjustment in 2006 Risk management and trading--mark-to-market represents compared to 2005.

both realized and unrealized gains and losses from changes in the value of our portfolio, including the recognition of gains associated DerivatireAssets and Liabilities with decreases in the close-out adjustment when we are able to As discussed in our CriticalAccounting Policies section, our obtain sufficient market price information. In addition, we use "Derivative assets and liabilities" include contracts accounted for derivative contracts subject to mark-to-market accounting to manage as hedges and those accounted for on a mark-to-market basis.

our exposure to changes in market prices primarily as a result of Derivative assets and liabilities consisted of the following:

our gas transportation and storage activities, while in general the underlying physical transactions related to our gas activities are At December 31, 2007 .2006 accounted for on an accrual basis. We discuss the changes in (In millions) mark-to-market results below. We show the relationship between Current Assets $ 961.2 $ 1,556.5 our mark-to-market results and the change in our net Noncurrent Assets 1,030.2 949.1 mark-to-market energy asset on the next page. Total Assets 1,991.4 2,505.6 Total mark-to-market results increased $141.8 million Current Liabilities 1,137.1 2,411.7 during 2007 compared to 2006 mostly because of an increase in Noncurrent Liabilities 1,118.9 1,099.7 unrealized changes in fair value of approximately $113 million and an increase in origination gains previously discussed. The Total Liabilities 2,256.0 3,511.4 increase in unrealized changes in fair value was primarily due to: Net Derivative Position $ (264.6) $(0,005.8)

" a more favorable price environment resulting in higher Portion of net derivative position accounted for gains of approximately $132 million, and as hedges $ (937.6) $(1,459.9)

• an increase of approximately $43 million from a Portion of net derivative position accounted for favorable impact related to changes in the close-out as mark-to-market $ 673.0 $ 454.1 adjustment.

These increases were partially offset by approximately The decrease in our net derivative liability subject to hedge

$62 million from lower mark-to-market results related to the accounting since December 31, 2006 of $522.3 million was due impact of certain economic hedges, primarily related to gas primarily to an approximate $355 million change in our transportation and storage contracts that do not qualify for or cash-flow hedge positions, which include both increases in power are not designated as cash-flow hedges. These mark-to-market prices that increased the fair value of our cash-flow hedge results will be offset in future periods as we realize the related positions and settlements of cash-flow hedges during 2007, and accrual load-serving positions in cash. approximately $167 million of net cash-flow hedge assets acquired as part of a contract and portfolio acquisition in June 2007. We discuss this contract and portfolio acquisition in more detail in FinancialCondition-Contractand Port rlio Acquisitions.

47

While some of our mark-to-market contracts represent " Unrealized changes in fair value represent unrealized commodities or instruments for which prices are available from changes in commodity prices, the volatility of options external sources, other commodities and certain contracts are not on commodities, the time value of options, and other actively traded and are valued using other pricing sources and valuation adjustments.

modeling techniques to determine expected future market prices, " Changes in valuation techniques represent improvements contract quantities, or both. We discuss our modeling techniques in estimation techniques, including modeling and other later in this section. The following are the primary sources of statistical enhancements used to value our portfolio to the change in our net derivative asset subject to mark-to-market reflect more accurately the fair value of our contracts.

accounting during 2007 and 2006:

• Reclassification of settled contracts to realized represents the portion of previously unrealized amounts settled 2007 2006 during the period and recorded as realized revenues.

(In millions) Our net derivative asset subject to mark-to-market Fair value beginning of year $454.1 accounting also changed due to the following items recorded in Changes in fair value accounts other than in our Consolidated Statements of Income:

recorded in earnings " Changes in value of exchange-listed futures and options Origination gains $ 41.9 $ 13.5 are adjustments to remove unrealized revenue from Unrealized changes in fair exchange-traded contracts that are included in risk value 500.8 387.4 management revenues. The fair value of these contracts Changes in valuation is recorded in "Accounts receivable" rather than techniques "Derivative assets" in our Consolidated Balance Sheets Reclassification of settled because these amounts are settled through our margin contracts to realized (369.3) (372.1) account with a third-party broker.

Total changes in fair value " Net changes in premiums on options reflects the recorded in earnings 173.4 accounting for premiums on options purchased as an Changes in value of increase in the net derivative asset and premiums on exchange-listed futures options sold as a decrease in the net derivative asset.

and options 18.6

• Contracts acquired represents the initial fair value of Net change in premiums on acquired derivative contracts recorded in "Derivative options (19.0) assets and liabilities" in our Consolidated Balance Contracts acquired 83.8 Sheets.

Other changes in fair value (37.9) " Other changes in fair value include transfers of derivative assets and liabilities between accounting Fair value at end of year $673.0 methods resulting from the designation and Changes in our net derivative asset subject to de-designation of cash-flow hedges.

mark-to-market accounting that affected earnings were as follows:

• Origination gains represent the initial unrealized fair value at the time these contracts are executed to the extent permitted by applicable accounting rules.

The settlement terms of our net derivative asset subject to mark-to-market accounting and sources of fair value as of December 31, 2007 are as follows:

Settlement Term 2008 2009 2010 2011 2012 2013 Thereafter Fair Value (In millions)

Prices provided by external sources (1) $359.0 $ 50.6 $ 26.2 $30.3 $ 28.0 $ 6.8 $3.0 $503.9 Prices based on models (1.8) 71.1 74.4 36.5 (11.4) (1.3) 1.6 169.1 Total net mark-to-market energy asset $357.2 $121.7 $100.6 $66.8 $ 16.6 $ 5.5 $4.6 $673.0 (1) Includes contracts actively quoted and contracts valued from other external sources.

48

We manage our mark-to-market risk on a portfolio basis Modeling techniques include estimating the present value of based upon the delivery period of our contracts and the cash flows based upon underlying contractual terms and individual components of the risks within each contract. incorporate, where appropriate, option pricing models and Accordingly, we record and manage the energy purchase and sale statistical and simulation procedures. Inputs to the models obligations under our contracts in separate components based include:

upon the commodity (e.g., electricity or gas), the product " observable market prices, (e.g., electricity for delivery during peak or off-peak hours), the

• estimated market prices in the absence of quoted market delivery location (e.g., by region), the risk profile (e.g., forward prices, or option), and the delivery period (e.g., by month and year). " the risk-free market discount rate, Consistent with our risk management practices, we have " volatility factors, presented the information in the table on the preceding page

• estimated correlation of energy commodity prices, and based upon the ability to obtain reliable prices for components " expected generation profiles of specific regions.

of the risks in our contracts from external sources rather than on Additionally, we incorporate counterparry-specific credit a contract-by-contract basis. Thus, the portion of long-term quality and factors for market price and volatility uncertainty contracts that is valued using external price sources is presented and other risks in our valuation. The inputs and factors used to under the caption "prices provided by external sources." This is determine fair value reflect management's best estimates.

consistent with how we manage our risk, and we believe it The electricity, fuel, and other energy contracts we hold provides the best indication of the basis for the valuation of our have varying terms to maturity, ranging from contracts for portfolio. Since we maniage our risk on a portfolio basis rather delivery the next hour to contracts with terms of ten years or than contract-by-contract, it is not practicable to determine more. Because an active, liquid electricity futures market separately the portion of long-term contracts that is included in comparable to that for other commodities has not developed, the each valuation category. We describe the commodities, products, majority of contracts used in the wholesale marketing, risk and delivery periods included in each valuation category in detail management, and trading operation are direct contracts between below. market participants and are not exchange-traded or financially The amounts for which fair value is determined using settling contracts that ca-n be readily liquidated in their entirety prices provided by external sources represent the portion of through an exchange or other market mechanism. Consequently, forward, swap, and option contracts for which price quotations we and other market participants generally realize the value of are available through brokers or over-the-counter transactions. these contracts as cash flows become due or payable under the The term for which such price information is available varies by terms of the contracts rather than through selling or liquidating commodity, region, and product. The fair values included in this the contracts themselves.

category are the following portions of our contracts: Consistent with our risk management practices, the

" forward purchases and sales of electricity during peak amounts shown in the table on the preceding page as being and off-peak hours for delivery terms primarily through valued using prices from external sources include the portion of 2011, but up to 2012, depending upon the region, long-term contracts for which we can obtain reliable prices from

• options for the purchase and sale of electricity during external sources. The remaining portions of these long-term peak hours for delivery terms through 2009, depending contracts are shown in the table as being valued using models.

upon the region, In order to realize the entire value of a long-term contract in a

" forward purchases and sales of electric capacity for single transaction, we would need to sell or assign the entire delivery terms primarily through 2009, but up to 2011, contract. If we were to sell or assign any of our long-term depending on the region, contracts in their entirety, we may realize an amount different

" forward purchases and sales of natural gas through from the value reflected in the table. However, based upon the 2012, coal through 2010, and oil for delivery terms nature of the wholesale marketing, risk management, and trading through 2011, and operation, we generally expect to realize the value of these

• options for the purchase and sale of natural gas for contracts, as well as any contracts we may enter into in the delivery terms through 2009. future to manage our risk, over time as the contracts and related The remainder of our net derivative asset subject to hedges settle in accordance with their terms. In general, we do mark-to-market accounting is valued using models. The portion not expect to realize the value of these contracts and related of contracts for which such techniques are used includes hedges by selling or assigning the contracts themselves in total.

standard products for which external prices are not available and The fair values in the table represent expected future cash customized products that are valued using modeling techniques flows based on the level of forward prices and volatility factors to determine expected future market prices, contract quantities, as of December 31, 2007 and could change significantly as a or both. result of future changes in these factors. Additionally, because the depth and liquidity of the power markets vary substantially between regions and time periods, the prices used to determine fair value could be affected significantly by the volume of transactions executed.

49

Management uses its best estimates to detetmine the fair We believe the current market conditions for our equity-value of commodity and derivative contracts it holds and sells. method investments that own geothermal, coal, hydroelectric, These estimates consider vatious factors including closing fuel processing projects, as well as our equity investments in our exchange and over-the-counter price quotations, time value, joint ventures and CEP provide sufficient positive cash flows to volatility factors, and credit exposure. However, future market recover our investments. We continuously monitor issues that prices and actual quantities will vary from those used in potentially could impact fuiture profitability of these investments, recording our net derivative assets and liabilities subject to including environmental and legislative initiatives. We discuss mark-to-market accounting, and it is possible that such certain risks and uncertainties in more detail in our Forward variations could be material.I Looking Statements and Item ]A. Risk Factors sections. However, In 2006, the Financial Accounting Standards Board issued should future events cause these investments to become SFAS No. 157 that will impact our accounting for derivative uneconomic, our investments in these projects could become instruments. We discuss this in more detail in Note 1. impaired under the provisions of APB No. 18.

Current California statutes and regulations require load-Other serving entities to increase their procurement of renewable 2007 2006 2005 energy resources and mandate statewide reductions in greenhouse (in millions) gas emissions. Given the need for electric power and the Revenues $69.3 $74.8 $58.0 statutory and regulatory requirements increasing demand for renewable resource technologies, we believe California will Our merchant energy business holds up to a 50% voting interest continue to foster an environment that supports the use of in 24 operating domestic energy projects that consist of electric renewable energy and continues certain subsidies that will make generation, fuel processing, or fuel handling facilities. Of these renewable energy projects economical. However, should 24 projects, 17 are "qualifying facilities" that receive certain California legislation and regulatory policies and federal energy exemptions based on the facilities' energy source or the use of a policies fail to adequately support renewable energy initiatives, cogeneration process. In addition, during 2007, our merchant our equity-method investments in these types of projects could energy business obtained and currently holds a 50% interest in a become impaired under the provisions of APB No. 18, and any joint venture to develop, own, and operate new nuclear projects losses recognized could be material.

in the United States and Canada (UniStar Nuclear Energy, LLC (UNE)). Earnings from these investments were $2.8 million in Operating Expenses 2007, $13.8 million in 2006, and $3.6 million in 2005.

Our merchant energy business operating expenses increased

$242.4 million during 2007 compared to 2006 mostly due to an Investments increase at our competitive supply operations totaling Our investment in qualifying facilities and domestic power $218.4 million, primarily related to the continued growth of this projects, CEP, and joint ventures consisted of the following: operation and higher compensation and benefit costs.

Our merchant energy business operating expenses increased Book Value at December 31, 2007 2006

$203.3 million in 2006 compared to 2005 mostly due to the (In millions) following:

Project Type

" an increase of $139.2 million at our competitive supply Coal $119.6 $125.7 operations, primarily related to higher labor and benefit Hydroelectric 54.7 55.1 costs and the impact of inflation on other costs, Geothermal 37.6 40.5

• an increase of $22.7 million at our upstream gas Biomass 43.6 46.6 operations, primarily due to acquisitions made in June Fuel Processing 26.8 33.7 Solar 2005, and 7.0 7.0 CEP 143.0 -

" an increase of approximately $18 million at our joint ventures: generating facilities, which includes higher expenses Shipping JV 56.6 - associated with longer planned outages, offset in part by UNE 52.2 - lower expenses that resulted from our productivity Other 1.1 - initiatives.

Total $542.2 $308.6 Impairment Losses and Other Costs Our impairment losses and other costs are discussed in more detail in Note 2.

Workforce Reduction Costs Our merchant energy business recognized expenses associated with our workforce reduction efforts as discussed in more detail in Note 2.

50

Merger-Related Costs Net income from the regulated electric business decreased We discuss costs related to the proposed merger with FPL $22.3 million in 2007 compared to 2006, primarily due to the Group, which has been terminated, in Note 15. following:

" increased operations and maintenance expenses of Depreciation, Depletion and Amortization Expense $15.0 million after-tax mostly due to higher labor and Merchant energy depreciation, depletion, and amortization benefits costs, expenses increased $11.2 million in 2007 compared to 2006 " increased depreciation and amortization of $3.6 million mostly due to: after-tax, and

• $30.9 million related to our upstream natural gas " increased taxes other than income taxes of $3.2 million operations, primarily due to acquisitions made in 2007, after-tax.

and The decrease was partially offset by an increase in revenues

• $6.2 million primarily related to additions to our less electricity purchased for resale expenses of $4.4 million nuclear facilities, including the impact of the uprate at after-tax, which includes the impact of Senate Bill 1 credits.

our Ginna facility in 2006. Net income from the regulated electric business decreased These increases were partially offset by $29.0 million $29.2 million in 2006 compared to 2005 mostly because of the primarily related to the absence of depreciation associated with following:

the gas plants that were sold in December 2006. " increased operations and maintenance expenses of

$19.9 million after-tax mostly due to higher labor and Taxes Other Than Income Taxes benefit costs and incremental costs associated with 2006 Taxes other than income taxes decreased $9.8 million in 2007 storms, and compared to 2006, primarily due to $5.8 million lower gross " decreased revenues less electricity purchased for resale receipts tax at our retail competitive supply operation and a expenses of $11.8 million after-tax.

$4.2 million decrease due to the sale of our gas-fired plants.

Merchant energy taxes other than income taxes increased Electric Revenues

$13.3 million in 2006 compared to 2005 mostly due to The changes in electric revenues in 2007 and 2006 compared to

$5.3 million related to higher gross receipts taxes at our retail the respective prior year were caused by:

competitive supply operation and $3.1 milli6n related to our 2007 2006 working interests in gas producing properties.

(In millions)

Regulated Electric Business Distribution volumes $ 19.5 $ (40.9)

Our regulated electric business is discussed in detail in Item 1. Standard offer service 267.8 433.7 Business-Electric Business section. Rate stabilization credits 34.6 (321.9)

Rate stabilization recovery 36.1 -

Financing credits (7.5) -

Results Senate Bill 1 credits (29.7) -

2007 2006 2005 (In millions) Total change in electric revenues from Revenues $ 2,455.7 $ 2,115.9 $2,036.5 electric system sales 320.8 70.9 Electricity purchased for Other 19.0 8.5 resale expenses (1,500.4) (1,167.8) (1,068.9) Total change in electric revenues $339.8 $ 79.4 Operations and maintenance expenses (376.1) (351.3) (318.4)

Distribution Volumes Merger-related costs - (3.3) (4.0)

Distribution volumes are the amount of electricity that BGE Depreciation and amortization (187.4) (181.5) (185.8) delivers to customers in its service territory.

Taxes other than income The percentage changes in our electric system distribution taxes (140.2) (134.9) volumes, by type of customer, in 2007 and 2006 compared to (135.3) the respective prior year were:

Income from Operations $ 251.6 $ 277.1 $ 324.1 Net Income $ 97.9 $ 120.2 $ 149.4 2007 2006 Other Items Included in Operations (after-tax) Residential 3.7% (6.4)%

Merger-related costs $ - $ (0.8) $ (3.7) Commercial 3.6 (0.6)

Industrial 0.2 (7.5)

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

51

In 2007, we distributed more electricity to residential Rate Stabilization Recover customers due to colder winter weather and an increased BGE began recovering amounts deferred during the first rate number of customers, partially offset by decreased usage per deferral period that ended on May 31, 2007 in late June 2007.

customer. We distributed more electricity to commercial customers due to increased usage per customer, colder winter Financing Credits weather, and an increased number of customers. We distributed Concurrent with the recovery of the deferred a-mounts related to essentially the same amount of electricity to industrial customers. the first rate deferral period, we are providing credits to In 2006, we distributed less electricity to residential residential customers to compensate them primarily for income customers mostly due to milder weather and decreased usage per tax benefits associated with the financing of the deferred customer, partially offset by an increased number of customers. amounts with rate stabilization bonds. We discuss the rate We distributed less electricity to commercial customers mostly stabilization bonds in more detail in Note 9.

due to milder weather, partially offset by an increased number of customers and increased usage per customer. We distributed less Senate Bill 1 Credits electricity to industrial customers mostly due to decreased usage As a result of Senate Bill 1, beginning January 1, 2007, we were per customer. required to provide to residential electric customers a credit equal to the amount collected from all BGE ratepayers for the Standard Offer Service decommissioning of our Calvert Cliffs nuclear power plant and BCE provides standard offer service for customers that do not to suspend collection of the residential return component of the select an alternative supplier. We discuss the provisions of Provider of Last Resort (POLR) administrative charge collected Maryland's Senate Bill I related to residential electric rates in the through residential POLR rates through May 31, 2007. Under Business Environment-Regulation-Maryland-SenateBills I and an order issued by the Maryland PSC in May 2007, as of 400 section. June 1, 2007, we were required to reinstate collection of the Standard offer service revenues increased in 2007 compared residential return component of the POLR administration charge to 2006, primarily due to an increase in the standard offer in POLR rates and to provide all residential electric customers a service rates following the expiration of residential rate freeze credit for the residential return component of the administrative service in July 2006, partially offset by lower standard offer charge.

service volumes.I Standard offer service revenues were higher in 2006 compared to 2005, mostly due to an increase to market prices in the standard offer service rates due to the expiration of the residential rate freeze in July 2006, partially offset by lower standard offer service volumes.

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

$6.5 million as of December 31, 2007.

In 2007 compared to 2006, the amount of rate stabilization credits provided to residential electric customers decreased, primarily due to the end of the first deferral period on May 31, 2007, partially offset by the additional deferrals during the second deferral period, which ended on December 31, 2007.

52

Electricity Purchasedfor Resale Expenses Recovery under Rate Stabilization Plans Electricity purchased for resale expenses include the cost of In late June 2007, we began recovering previously deferred electricity purchased for resale to our standard offer service amounts from customers. We recovered $28.5 million in 2007 customers. These costs do not include the cost of electricity in deferred electricity purchased for resale expenses. As discussed purchased by delivery service only customers. The following later, these collections secure the payment of principal and table summarizes our regulated electricity purchased for resale interest and other ongoing costs associated with rate stabilization expenses: bonds issued by a subsidiary of BGE in June 2007.

2007 2006 2005 Electric Operations and Maintenance Expenses (In millions) Regulated operations and maintenance expenses increased Actual costs $1,759.2 $1,489.7 $1,0,68.9 $24.8 million in 2007 compared to 2006 mostly due to higher Deferral under rate labor and benefit costs and the impact of inflation on other stabilization plan (287.3) (321.9) - costs of $16.9 million, customer education in relation to rate Recovery under rate stabilization of $5.3 million and increased uncollectible accounts stabilization plans 28.5 - -

receivable expense of $2.9 million.

Electricity purchased for Regulated electric operations and maintenance expenses resale expenses $1,500.4 $1,167.8 $1,068.9 increased $32.9 million in 2006 compared to 2005 mostly due to higher labor and benefit costs and the impact of inflation on other costs and $13.1 million of incremental distribution service Actual Costs restoration expenses associated with 2006 storms.

BGE's actual costs for electricity purchased for resale increased

$269.5 million for 2007 compared to 2006, primarily due to Electric Depreciation andAmortization Expense higher contract prices to purchase electricity for our residential Regulated electric depreciation and amortization expense customers following the expiration of contracts that were increased $5.9 million in 2007 compared to 2006, primarily due executed in 2000 as part of the implementation of electric to additional property placed in service.

deregulation in Maryland, partially offset by lower volumes.

Regulated electric depreciation and amortization expense BGE's actual costs for electricity purchased for resale decreased $4.3 million in 2006 compared to 2005 mostly increased $420.8 million in 2006 compared to 2005 due to because of the absence of $6.9 million amortization expense higher contract prices to purchase electricity resulting from the associated with certain software, partially offset by $3.0 million expiration of contracts that were executed in 2000 as part of the related to additional property placed in service.

implementation of electric deregulation in Maryland, partially offset by lower standard offer service volumes.

Taxes Other Than Income Taxes Taxes other than income taxes increased $5.3 million in 2007 in Deferral under Rate Stabilization Plan comparison with 2006, primarily due to increased property We defer the difference between our actual costs of electricity taxes.

purchased for resale and what we are allowed to bill customers under Senate Bill 1. In 2007, we deferred $287.3 million in electricity purchased for resale expenses. Since July 1, 2006, we have deferred $609.2 million in electricity purchased for resale expenses. In 2006, we deferred $321.9 million in electricity purchased for resale expenses. These deferred expenses, plus carrying charges, are included in "Regulatory Assets (net)" in our, and BGE's, Consolidated Balance Sheets. We discuss the provisions of Senate Bill I related to residential electric rates in the Business Environment-Regulation-Maryland-SenateBills I and 400 section.

53

Regulated Gas Business Distribution Volumes Our regulated gas business is discussed in detail in Item 1. The percentage changes in our distribution volumes, by type of Business-Gas Business section. customer, in 2007 and 2006 compared to the respective prior year were:

Results 2007 2006 2005 2007 2006 (In millions) Residential 17.7% (17.0)%

Revenues $ 962.8 $ 899.5 $ 972.8 Commercial 14.6 (13.3)

Gas purchased for resale Industrial (11.3) 3.2 expenses (639.8) (581.5) (687.5)

Operations and maintenance In 2007, we distributed more gas to residential customers expenses (157.5) (144.8) (131.8) due to colder weather, increased usage per customer and an Merger-related costs - (1.4) (1.4) increased number of customers. We distributed more gas to Depreciation and amortization (46.8) (46.0) (46.6) commercial customers due to an increased number of customers Taxes other than income taxes (36.1) (33.8) (33.1) and colder weather, partially offset by decreased usage per Income from Operations $ 82.6 $ 92.0 $ 72.4 customer. We distributed less gas to industrial customers mostly Net Income $ 28..8 $ 37.0 $ 26.7 due to decreased usage per customer.

In 2006, we distributed less gas to residential and Other Items Included in Operations (afier-taaý)

commercial customers compared to 2005 mostly due to milder Merger-related costs $ _'~ $ (0.4) $ (1.3) weather and decreased usage per customer, partially offset by an Above amounts include intercompany transactions eliminated in our increased number of customers. We distributed more gas to Consolidated FinancialStatements. Note 3 provides a reconciliation industrial customers mostly due to increased usage per customer.

of operating results by segment to our Consolidated Financial Statements.I Base Rates Net income from the regulated gas business decreased In December 2005, the Maryland PSC issued an order granting

$8.2 million in 2007 compared to 2006, primarily due to BGE a $35.6 million annual increase in its gas base rates. In increased operations and maintenance expenses of $7.7 million December 2006, the Baltimore City Circuit Court upheld the after-tax. rate order. However, certain parties have filed an appeal with the Net income from the regulated gas business increased Court of Special Appeals. We cannot provide assurance that the

$10.3 million in 2006 compared to 2005 mostly due to Maryland PSC's order will not be reversed in whole or in part increased revenues less gas purchased for resale expenses of or that certain issues will not be remanded to the Maryland PSC

$19.8 million after-tax, which was primarily due to the increase for reconsideration.

in gas base rates that was approved by the Maryland PSC in December 2005. This increase was partially offset by higher Gas Revenue Decoupling operations and maintenance expenses of $7.9 million after-tax. The Maryland PSC allows us to record a monthly adjustment to our gas distribution revenues to eliminate the effect of abnormal Gas RevenuesI weather and usage patterns per customer on our gas distribution The changes in gas revenues in 2007 and 2006 compared to the volumes. This means our monthly gas distribution revenues are respective prior year were caused by: based on weather and usage that is considered "normal" for the month and, therefore, are affected by customer growth and nor 2007 2006 by actual weather or usage conditions.

(In millions)

Distribution volumes $ 19.3 $ (38.0)

Base rates 0.2 33.4 Gas revenue decoupling (20.1) 28.4 Gas cost adjustments 74.4 (112.3)

Total change in gas revenues from gas system sales 73.8 (88.5)

Off-system sales (11.2) 13.9 Other 0.7 1.3 Total change in gas revenues $ 63.3 $ (73.3) 54

Gas Cost Adjustments labor and benefit costs and the impact of inflation on other We charge our gas customers for the natural gas they purchase costs of $8.9 million and increased uncollectible accounts from us using gas cost adjustment clauses set by the Maryland receivable expense of $1.2 million.

PSC as described in Note 1. However, under the market-based Regulated gas operations and maintenance expenses rates mechanism approved by the Maryland PSC, our actual cost increased $13.0 million in 2006 compared to 2005 mostly due of gas is compared to a market index (a measure of the market to higher labor and benefit costs and the impact of inflation on price of gas in a given period). The difference between our other costs.

actual cost and the market index is shared equally between shareholders and customers. Gas Taxes Other Than Income Taxes Customers who do not purchase gas from BGE are not Gas taxes other than income taxes increased $2.3 million in subject to the gas cost adjustment clauses because we are not 2007 compared to 2006, primarily due to increased property selling gas to them. However, these customers are charged base taxes.

rates to recover the costs BGE incurs to deliver their gas through our distribution system, and are included in the gas distribution Other Nonregulated Businesses volume revenues. Results Gas cost adjustment revenues increased in 2007 compared 2007 2006 2005 to 2006 because we sold more gas at higher prices. (In millions)

Gas cost adjustment revenues decreased in 2006 compared Revenues $ 249.8 $ 231.0 $ 207.0 to 2005 because we sold less gas at lower prices. Operating expenses (173.5) (173.1) (156.2)

Merger-related costs - (0.5) (0.4)

Off-System Sales Depreciation and amortization (53.7) (37.7) (40.2)

Off-system gas sales are low-margin direct sales of gas to Taxes other than income taxes (2.4) (2.0) (2.0) wholesale suppliers of natural gas. Off-system gas sales, which Income from Operations $ 20.2 $ 17.7 $ 8.2 occur after BGE has satisfied its customers' demand, are not Income from continuing operations and subject to gas cost adjustments. The Maryland PSC approved an before cumulative effects of changes arrangement for part of the margin from off-system sales to in accounting principles (after-tax) $ 16.5 $ 11.3 $ 0.4 benefit customers (through reduced costs) and the remainder to Income from discontinued operations be retained by BGE (which benefits shareholders). Changes in (after-tax) - 0.9 20.6 off-system sales do not significantly impact earnings. Cumulative effects of changes in Revenues from off-system gas sales decreased in 2007 accounting principles (after-tax) - - 0.2 compared to 2006 because we sold gas at lower prices, partially Net Income $ 16.5 $ 12.2 $ 21.2 offset by more gas sold. Other Items Included In Operations (after-tax)

Revenues from off-system gas sales increased in 2006 Merger-related costs $ - $ (0.2) $ (0.2) compared to 2005 because we sold more gas, partially offset by lower prices. Above amounts include intercompany transactions eliminated in our Consolidated FinancialStatements. Note 3 provides a reconciliation Gas PurchasedForResale Expenses of operating results by segment to our ConsolidatedFinancial Gas purchased for resale expenses include the cost of gas Statements.

purchased for resale to our customers and for off-system sales.

Net income from our other nonregulated businesses increased These costs do not include the cost of gas purchased by delivery

$4.3 million in 2007 compared to 2006, primarily due to higher service only customers.

construction volume at our energy projects business.

Gas purchased for resale expenses increased $58.3 million Net income from our other nonregulated businesses in 2007 compared to 2006 because we purchased more gas, decreased $9.0 million in 2006 compared to 2005, primarily due partially offset by lower prices.

to a $19.7 million decrease in income from discontinued Gas purchased for resale expenses decreased $106.0 million operations, partially offset by a $10.7 million increase in net in 2006 compared to 2005 because we purchased less gas at income from our remaining other nonregulated businesses, lower prices.

including an increase in net income from our continued liquidation of our real estate investments.

Gas Operations and Maintenance Expenses Regulated gas operations and maintenance expenses increased

$12.7 million in 2007 compared to 2006 mostly due to higher 55

Consolidated Nonoperating Income and Expenses Income Taxes Gains on Sale of CEP Equity The differences in income taxes resulted from a combination of In November 2006, CEP, a limited liability company formed by the changes in income and the impact of the recognition of tax Constellation Energy, completed an initial public offering of credits on the effective tax rate. We include an analysis of the 5.2 million common units at $21 per unit. As a result of the changes in the effective tax rate in Note 10.

initial public offering of CEP, we recognized a pre-tax gain of Our income taxes increased $77.3 million in 2007

$28.7 million, or $17.9 million after recording deferred taxes on compared to 2006 mostly because of an increase in pre-tax the gain. As a result of subsequent sales of equity by CEP, which income and a decrease in synthetic fuel tax credits of reduced our relative ownership percentage, we recognized pre-tax $20 million.

gains totaling $63.3 million in 2007. We discuss the issuances of In 2007, the State of Maryland increased its corporate CEP equity in more detail in Note 2. income tax rate from 7% to 8.25%, effective January 1, 2008.

The impact of adjusting all existing deferred income tax assets Other Income and liabilities for this change in the period of enactment was not O41her income increased in 2007 compared to 2006, mostly due material to us. However, this did impact BGE, as discussed to higher interest and investment income due to a higher cash below.

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

stabilization deferrals of "Electricity Purchased for Resale" Income taxes increased $187.1 million in 2006 compared expense. We discuss the rate stabilization deferrals in more detail to 2005, primarily due to a higher level of pre-tax income, in the Regulated Elecrric Business section. including the gain on sale of gas-fired plants and the gain on the initial public offering of CEP, as well as a decrease in Fixed Charges synthetic fuel tax credits.

Fixed charges decreased in 2007 compared to 2006, mostly due Total income taxes for BGE decreased $17.7 million in to a lower average level of debt outstanding. 2006 compared to 2005 mostly due to lower pre-tax income.

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

Fixed charges increased $18.5 million in 2006 compared to 2005 mostly because of a higher level of debt outstanding, including commercial paper borrowings, and higher interest rates in 2006 compared to 2005.

Total fixed charges for BGE increased $9.1 million in 2006 compared to 2005 mostly because of a higher level of debt outstanding.

56

Financial Condition Cash Flows The following table summarizes our 2007 cash flows by business segment, as well as our consolidated cash flows for 2007, 2006, and 2005.

2007 Segment Cash Flows Coxisolidated Cash Flows Merchant Regulated Other 2007 2006 2005 (In millions)

Operating Activities Net income $ 678.3 $ 126.7 $ 16.5 $ 821.5 $ 936.4 $ 623.1 Non-cash adjustments to net income 428.2 93.4 13.0 534.6 195.4 746.0 Changes in working capital (260.9) (120.9) 8.6 (373.2) (677.7) (747.6)

Defined benefit obligations* (53.6) 40.5 3.4 Other (18.4) (45.8) 62.7 (1.5) 30.7 2.3 Net cash provided by operating activinies 827.2 53.4 100.8 927.8 525.3 627.2 Investing Activities Investments in property, plant and equipment (837.0) (375.8) (82.9) (1,295.7) (962.9) (760.0)

Asset acquisitions and business combinations, net of cash acquired (347.5) - - (347.5) (137.6) (237.2)

Investment in nuclear decommissioning Itrust fund securities (659.5) - - (659.5) (492.5) (370.8)

Proceeds from nuclear decommissioning trust fund securities 650.7 - - 650.7 483.7 353.2 Net proceeds from sale of gas-fired plan ts and discontinued operations lon eevbe- - - - 1,630.7 289.4 Issuances oflasrcibe (19.0) - - (19.0) (65.4) (82.8)

Sale of investments and other assets 3.9 0.8 9.2 13.9 43.9 14.4 Contract and portfolio acquisitions (474.2) - - (474.2) (2.3) (336.2)

Decrease (increase) in restricted funds (2.9) (42.3) (64.7) (109.9) 7.7 (4.0)

Other investments (44.1) - (1.2) (45.3) 54.8 (40.0)

Net cash (used in) provided by investing activities (1,729.6) (417.3) (139.6) (2,286.5) 560.1 (1,174.0)

Cash flows from operating activities less cash flows from investing activities $ (902.4) $(363.9) $ (38.8) (1,358.7) 1,085.4 (546.8)

Financing Activities*

Net (repayment) issuance of debt (33.1) 242.2 (339.6)

Proceeds from issuance of common stock 65.1 84.4 96.9 Common stock dividends paid (306.0) (264.0) (228.8)

Reacquisition of common stock (409.5) --

Proceeds from initial public offering of CEP - 101.3 -

Proceeds from contract and portfolio acquisitions 847.8 221.3 1,026.9 Other 1.2 5.5 98.1 Net cash provided by Financing activities 165.5 390.7 653.5 Net (decrease) increase in cash and cash equivalents $01,193.2) $ 1,476.1 $ 106.7

• Items are not allocated to the business segments because they are managedfor the company as a whole.

Certainprior-year amounts have been reclassified to conform with the current year I presentation.

Cash Flows from OperatingActivities Changes in working capital had a negative impact of Cash provided by operating activities was $927.8 million in $373.2 million on cash flows from operations in 2007 compared 2007 compared to $525.3 million in 2006. This $402.5 million to a negative impact of $677.7 million in 2006. The increase was primarily due to an increase iIn non-cash improvement in working capital of $304.5 million was due to a adjustments to net income and favorable changes in working $200.8 million change in working capital primarily related to capital, offset in part by unfavorable changes in net income. higher fuel stock purchases in 2006 as compared to 2007.

Non-cash adjustments to net income increased Cash provided by operating activities was $525.3 million in

$339.2 million in 2007 compared to 2006, primarily due to the 2006 compared to $627.2 million in 2005. This $101.9 million absence of a $191.4 million gain on sale of gas-fired plants and decrease was primarily due to a decrease in non-cash adjustments discontinued operations in 2006, a change in deferred fuel costs to net income in 2006, partially offset by favorable changes in of $100.5 million related mostly to lower deferrals of electricity net income and working capital.

purchased for resale under the BGE rate stabilization plan, and a Non-cash adjustments to net income decreased by

$98.2 million increase in deferred income tax expense. $550.6 million in 2006 compared to 2005, primarily due to the change in deferred fuel costs of $336.6 million related mostly to 57

the deferred recovery of electricity purchased for resale under the contract and portfolio acquisitions of $626.5 million, which we BCE rate stabilization plan. We discuss the rate stabilization discuss below.

plan in more detail in the Item 1.-Business-Baltimore Gas and In October 2007, our board of directors approved a Electric Company-Electric Business-Electric Competi.ti.on section common share repurchase program for up to $1 billion of our and Note 1. In addition, our gains on the sale of gas-fired plants outstanding common shares. Subsequent to this approval, on and discontinued operations increased $177.6 million in 2006 October 31, 2007, we entered into an accelerated share compared to 2005. We discuss this in more detail in Note 2. repurchase agreement with a financial institution, and on Changes in working capital had a negative impact of November 2, 2007 we purchased 2,023,527 of outstanding

$677.7 million on cash flow from operations in 2006 compared shares of our common stock for $250 million. We discuss the to a negative impact of $747.6 million in 2005. The negative share repurchase program in more detail in Note 9.

impact of $677.7 million related to working capital was Cash provided by financing activities-was $390.7 million in primarily due to the commodity price environment and 2006 compared to $653.5 million in 2005. The decrease of increased risk management and trading activities that resulted in $262.8 million in cash provided in 2006 compared to 2005 was an increase of approximately $630 million in net cash collateral primarily due to a decrease in proceeds from acquired contracts requirements, primarily for requirements on exchange-settled of $805.6 million, a decrease in other financing activities of transactions. This increase in cash collateral requirements was $92.6 million, and a $35.2 million increase in our dividends accompanied by a decrease in our letters of credit requirements. paid in 2006 compared to 2005. We discuss the proceeds from acquired contracts below. These decreases were partially offset by Cash Flows fromn Investing Activities a net increase in cash related to changes in short-term Cash used in investing activities was $2,286.5 million in 2007 borrowings and long-term debt of $581.8 million and compared to cash provided by of $560.1 million in 2006. The $101.3 million in proceeds from the initial public offering of

$2,846.6 million increase in cash used in 2007 compared to CER 2006 was primarily due to the following:

" the absence of the net proceeds of $1,630.7 million Contract and Portfolio Acquisitions from the sale of gas-fired plants and discontinued During 2007, 2006, and 2005, our merchant energy business operations received in 2006, acquired several pre-existing energy purchase and sale

• a $471.9 million increase in contract and portfolio agreements, which generated significant cash flows at the acquisitions that we discuss in more detail below, inception of the contracts. These agreements had contract prices

" a $332.8 million increase in investments in property, that differed from market prices at closing, which resulted in plant and equipment primarily related to growth within cash payments from the counterparty at the acquisition of the our merchant segment, which includes spending related contract. We received net cash of $373.6 million in 2007, to environmental controls at our generating facilities, $219.0 million in 2006, and $690.7 million in 2005 -for various andI contract and portfolio acquisitions. We reflect the underlying

" a $209.9 million increase in acquisitions, primarily contracts on a gross basis as assets or liabilities in our related to our acquisitions of working interests in gas Consolidated Balance Sheets depending on whether they were at and oil producing properties and a retail competitive above- or below-market prices at closing; therefore, we have also supply business as discussed in more detail in Note 15. reflected them on a gross basis in cash flows from investing and Cash provided by investing activities was $560.1 million in financing activities in our Consolidated Statements of Cash 2006 compared to cash used in investing activities Flows as follows:

$1,174.0 million in 2005. The $1,734.1 risillion favorable Year ended December 31, 2007 2006 2005 change in 2006 compared to 2005 was primarily due to the (In millions) increase in proceeds from sale of gas-fired plants and Financing activities-proceeds discontinued operations of $1,341.3 million and a decrease of from contract and portfolio

$333.9 million in cash paid for contract and portfolio acquisitions $ 847.8 $221.3 $1,026.9 acquisitions. Investing activities-contract and portfolio acquisitions (474.2) (2.3) (336.2)

Cash Flows from Financing Activities Cash flows from contract and Cash provided by financing activities was $165.5 million in portfolio acquisitions $ 373.6 $219.0 $ 690.7 2007 compared to $390.7 million in 2006. The decrease of

$225.2 million was primarily due to cash used for reacquisition We record the proceeds we receive to acquire energy of common stock of $409.5 million, a net decrease in cash purchase and sale agreements as a financing cash inflow because related to changes in short-term borrowings and long-term debt it constitutes a prepayment for a portion of the market price of of $275.3 million, and a net decrease of $101.3 million in energy, which we will buy or sell over the term of the proceeds from the initial public offering of CEP in 2006. This agreements and does nor represent a cash inflow from current was partially offset by an increase in gross proceeds from period operating activities. For those acquired contracts that are derivatives, we record the ongoing cash flows related to the 58

contract with the counterparties as financing cash inflows in subsidiaries. At December 31, 2007, we had approximately accordance with SFAS No. 149. For those acquired contracts $3.85 billion of credit under a five-year facility that expires in that are not derivatives, we record the ongoing cash flows related July 2012. In December 2007, we entered into an additional to the contract as operating cash flows. one-year credit facility totaling $250.0 million. This facility We discuss certain of these contract ind portfolio amended and restated a $200.0 million facility that expired in acquisitions in more detail in Note 5. December 2007.

These revolving credit facilities allow the issuance of letters Security Ratings of credit up to $4.1 billion. At December 31, 2007, letters of Independent credit-rating agencies rate Constellation Energy's credit that totaled $1.8 billion were issued under all of our and BGE's fixed-income securities. The ratings indicate the facilities, which results in approximately $2.3 billion of unused agencies' assessment of each company's ability to pay interest, credit facilities. Additionally, in January 2008, we entered into a distributions, dividends, and principal on these securities. These new six month line of credit totaling $500.0 million. This line ratings affect how much it will, cost each company to sell these of credit expires in July 2008 and has an option to be extended securities. Generally, the better the rating, ,the lower the cost of for an additional six months, subject to the lender's approval.

the securities to each company when they'sell them. We enter into these facilities to ensure adequate liquidity to The factors that credit rating agencies consider in support our operations. Currently, we use the facilities to issue establishing Constellation Energy's and BGE's credit ratings letters of credit primarily for our merchant energy business.

include, but are not limited to, cash flows, liquidity, business We expect to fund future acquisitions with an overall goal risk profile, political, legislative and regulatory risk, and the of maintaining a strong investment grade credit profile.

amount of debt as a component of total capitalization.

At the date of this report, our credit ratings were as follows: BGE Standard BGE currently maintains a $400.0 million five-year revolving

& Poors Moody's credit facility expiring in 2011. BGE can borrow directly from Rating Investors Fitch-Groudp Service Ratings the banks or use the facilities to allow commercial paper to be issued. As of December 31, 2007, BGE had $0.7 million in Constellation Energy letters of credit issued, which results in $399.3 million in Commercial Paper A-2 P-2 F2 unused credit facilities.

Senior Unsecured Debt BBB+ Baal BBB+

BGE Commercial Paper A-2 P-2 F2 Capital Resources Mortgage Bonds A, Baal A Our actual consolidated capital requirements for the years 2005 Senior Unsecured Debt BBB+ Baa2 A- through 2007, along with the estimated annual amount for Rate Stabilization Bonds

• AAA Aaa AAA 2008, are shown in the table on the next page.

Trust Preferred Securities BBB- Baa3 BBB+ We will continue to have cash requirements for:

Preference Stock BBB- Bal BBB+

• working capital needs,

• Bonds issued by RSB BondCo LLC, a subsidiary of BGE

• payments of interest, distributions, and dividends,

1. capital expenditures, and In February 2008, Fitch Ratings placed both Constellation

• the retirement of debt and redemption of preference Energy and BGE on Ratings Watch Negative due to the current stock.

political and regulatory environment in Maryland. Additionally, Capital requirements for 2008 and 2009 include estimates in February 2008, Standard & Poors Rating Group affirmed the of spending for existing and anticipated projects. We ratings of both Constellation Energy and BGE. They kept the continuously review and modify those estimates. Actual outlook on the ratings as negative due to the current political requirements may vary from the estimates included in the table and regulatory environment in Maryland. .We discuss the on the next page because of a number of factors including:

potential effect of a ratings downgrade in the Liquidity Provisions

" regulation, legislation, and competition, section.

" BGE load requirements,

" environmental protection standards, Available Sources of Funding

• the type and number of projects selected for We continuously monitor our liquidity requirements and believe construction or acquisition, that our credit facilities and access to the capital markets provide

" the effect of market conditions on those projects, sufficient liquidity to meet our business requirements. We

" the cost and availability of capital, discuss our available sources of funding in more detail below.

" the availability of cash from operations, and

" business decisions to invest in capital projects.

Constellation Energy In addition to our cash balance, we have a commercial paper program under which we can issue short-term notes to fund our 59

Our estimates are also subject to additional factors. Please Regulated Electric and Gas see the Forward Looking Statements and Item IA. Risk Factors Regulated electric and gas construction expenditures primarily sections. include new business construction needs and improvements to existing facilities, including projects to improve reliability and 2005 2006 2007 2008 support demand response and conservation initiatives.

(In millions)

Nonregulated Capital Funding for Capital Requirements Requirements: Merchant Energy Business Merchant energy (excludes Funding for our merchant energy business is expected from acquisitions) internally generated funds. If internally generated funds are not Generation plants $ 182 $ 235 $ 201 $ 450 550 sufficient to meet funding requirements, we have available Environmental controls 1 17 157 Portfolio acquisitions/ sources from commercial paper issuances, issuances of long-term investments 231 227 512 565 debt and equity, leases, and other financing activities.

Technology/other 165 152 160 135 The projects that our merchant energy business develops Nuclear fuel 130 137 148 200 typically require substantial capital investment. Many of the Total merchant energy qualifying facilities and independent power projects that we have capital requirements 709 768 1,178 1,900 an interest in are financed primarily with non-recourse debt that Other nonregulated capital is repaid from the project's cash flows. This debt is collateralized requirements 32 21 85 80 by interests in the physical assets, major project contracts and Total nonregulated capital agreements, cash accounts and, in some cases, the ownership requirements 741 789 1,263 1,980 interest in that project.

We expect to fund acquisitions with a mixture of debt and Regulated Capital Requirements: equity with an overall goal of maintaining a strong investment Regulated electric 241 297 340 415 grade credit profile.

Regulated gas 50 63 62 80 Regulated Electric and Gas Total regulated capital requirements 291 360 402 495 Funding for regulated electric and gas capital expenditures is expected from internally generated funds. If internally generated Total capital requirements $1,032 $1,149 $1,665 $2,475 funds are not sufficient to meet funding requirements, we have As of the date of this report, we have not completed our available sources from commercial paper issuances, available 2009 capital budgeting process, but expect our 2009 capital capacity under credit facilities, the issuance of long-term debt, requirements to be approximately $2.0 billion. trust preferred securities, or preference stock, and/or from time Our environmental controls capital requirements are to time equity contributions from Constellation Energy. BGE affected by new rules or regulations that require modifications to also participates in a cash pool administered by Constellation our facilities. We are in the process of installing additional air Energy as discussed in Note 16.

emission control equipment at certain of our coal-fired generating facilities in Maryland and plan to install additional Other Nonregula ted Businesses air emission control equipment at co-owned coal-fired generating Funding for our other nonregulated businesses is expected from facilities in Pennsylvania. We estimate another $400 million of internally generated funds. If internally generated funds are not capital spending from 2009-2012 for environmental controls. sufficient to meet funding requirements, we have available We discuss environmental matters in more detail in Item 1. sources from commercial paper issuances, issuances of long-term Business-EnvironmentalMatters. debt of Constellation Energy, sales of securities and assets, and/or from time to time equity contributions from Capital Requirements Constellation Energy.

Merchant Energy Business Our ability to sell or liquidate securities and assets will Our merchant energy business' capital requirements consist of its depend on market conditions, and we cannot give assurances continuing requirements, including expenditures for: that these sales or liquidations could be made.

" improvements to generating plants, Contractual Payment Obligations and Committed

" nuclear fuel costs, Amounts

" upstream gas investments, We enter into various agreements that result in contractual

• portfolio acquisitions and other investments, payment obligations in connection with our business activities.

" costs of complying with the Environmental Protection These obligations primarily relate to our financing arrangements Agency (EPA), Maryland, and Pennsylvania (such as long-term debt, preference stock, and operating leases),

environmental regulations and legislation, and purchases of capacity and energy to support the growth in our

• enhancements to our information technology merchant energy business activities, and purchases of fuel and infrastructure. transportation to satisfy the fuel requirements of our power generating facilities.

60

We detail our contractual payment obligations as of obligated to post collateral if Constellation Energy's senior December 31, 2007 in the following table: unsecured credit ratings declined below established contractual Payments levels. Based on contractual provisions at December 31, 2007, 2009- 2011- we estimate that if Constellation Energy's senior unsecured debt 2008 2010 2012 Thereafter Total were downgraded we would have the following additional (In millions) collateral obligations:

ContractualPayment Obligations Long-term debt:'

Nonregulated Level Principal $ 5.6 $ 501.9 $ 742.9 $1,580.4 $ 2,830.8 Below Cumulative Interest 165.6 286.9 238.0 1,218.5 1,909.0 Credit Ratings Current Incremental Incremental Downgraded to Rating Obligations Obligations Total 171.2 788.8 980.9 2,798.9 4,739.8 BGE (In millions)

Principal 350.0 121.6 254.2 1,489.3 2,215.1 BBB/Baa2 1 $327 $ 327 Interest 128.9 215.6 197.4 1,411.5 1,953.4 BBB-/Baa3 2 281 608 Total 478.9 337.2 451.6 2,900.8 4,168.5 Below investment grade 3 728 1,336 BGE preference 2stock - - - 190.0 190.0 Operating leases 3 505.6 454.6 470.7 892.5 2,323.4 Based on market conditions and contractual obligations at Purchase obligations:

Purchased capacity and the time of a downgrade, we could be required to post collateral 4

energy 425.2 489.6 213.8 276.4 1,405.0 in an amount that could exceed the amounts specified above, Fuel and transportation 1,825.1 1,503.5 649.7 918.9 4,897.2 Other 259.1 41.8 20.3 19.3 340.5 which could be material. We discuss our credit ratings in the Other noncurrent liabilities: Security Ratings section and our credit facilities in the Available FIN 48 tax liability 22.7 18.4 - 14.0 55.1 Pension benefits 5

84.1 170.8 162.9 - 417.8 Sources ofFunding section.

Postretirement and post6 The credit facilities of Constellation Energy and BGE have employment benefits 43.0 99.6 116.2 229.1 487.9 limited material adverse change clauses, none of which would Total contractual payment prohibit draws under the existing facilities. The long-term debt obligations $3,814.9 $3,904.3 $3,066.1 $8,239.9 $19,025.2 indentures of Constellation Energy and BGE do not contain 1 Amounts in long-term debt reflect the originalmaturity date. Investors may require us to repay $339.8 million early through remarketingfeatures. Interest on variable material adverse change clauses or financial covenants.

rate debt is included based on the December 31, 2007forward curve for interest Certain credit facilities of Constellation Energy contain a rates.

2 Our operating lease commitments include future payment obligations under certain provision requiring Constellation Energy to maintain a ratio of power purchase agreements as discussedfurther in Note Il. debt to capitalization equal to or less than 65%. At 3 Contracts to purchase goods or services that specify all significant terms. Amounts December 31, 2007, the debt to capitalization ratios as defined related to certainpurchase obligations are based on future purchase expectations which may differ from actual purchases. in the credit agreements were no greater than 46%. The credit 4 Our contractualobligationsfor purchasedcapacity and energy are shown on a gross agreement of BGE contains a provision requiring BGE to basisfor certain transactions. including both thefitxed payment portions of tolling contractsand estimated variablepayments under unit-contingent power purchase maintain a ratio of debt to capitalization equal to or less than agreements. 65%. At December 31, 2007, the debt to capitalization ratio for 5 Amounts related to pension benefits reflect our current 5-year forecastfor contribu-tions for our qualifiedpension plans andparticipantpayments for our nonqualfied BGE as defined in this credit agreement was 47%. At pension plans. Refer to Note 7for more detail on our pension plans. December 31, 2007, BGE had $0.7 million in letters of credit 6 Amounts related to postretirement and postemployment benefits are for unfunded plans and reflect present value amounts consistent with the determination ofthe outstanding under this agreement.

related liabilities recorded in our ConsolidatedBalance Sheets as discussed in Failure by Constellation Energy, or BGE, to comply with Note 7. these provisions could result in the acceleration of the maturity of the debt outstanding under these facilities. The credit facilities Liquidity Provisions of Constellation Energy contain usual and customary cross-In many cases, customers of our merchant energy business rely default provisions that apply to defaults on debt by on the creditworthiness of Constellation Energy. A decline below Constellation Energy and certain subsidiaries over a specified investment grade by Constellation Energy would negatively threshold.

impact the business prospects of that operation. The BGE credit facility also contains usual and customary We regularly review our liquidity needs to ensure that we cross-default provisions that apply to defaults on debt by BGE have adequate facilities available to meet collateral requirements. over a specified threshold. The indenture pursuant to which This includes having liquidity available to ,meet margin BGE has issued and outstanding mortgage bonds provides that a requirements for our wholesale marketing, risk management, and default under any debt instrument issued under the indenture trading operation and our competitive supply operations. may cause a default of all debt outstanding under such We have certain agreements that contain provisions that indenture.

would require additional collateral upon credit rating decreases Constellation Energy also provides credit support to Calvert in the senior unsecured debt of Constellation Energy. Decreases Cliffs, Nine Mile Point, and Ginna to ensure these plants have in Constellation Energy's credit ratings would not trigger an funds to meet expenses and obligations to safely operate and early payment on any of our credit facilities. maintain the plants.

Under counterparty contracts related to our wholesale marketing, risk management, and trading operation, we are 61

Pursuant to Senate Bill 1, in June 2007, BondCo, a *variable interests in unconsolidated entities that provide subsidiary of BGE, issued an aggregate principal a-mount of financing, liquidity, market risk or credit risk support,

$623.2 million of rate stabilization bonds to recover deferred or engage in leasing, hedging or research and power purchase costs. We discuss Senate Bill 1 in Business development services.

Environment-.-Regulation-Maryland-SenateBills 1 and 400 At December 31, 2007, Constellation Energy had a total of section and BondCo in more detail in Note 4. $14,761.6 million in guarantees outstanding, of which We discuss our short-term credit facilities in Note 8, $13,538.0 million related to our competitive supply activities.

long-term debt in Note 9, lease requirements in Note 11, and These amounts do not represent incremental consolidated commitments and guarantees in Note 12. Constellation Energy obligations; rather, they primarily represent parental guarantees of certain subsidiary obligations to third Off-Balance Sheet Arrangements parties. These guarantees are put into place in order to allow our For financing and other business purposes, we utilize certa-in subsidiaries the flexibility needed to conduct business with off-balance sheet arrangements that are not reflected in our counterparties without having to post other forms of collateral.

Consolidated Balance Sheets. Such arrangements do not While the stated limit of these guarantees is $13,538.0 million, represent a significant part of our activities or a significant our calculated fair value of obligations for commercial ongoing source of financing. transactions covered by these guarantees was $3,460.6 million at We use these arrangements when they enable us to obtain December 31, 2007. If the parent company was required to Financing or execute commercial transactions on favorable terms. fund these subsidiary obligations, the total amount based on As of December 31, 2007, we have no material off-balance sheet December 31, 2007 market prices would be $3,460.6 million.

arrangements including:I For those guarantees related to our derivative liabilities, the fair

• guarantees with third-parties that are subject to the value of the obligation is recorded in our Consolidated Balance initial recognition and measurement requirements of Sheets. We believe it is unlikely that we would be required to FASB Interpretation No. 45, GuaraneoriAccounting and perform or incur any losses associated with guarantees of our Disclosure Requirements for Guarantees, Including Indirect subsidiaries' obligations.

Guarantees a/ Indebtedness to Others, We discuss our other guarantees in Note 12 and our

• retained interests in assets transferred to unconsolidated significant variable interests in Note 4.

entities,I

• derivative instruments indexed to 'our common stock, and classified as equity, or Market RiskI our Chief Risk Officer, and consists of our Chief Executive We are exposed to various risks, including, but not limited to, Officer, our Chief Financial Officer, our Executive Vice President energy commodity price and volatility risk, credit risk, interest of Corporate Strategy, the President of Constellation Energy rate risk, equity price risk, foreign exchange risk, and operations Resources, the Chief Commercial Officers of Constellation risk. Our risk management program is based on established Energy Resources, and the President of Constellation Energy policies and procedures to manage these key business risks with Nuclear Group. In addition, the CR0 coordinates with the risk a strong focus on the physical nature of our business. This management committees at the major operating subsidiaries that program is predicated on a strong risk management culture meet regularly to identify, assess, and quantify' material risk combined with an effective system of internal controls. issues and to develop strategies to manage these risks.

The Audit Committee of the Board of Directors periodically reviews compliance with our risk parameters, limits Interest Rate Risk and trading guidelines, and our Board of Directors has We are exposed to changes in interest rates as a result of established a value at risk limit. We have a Risk Management financing through our issuance of variable-rate and fixed-rate Division that is responsible for monitoring the key business debt and certain related interest rate swaps. We may use risks, enforcing compliance with risk management policies and derivative instruments to manage our interest rate risks.

risk limits, as well as managing credit risk. The Risk In July 2004, to optimize the mix of fixed and floating-rate Management Division reports to the Chief Risk Officer (CR0) debt, we entered into interest rate swaps relating to who provides regular risk management updates to the Audit $450.0 million of our long-term debt. These fair value hedges Committee and the Board of Directors. effectively convert our current fixed-rate debt to a floating-rate We have a Risk Management Committee (RMC) that is instrument tied to the three month London Inter-Bank Offered responsible for establishing risk management policies, reviewing Rate. Including the $450.0 million in interest rate swaps, procedures for the identification, assessment, measurement and approximately 16% of our long-term debt is floating-rate.

management of risks, and the monitoring and reporting of risk We discuss our use of derivative instruments to manage our exposures. The RMC meets on a regular lasis anid is chaired by interest rate risk in more detail in Note 13.

62

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

Principal Payments and Interest Rate Detail by Contractual Maturity Date Fair value at December 31, 2008 2009 2010 2011 2012 Thereafter Total 2007 (Dollars in millions)

Long-term debt Variable-rate debt $ - $ - $ - $ 36.0 $255.2 $ 510.4 $ 801.6 $ 801.6 Average interest rate -% -  % 3.77% 7.59% 4.09% 5.19%

Fixed-rate debt $355.6 $566.5 $ 56.9 $ 81.7 $624.1 $2,559.5(A) $4,244.3 $4,307.5 Average interest rate 6.20% 6.09% 5.68% 5.95% 6.82% 6.18% 6.26%

(A) Amount excludes $339.8 million of long-term debt that is periodically remarkered and could require us to repay the debt prior to maturity of which $25.0 million is classified as currentportion of long-term debt in our Consolidated Balance. Sheets and in our Consolidated Statements of Capitalization.

Commodity Risk *geopolitical concerns affecting global supply of coal, oil, We are exposed to the impact of market fluctuations in the price and natural gas.

and transportation costs of electricity, natural gas, coal, and These factors can affect energy commodity and derivative other commodities. These risks arise from our ownership and prices in different ways and to different degrees. These effects operation of power plants, the load-serving activities of BCE and may vary throughout the country as a result of regional our competitive supply operations, and our origination, risk differences in:

management, and trading activities. We discuss these risks " weather conditions, separately for our merchant energy and our regulated businesses " market liquidity, below. " capability and reliability of the physical electricity and gas systems, and Merchant Energy Business

" the nature and extent of electricity deregulation.

Our merchant energy business is exposed to various risks in the Additionally, we have fuel requirements that are subject to competitive marketplace that may materially impact its financial future changes in coal, natural gas, uranium, and oil prices. Our results and affect our earnings. These risksý include changes in power generation facilities purchase fuel under contracts or in, commodity prices, imbalances in supply and demand, and operations risk. the spot market. Fuel prices may be volatile, and the price that can be obtained from power sales may not change at the same Commodity Prices rate or in the samse direction as changes in fuel costs. This could Commodity price risk arises from: have a material adverse impact on our financial results.

• the potential for changes in the price of, and transportation costs for, electricity, natural gas, coal, and Supply and Demand Risk other commodities, We are exposed to the risk that available sources of supply may

• the volatility of commodity prices, and differ from the amount of power demanded by our customers

• changes in interest rates and foreign exchange rates. under fixed-price load-serving contracts. During periods of high A number of factors associated with the structure and demand, our power supplies may be insufficient to serve our operation of the energy markets significantly influence the level customers' needs and could require us to purchase additional and volatility of prices for energy commodities and related energy at higher prices. Alternatively, during periods of low derivative products. We use such commodities and contracts in demand, our power supplies may exceed our customers' needs our merchant energy bus'iness, and if we do not properly hedge and could result in us selling that excess energy at lower prices.

the associated financial exposure, this commodity price volatility Either of those circumstances could have a negative impact on could affect our earnings. These factors include: our financial results.

" seasonal, daily, and hourly changes in demand, We are also exposed to variations in the prices and required

" extreme peak demands due to weather conditions, volumes of natural gas, oil, and coal we burn at our power

• available supply resources, plants to generate electricity. During periods of high demand on

" transportation availability and reliability within and our generation assets, our fuel supplies may be insufficient and between regions, could require us to procure additional fuiel at higher prices.

• location of our generating facilities relative to the Alternatively, during periods of low demand on our generation location of our load-serving obligations, assets, our fuel supplies may exceed our needs, and could result

" procedures used to maintain the integrity of the physical in us selling the excess fuels at lower prices. Either of these electricity system during extreme conditions, circumstances will have a negative impact on our financial

" changes in the nature and extent of federal and state results.

regulations, and 63

Operations Rs " fixing the price of a portion of anticipated fuel Operations risk is the risk that a generating plant will not be purchases for the operation of our power plants, available to produce energy and the risks related to physical " fixing the price for a portion of anticipated energy delivery of energy to meet our customers' needs. If one or more purchases to supply our load-serving customers, and of our generating facilities is not able to produce electricity " managing our exposure to interest rate risk and foreign when required due to operational factors, we may have to forego currency exchange risks.

sales opportunities or fulfill fixed-price sales commitments The portion of forecasted transactions hedged may vary through the operation of other more costly generating facilities based upon management's assessment of market, weather, or through the purchase of energy in the wholesale market at operational, and other factors.

higher prices. We purchase power from generating facilities we While some of the contracts we use to manage risk do not own. If one or more of those generating facilities were represent commodities or instruments for which prices are unable to produce electricity due to operational factors, we may available from external sources, other commodities and certain be forced to purchase electricity in the wholesale market at contracts are nor actively traded and are valued using other higher prices. This could have a material adverse impact on our pricing sources and modeling techniques to determine expected financial results. future market prices, contract quantities, or both. We use our Our nuclear plants produce electricity at a relatively low best estimates to determine the fair value of commodity and marginal cost. The Nine Mile Point facility and the Ginna derivative contracts we hold and sell. These estimates consider facility sell 90% and 80% of their respective output under various factors including closing exchange and over-the-counter unit-contingent power purchase agreements (we have no price quotations, time value, volatility factors, and credit obligation to provide power if the units are not available) to the exposure. However, it is likely that future market prices could previous owners. However, if an unplanned outage were to occur vary from those used in recording derivative assets and liabilities at Calvert Cliffs during periods when demand was high, we may subject to mark-to-market accounting, and such variations could have to purchase replacement power at potentially higher prices be material.

to meet our obligations, which could have, a material adverse We measure the sensitivity of our wholesale marketing and impact on our Financial results. risk management mark-to-market energy contracts to potential changes in market prices using value at risk. Value at risk is a Risk Managemnent and Trading statistical model that attempts to predict risk of loss based on As part of our overall portfolio, we manage the commodity price historical market price volatility. We calculate value at risk using risk of our competitive supply activities and our electric a historical variance/covariance technique that models option generation facilities, including power sales, fuel and energy positions using a linear approximation of their value.

purchases, emission credits, interest rate and foreign currency Additionally, we estimate variances and correlation using risks, weather risk, and the market risk of outages. In order to historical commodity price changes over the most recent rolling manage these risks, we may enter into fixed-price derivative or three-month period. Our value at risk calculation includes all non-derivative contracts to hedge the variability in future cash wholesale marketing and risk management derivative assets and flows from forecasted sales and purchases of energy, including: liabilities subject to mark-to-market accounting, including

" forward contracts, which commit 'us to purchase or sell contracts for energy commodities and derivatives that result in energy commodities in the future; physical settlement and contracts that require cash settlement.

• futures contracts, which are exchange-traded The value at risk calculation does nor include market risks standardized commitments to purchase or sell a associated with activities that are subject to accrual accounting, commodity or Financial instrument, or to make a cash primarily our generating facilities and our competitive supply settlement, at a specific price and future date; load-serving activities. We manage these risks by monitoring our

• swap agreements, which require payments to or from fuel and energy purchase requirements and our estimated couniterparties based upon the differential between two contract sales volumes compared to associated supply prices for a predetermined contractual (notional) arrangements. We also engage in hedging activities to manage quantity; and these risks. We describe those risks and our hedging activities

" option contracts, which convey the right to buy or sell a earlier in this section.

commodity, financial instrument, or index at a The value at risk amounts on the next page represent the predetermined price. potential pre-tax loss in the fair value of our wholesale marketing The objectives for entering into such hedges include: and risk management derivative assets and liabilities subject to

• fixing the price for a portion of anticipated future mark-to-market accounting over one and ten-day holding electricity sales at a level that provides an acceptable periods.

return on our electric generation operations, 64

Total Wholesale Value at Risk Due to the inherent limitations of statistical measures such For the year ended December 31, 2007 2006 as value at risk and the seasonality of changes in market prices, (In millions) the value at risk calculation may not reflect the full extent of 99% Confidence Level, One-Day Holding our commodity price risk exposure. Additionally, actual changes Period Year end $20.4 $13.4 in the value of options may differ from the value at risk Average 15.4 16.7 calculated using a linear approximation inherent in our High 26.8 28.0 calculation method. As a result, actual changes in the fair value Low 8.2 9.6 of derivative assets and liabilities subject to mark-to-market accounting could differ from the calculated value at risk, and 95% Confidence Level, One-Day Holding such changes could have a material impact on our financial Period 1 , results.

Year end Average 11.7 12.7 High 20.4 21.3 Regulated Electric Business Low 6.2 7.3 Our wholesale marketing, risk management, and trading operation provided BGE 100% of the energy and capacity to 95% Confidence Level, Ten-Day Holding meet its residential standard offer service obligations through Period Year end $49.1 $32.3 June 30, 2006. Bidding to supply BGE's standard offer service Average 37.0 40.2 to all customers occurs from time to time through a competitive High 64.6 67.4 bidding process approved by the Maryland PSC. Our wholesale Low 19.7 23.0 marketing, risk management, and trading operation is supplying Based on a 99% confidence interval, we would expect a a portion of BGE's standard offer service obligation to all one-day change in the fair value of the portfolio greater than or customers. We discuss standard offer service and the impact on equal to the daily value at risk approximately once in every base rates in more detail in Item 1. Business-Baltimore Gas and 100 days. In 2007, we did not experience any instance where Electric Company-Electric Business section.

the actual daily mark-to-market change in portfolio value BGE may receive performance assurance collateral from exceeded the predicted value at risk. However, published market suppliers to mitigate suppliers' credit risks in certain studies conclude that exceeding daily value at risk less than seven circumstances. Performance assurance collateral is designed to times in a one-year period is considered consistent with a 99% protect BGE's potential exposure over the term of the supply confidence interval. contracts and will fluctuate to reflect changes in market prices.

The table above is the value at risk associated with our In addition to the collateral provisions, there are supplier "step-up" provisions, where other suppliers can step in if the wholesale marketing, risk management, and trading operation's derivative assets and liabilities subject to mark-to-market early termination of a full-requirements service agreement with a accounting, including both trading and n6n-trading activities. supplier should occur, as well as specific mechanisms for BGE to We experienced higher value at risk for the year ended otherwise replace defaulted supplier contracts. All costs incurred December 31, 2007 compared to the year ended December 31, by BGE to replace the supply contract are to be recovered from 2006, primarily due to a higher number of economic hedges of the defaulting supplier or from customers through rates. Finally, accrual positions, increased volatility of commodity market BGE's exposure to uncollectible expense or credit risk from prices, and an increase in our trading activities discussed below. customers for the commodity portion of the bill is covered by We discuss our mark-to-market results in more detail in the the administrative fee included in Provider of Last Resort rates.

Competitive Supply section. Our regulated electric business may enter into electric The following table details our value at risk for the trading futures, options, and swaps to hedge its price risk. We discuss portion of our wholesale marketing and risk management this further in Note 13. At December 31, 2007 and 2006, our derivative assets and liabilities subject to mark-to-market exposure to commodity price risk for our regulated electric accounting over a one-day holding period at a 99% confidence business was not material.

level for 2007 and 2006:

Regulated Gas Business Wholesale Trading Value at Risk Our regulated gas business may enter into gas futures, options, For the year ended December 31, 2007 2006 and swaps to hedge its price risk under our market-based rate (In millions) incentive mechanism and our off-system gas sales program. We Average $11.0 $11f.2 discuss this further in Note 13. At December 31, 2007 and High 17.4 17.6 2006, our exposure to commodity price risk for our regulated Our trading positions can be used to. manage the gas business was not material.

commodity price risk of our competitive supply activities and our generation facilities. We also engage in trading activities for Credit Risk profit. These activities are managed through daily value at risk We are exposed to credit risk through our merchant energy and stop loss limits and liquidity guidelines. business and BGE's operations. Credit risk is the loss that may 65

result from counterparties' nonperformance and retail collections. coal and freight business combined with significant increases in We evaluate the credit risk of our wholesale marketing, risk coal prices and freight rates.

management, and trading operation and our retail activities A portion of our total wholesale credit risk is related to separately as discussed below. transactions that are recorded in our Consolidated Balance Sheets. These transactions primarily consist of open positions Wholesale Credit Risk from our wholesale marketing, risk management, and trading We measure wholesale credit risk as the replacement cost for operation that are accounted for using mark-to-market open energy commodity and derivative transactions (both accounting, as well as amounts owed by wholesale counterparties mark-to-market and accrual) adjusted for amounts owed to or for transactions that settled but have not yet been paid. The due from counterparties for settled transactions. The replacement following table highlights the credit quality and exposures related cost of open positions represents unrealized gains, net of any to these activities at December 31, 2007:

unrealized losses, where we have a legally enforceable right of Number of Net setoff We monitor and manage the credit risk of our wholesale Total Counterparties Exposure of marketing, risk management, and trading 'operation through Exposure Greater Counterparties Before than 10% Greater than credit policies and procedures which include an established credit Credit Credit Net of Net 10% of Net Rating Collateral Collateral Exposure Exposure Exposure approval process, daily monitoring of counterparty credit limits, the use of credit mitigation measures such' as margin, collateral, (Dollars in millions)

Investment grade $1,544 $278 $1,266 - $ -

or prepayment arrangements, and the use of master netting Split rating 73 - 73 - -

agreements. Non-investment grade 88 48 40 - -

As of December 31, 2007 and 2006, the credit portfolio of Internally rated-our wholesale marketing, risk management, and trading investment grade 321 70 251 - -

operation had the following public credit ratings: Internally rated-non-investment grade 395 48 347 - -

At December 31, I 2007 2006 Total $2,421 $444 $1,977 - $ -

Rating Investment Gradet 44% 61% Due to the possibility of extreme volatility in the prices of Non-Investment Grade 7 3 energy commodities and derivatives, the market value of Not Rated 49 36 contractual positions with individual counterparties could exceed I Includes counterpartieswith an investmentgrade rating by at established credit limits or collateral provided by those least one of the major credit rating agencies. If split rating exists, counterparties. If such a counterparty were then to fail to the lower rating is used. perform its obligations under its contract (for example, fail to deliver the electricity our wholesale marketing, risk management, Our exposure to "Not Rated" counterparties wa as and trading operation had contracted for), we could incur a loss

$2.1 billion at December 31, 2007 compared to $1. 1 billion at that could have a material impact on our financial results.

December 31, 2006. This increase was mostly due t.o an increase Additionally, if a counterparty were to default and we were in our credit portfolio related to natural gas, interna ublcoal to liquidate all contracts with that entity, our credit loss would customers, and freight companies that do not have ublic credit include the loss in value of derivative contracts recorded at fair ratings. Although not rated, many of these counterp arties are value, the amount owed for settled transactions, and additional considered investment grade equivalent based on oui payments, if any, that we would have to make to settle credit ratings. unrealized losses on accrual contracts. In addition, if a We utilize internal credit ratings to evaluate the counterparty were to default under an accrual contract that is creditworthiness of our wholesale customers, includirrg those currently favorable to us, we may recognize a material adverse companies that do not have public credit ratings. Ba or 33% of impact in our results in the future delivery period to the extent internal credit ratings, approximately $682.9 million ortmet 3 o that we are required to replace the contract that is in default the exposure to unrated counterparties was rated inv metment with another contract at current market prices. These potential grade equivalent at December 31, 2007 and approxi mately losses would be limited to the extent that the in-the-money

$643.8 million or 59% was rated investment grade equivalent at amount exceeded any credit mitigants such as cash, letters of December 31, 2006. The following table provides th ie credit, or parental guarantees supporting the counterparty breakdown of the credit quality of our wholesale cre dit portfolio obligation.

based on our internal credit ratings. We also enter into various wholesale transactions through At December 31, 2007 2006 ISOs. These ISOs are exposed to counterparry credit risks. Any losses relating to counterparty defaults impacting the ISOs are Investment Grade Equivalent 62% 82% allocated to and borne by all other market participants in the Non-Investment Grade 38 18 ISO. These ISOs have established credit policies and practices to The credit quality of our wholesale ciedit port olio declined mitigate the exposure of counterparty credit risks. As a market during 2007 as a result of the continued growth of our global 66

participant, we continuously assess our exposure to the credit Foreign Currency Risk risks of each ISO. Our merchant energy business is exposed to the impact of foreign exchange rate fluctuations. This foreign currency risk Retail Credit Risk arises from our activities in countries where we transact in We are exposed to retail credit risk through our competitive currencies other than the U.S. dollar. In 2007, our exposure to electricity and natural gas supply activities, which serve foreign currency risk was not material. However, we expect our commercial and industrial companies, and through BGE's foreign currency exposure to grow due to our Canadian operations. Retail credit risk results when customers default on operations, global power, coal, freight, and natural gas their contractual obligations. This risk represents the loss that operations, and our shipping and UniStar ventures. We manage may be incurred due to the nonpayment of customer accounts our exposure to foreign currency exchange rate risk using a receivable balances, as well as the loss from the resale of energy comprehensive foreign currency hedging program. While we previously committed to serve customers of our nonregulated cannot predict currency fluctuations, the impact of foreign retail businesses. currency exchange rate risk could be material.

Retail credit risk is managed through established credit policies, monitoring customer exposures, and the use of credit Equity Price Risk mitigation measures such as letters of credit or prepayment We are exposed to price fluctuations in equity markets primarily arrangements. through our pension plan assets, our nuclear decommissioning Our retail credit portfolio is well diversified with no trust funds, and trust assets securing certain executive benefits.

significant company or industry concentrations. During 2007, We are required by the NRC to maintain externally funded we did not experience a material change in the credit quality of trusts for the costs of decommissioning our nuclear power our retail credit portfolio compared to 2006. Retail credit quality plants. We discuss our nuclear decommissioning trust funds in is dependent on the economy and the ability of our customers more detail in Note 1.

to manage through unfavorable economic cycles and other A hypothetical 10% decrease in equity prices would result market changes. If the business environment were to be in an approximate $140 million reduction in the fair value of negatively affected by changes in economic or other market our financial investments that are classified as trading or conditions, our retail credit risk may be adversely impacted. available-for-sale securities. In 2007, our actual return on As a regulated entity, BGE is generally able to recover all pension plan assets was $71.3 million due to advances in the prudently incurred costs including uncollectible customer markets in which plan assets are invested. We describe our accounts receivable expenses. financial investments in more detail in Note 4, and our pension plans in Note 7.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk The information required by this item with respect to market risk is set forth in Item 7 of Part II of this Form 10-K under the heading Market Risk.

67

Item 8. Financial Statements and Supplementary Data REPRT OF. NIGMN FinancialStatements Constellation Energy's internal control over financial reporting as The management of Constellation Energy Group, Inc. and of December 31, 2007, as stated in their report on the next Baltimore Gas and Electric Company (the "Companies") is page.

responsible for the information and representations in the Companies' financial statements. The Companies prepare the financial statements in accordance with accounting principles generally accepted in the United States of America based upon Mayo A. Shattuck III John R. Collins available facts and circumstances and management's best Chairman of the Board, Executive Vice President and estimates and judgments of known conditions.

Presidentand ChiefExecutive Chief FinancialOfficer PricewaterhouseCoopers LLP, an independent registered Officer public accounting firm, has audited the financial statements and expressed their opinion on them. They performed their audit in Management's Report on Internal Control Over Financial accordance with the standards of the Public Company Reporting-Baltimore Gas and Electric Company Accounting Oversight Board (United States).

The management of Baltimore Gas and Electric Company The Audit Committee of the Board of Directors, which (BGE), under the direction of its principal executive officer and consists of five independent Directors, meets periodically with principal financial officer, is responsible for establishing and management, internal auditors, and PricewaterhouseCoopers LLP maintaining adequate internal control over financial reporting as to review the activities of each in discharging their defined in Exchange Act Rule 13a-15(f).

responsibilities. The internal audit staff and BGE's system of internal control over financial reporting is PricewaterhouseCoopers LLP have free access to the Audit designed to provide reasonable assurance to BGE's management Committee.

and Board of Directors regarding the reliability of financial reporting and the preparation of financial statements for external Management's Report on Internal Control Over Financial purposes in accordance with generally accepted accounting Reporting-ConstellationEnergy Group, Inc.

principles in the United States of America.

The management of Constellation Energy IGroup, Inc.

The management of BGE conducted an evaluation of the (Constellation Energy), under the direction of its principal effectiveness of BGE's internal control over financial reporting executive officer and principal financial officer, is responsible for using the framework in Internal Control-IntegratedFramework establishing and maintaining adequate internal control over issued by the Committee of Sponsoring Organizations of the financial reporting as defined in Exchange Act Rule 13a-15(f).

Treadway Commission (COSO). As noted in the COSO Constellation Energy's system of internal control over framework, an internal control system, no matter how well financial reporting is designed to provide reasonable assurance to conceived and operated, can provide only reasonable-not Constellation Energy's management and Board of Directors absolute-assurance to management and the Board of Directors regarding the reliability of financial reporting and the regarding achievement of an entity's financial reporting preparation of financial statements for external purposes in objectives. Based upon the evaluation under this framework, accordance with generally accepted accounting principles in the management concluded that BGE's internal control over United States of America.

financial reporting was effective as of December 31, 2007.

The management of Constellation Energy conducted an This annual report does not include an attestation report of evaluation of the effectiveness of Constellation Energy's internal BGE's independent registered public accounting firm regarding control over financial reporting using the framework in Internal internal control over financial reporting. Management's report Control-IntegratedFramework issued by the Committee of was not subject to attestation by BGE's independent registered Sponsoring Organizations of the Treadway Commission public accounting firm pursuant to temporary rules of the (COSO). As noted in the COSO framework, an internal control Securities and Exchange Commission that permit BGE to system, no matter how well conceived and operated, can provide provide only management's report in this annual report.

only reasonable-not absolute-assurance to management and the Board of Directors regarding achievement of an entity's financial reporting objectives. Based upon the evaluation under this framework, management concluded that Constellation Energy's Kenneth W DeFontes, Jr. John R. Collins internal control over financial reporting was effective as of President and Chief Executive Senior Vice President and Chief December 31, 2007.

Officer FinancialOfficer PricewaterhouseCoopers LLP, an independent registered public accounting firm, has audited the effectiveness of 68

REPRT OF .NIPN TRGSEE PBI CONIGFR To the Board of Directors and Shareholders of changed its method of accounting for defined benefit pension Constellation Energy Group, Inc. and other postretirement plans. As discussed in Note I to the In our opinion, the consolidated financial statements listed in consolidated financial statements, in 2005 the Company changed the index appearing under Item 15(a) (1) present fairly, in all its method of accounting for conditional asset retirement material respects, the financial position of Constellation Energy obligations and for stock based compensation.

Group, Inc. and its subsidiaries (the Company) at December 31, A company's internal control over financial reporting is a 2007 and 2006, and the results of their operations and their process designed to provide reasonable assurance regarding the cash flows for each of the three years in the period ended reliability of financial reporting and the preparation of financial December 31, 2007 in conformity with accounting principles statements for external purposes in accordance with generally generally accepted in the United States of America. In addition, accepted accounting principles. A company's internal control in our opinion, the financial statement schedule listed in the over financial reporting includes those policies and procedures index appearing under Item 15(a) (2) presents fairly, in all that (i) pertain to the maintenance of records that, in reasonable material respects, the information set forth therein when read in detail, accurately and fairly reflect the transactions and conjunction with the related consolidated financial statements. dispositions of the assets of the company; (ii) provide reasonable Also in our opinion, the Company maintained, in all material assurance that transactions are recorded as necessary to permit respects, effective control over financial reporting as of preparation of financial statements in accordance with generally December 31, 2007, based on criteria established in Internal accepted accounting principles, and that receipts and Control-IntegratedFramework issued by the Committee of expenditures of the company are being made only in accordance Sponsoring Organizations of the Treadway Commission with authorizations of management and directors of the (COSO). The Company's management is responsible for these company; and (iii) provide reasonable assurance regarding financial statements and financial statement schedule, for prevention or timely detection of unauthorized acquisition, use, maintaining effective control over financial reporting and for its or disposition of the company's assets that could have a material assessment of the effectiveness of internal control over financial effect on the financial statements.

reporting, included in Management's Report on Internal Control Because of its inherent limitations, internal control over Over Financial Reporting appearing under Item 8. Our financial reporting may not prevent or detect misstatements.

responsibility is to express opinions on these financial statements, Also, projections of any evaluation of effectiveness to future on the financial statement schedule, and on the Company's periods are subject to the risk that controls may become internal control over financial reporting based on our integrated inadequate because of changes in conditions, or that the degree audits. We conducted our audits in accordance with the of compliance with the policies or procedures may deteriorate.

standards of the Public Company Accounting Oversight Board We have also previously audited, in accordance with the (United States). Those standards require that we plan and standards of the Public Company Accounting Oversight Board perform the audits to obtain reasonable assurance about whether (United States), the consolidated balance sheets and statements the financial statements are free of material misstatement and of capitalization of Constellation Energy Group, Inc. and its whether effective internal control over financial reporting was subsidiaries as of December 31, 2005, 2004, and 2003, and the maintained in all material respects. Our audits of the financial related consolidated statements of income, cash flows, and statements include examining, on a test basis, evidence common shareholders' equity and comprehensive income for the supporting the amounts and disclosures in the financial years ended December 31, 2004 and 2003 (none of which are statements, assessing the accounting principles used and presented herein); and we expressed unqualified opinions on significant estimates made by management, and evaluating the those consolidated financial statements. In our opinion, the overall financial statement presentation. Our audit of internal information set forth in the Summary of Operations and control over financial reporting included obtaining an Summary of Financial Condition of Constellation Energy understanding of internal control over financial reporting, Group, Inc. and its subsidiaries included in the Selected assessing the risk that a material weakness exists, and testing and Financial Data appearing under Item 6 for each of the five years evaluating the design and operating effectiveness of internal in the period ended December 31, 2007, is fairly stated, in all control based on the assessed risk. Our audits also included material respects, in relation to the consolidated financial performing such other procedures as we considered necessary in statements from which it has been derived.

the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As discussed in Note 1 to the consolidated financial PricewaterhouseCoopers LLP statements, in 2007 the Company changed its method of accounting for uncertain tax positions. As ,discussed in Note 7 to Baltimore, Maryland the consolidated financial statements, in 2006 the Company February 26, 2008 69

To Board of Directors and Shareholder of Baltimore Gas and presentation. We believe that our audits provide a reasonable Electric Company basis for our opinion.

In our opinion, the consolidated financial statements listed in As discussed in Note I to the consolidated financial the index appearing under Item 15(a) (1) present fairly, in all statements, in 2007 the Company changed its method of material respects, the financial position of Baltimore Gas and accounting for uncertain tax positions.

Electric Company and its subsidiaries (the. Company) at We have also previously audited, in accordance with the December 31, 2007 and 2006, and the results of their standards of the Public Company Accounting Oversight Board operations and their cash flows for each of the three years in the (United States), the consolidated balance sheets of Baltimore Gas period ended December 31, 2007 in conformity with accounting and Electric Company and its subsidiaries as of December 31, principles generally accepted in the United States of America. In 2005, 2004 and 2003, and the related consolidated statements addition, in our opinion, the financial statement schedule listed of income, cash flows, and comprehensive income for the years in the index appearing under Item 15(a) (2) presents fairly, in all ended December 31, 2004 and 2003 (none of which are material respects, the information set forth therein when read in presented herein); and we expressed unqualified opinions on conjunction with the related consolidated financial statements. those consolidated financial statements. In our opinion, the These financial statements and financial statement schedule are information set forth in the Summary of Operations and the responsibility of the Company's management. Our Summary of Financial Condition of Baltimore Gas and Electric responsibility is to express an opinion on these financial Company and its subsidiaries included in the Selected Financial statements and financial statement schedule based on our audits. Data appearing under Item 6 for each of the five years in the We conducted our audits of these statements in accordance with period ended December 31, 2007, is fairly stated, in all material the standards of the Public Company Accounting Oversight respects, in relation to the consolidated financial statements from Board (United States). Those standards require that we plan and which it has been derived.

perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing PricewaterhouseCoopers LLP the accounting principles used and significant estimates made by Baltimore, Maryland management, and evaluating the overall finsancial statement February 26, 2008 70

Constellation Energy Group, Inc. and Subsidiaries Year Ended December 31, 2007 2006 2005 (In millions, except per share amounts)

Revenues Nonregulated revenues $17,794.6 $16,279.0 $13,970.1 Regulated electric revenues 2,455.6 2,115.9 2,036.5 Regulated gas revenues 943.0 890.0 961.7 Total revenues 21,193.2 19,284.9 16,968.3 Expenses Fuel and purchased energy expenses 16,473.9 14,930.7 13,239.6 Operating expenses 2,447.4 2,165.8 1,900.7 Impairment losses and other costs 20.2 - -

Workforce reduction costs 2.3 28.2 4.4 Merger-related costs - 18.3 17.0 Depreciation, depletion, and amortization 557.8 523.9 523.0 Accretion of asset retirement obligations 68.3 67.6 62.0 Taxes other than income taxes 288.9 290.7 277.1 Total expenses 19,858.8 18,025.2 16,023!8 Gain on Sale of Gas-Fired Plants - 73.8 Income from Operations 1,334.4 1,333.5 944.5 Gain on Sales of CEP Equity 63.3 28.7 -

Other Income, primarily interest income 158.6 66.1 65.5 Fixed Charges Interest expense 311.8 329.2 306.9 Interest capitalized and allowance for borrowed funds used during construction (19.4) (13.7) (9.9)

BGE preference stock dividends 13.2 13.2 13.2 Total fixed charges 305.6 328.7 310.2 Income from Continuing Operations Before Income Taxes 1,250.7 1,099.6 699.8 Income Tax Expense 428.3 351.0 163.9 Income from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles 822.4 748.6 535.9 (Loss) Income from discontinued operations, net of income taxes of $1.5,

$107.7, and $61.6, respectively (0.9) 187.8 94.4 Cumulative effects of changes in accounting principles, net of income taxes of $(4.7) - - (7.2)

Net Income $ 821.5 $ 936.4 $ 623.1 Earnings Applicable to Common Stock $ 821.5 $ 936.4 $ 623.1 Average Shares of Common Stock Outstanding-Basic 180.2 179.4 177.5 Average Shares of Common Stock Outstanding-Diluted 182.5 181.4 179.7 Earnings Per Common Share from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles-Basic $ 4.56 $ 4.17 $ 3.02 (Loss) Income from discontinued operations (0.01) 1.05 0.53 Cumulative effects of changes in accounting principles - - (0.04)

Earnings Per Common Share-Basic $ 4.55 $ 5.22 $ 3.51 Earnings Per Common Share from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles-Diluted $ 4.51 $ 4.12 $ 2.98 (Loss) Income from discontinued operations (0.01) 1.04 0.53 Cumulative effects of changes in accounting principles - - (0.04)

Earnings Per Common Share-Diluted $ 4.50 $ 5.16 $ 3.47 Dividends Declared Per Common Share $ 1.74 $ 1.51 $ 1.34 See Notes to Consolidated FinancialStatements.

71

C Ih . BALAN]* E]

Constellation Energy Group, Inc. and Subsidiaries At December 31, 2007 2006 (In millions)

Assets Current Assets Cash and cash equivalents $ 1,095.9 $ 2,289.1 Accounts receivable (net of allowance for uncollectibles of $44.9 and $48.9, respectively) 4,289.5 3,248.3 Fuel stocks 591.3 599.5 Materials and supplies 207.5 200.2 Derivative assets 961.2 1,556.5 Unamortized energy contract assets 32.0 35.2 Deferred income taxes 300.7 674.3 Other 410.9 497.0 Total current assets 7,889.0 9,100.1 Investments and Other Noncurrent Assets Nuclear decommissioning trust funds; 1,330.8 1,240.1 Other investments 542.2 308.6 Regulatory assets (net) 576.2 389.0 Goodwill 261.3 157.6 Derivative assets 1,030.2 949.1 Unamortized energy contract assets 178.3 123.6 Other 370.6 311.4 Total investments and other noncurrent assets 4,289.6 3,479.4 Property, Plant and Equipment Nonregulated property, plant and equipment 8,087.0 7,587.6 Regulated property, plant and equipment 6,051.2 5,752.9 Nuclear fuel (net of amortization) 374.3 339.9 Accumulated depreciation (4,745.4) (4,458.3)

Net property, plant and equipment 9,767.1 9,222.1 Total Assets $21,945.7 $21,801.6 See Notes to Consolidated FinancialStatements.

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

72

Constellation Energy Group, Inc. and Subsidiaries At December 31, 2007 2006 (In millions)

Liabilities and Equity Current Liabilities Short-term borrowings $ 14.0 $ -

Current portion of long-term debt 380.6 878.8 Accounts payable and accrued liabilities 2,630.1 2,137.2 Customer deposits mid collateral 347.2 347.2 Derivative liabilities 1,137.1 2,411.7 Unamortized energy contract liabilities 392.2 378.3 Accrued expenses 528.5 619.8 Other 427.5 349.7 Total current liabilities 5,857.2 7,122.7 Deferred Credits and Other Noncurrent Liabilities Deferred income taxes 1,588.5 1,435.8 Asset retirement obligations 917.6 974.8 Derivative liabilities 1,118.9 1,099.7 Unamortized energy contract liabilities 1,218.6 958.0 Defined benefit obligations 828.6 928.3 Deferred investment tax credits 50.5 57.2 Other 155.9 109.0 Total deferred credits and other noncurrent liabilities 5,878.6 5,562.8 Capitalization (See Consolidated Statements of Capitalization)

Long-term debt 4,660.5 4,222.3 Minority interests 19.2 94.5 BGE preference stock not subject to mandatory redemption 190.0 190.0 Common shareholders' equity 5,340.2 4,609.3 Total capitalization 1 10,209.9 9,116.1 Commitments, Guarantees, and Contingencies (see Note 12)

Total Liabilities and Equity $21,945.7 $21,801.6 See Notes to Consolidated FinancialStatements.

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

73

COSLIAE STTMET OF CAS FLOS Constellation Energy Group, Inc. and Subsidiaries Year Ended December 31, 2007 2006 2005 (In millions)

Cash Flows From Operating Activities Net income $ 821.5 $ 936.4 $ 623.1 Adjustments to reconcile to net cash pro~tided by operating activities Gain on sales of gas-fired plants and discontinued operations (191.4) (13.8)

Cumulative effects of changes in accounting principles 7.2 Depreciation, depletion, and amortization 460.4 545.1 606.5 Accretion of asset retirement obligations 68.3 67.6 62.1 Deferred income taxes 226.2 128.0 136.9 Investment tax credit adjustments (6.7) (6.9) (7.1)

Deferred fusel costs (248.0) (348.5) (11.9)

Defined benefit obligation expense 111.8 129.7 94.2 Defined benefit obligation payments (165.4) (89.2) (90.8)

Impairment losses and other costs 20.2 Gains on sale of CEP equity (63.3) (28.7)

Equity in earnings of affiliates less thaii dividends received 45.3 27.6 38.7 Derivative power sales contracts classified as financing activities under SIAS No. 149 32.2 2.6 (72.6)

Changes in Accounts receivable (778.2) (653.7) (961.2)

Derivative assets and liabilities (138.2) (286.1) (88.2)

Materials, supplies, and fuel stocks (66.4) (267.2) (250.3)

Other current assets 145.1 240.6 (277.1)

Accounts payable and accrued liabilities 448.8 380.5 282.8 Other current liabilities 15.7 (91.8) 546.4 Other (1.5) 30.7 2.3 Net cash provided by operating activities 927.8 525.3 627.2 Cash Flows From Investing Activities Investments in property, plant and equipment (1,295.7) (962.9) (760.0)

Asset acquisitions and business combinations, net of cash acquired (347.5) (137.6) (237.2)

Investments in nuclear decommissioning trust fund securities (659.5) (492.5) (370.8)

Proceeds from nuclear decommissioning trust fund securities 650.7 483.7 353.2 Net proceeds from sale of gas-fired plants and discontinued operations - 1,630.7 289.4 Issuances of loans receivable (19.0) (65.4) (82.8)

Sale of investments and other assets 13.9 43.9 14.4 Contract and portfolio acquisitions (474.2) (2.3) (336.2)

(Increase) decrease in restricted funds (109.9) 7.7 (4.0)

Other investments (45.3) 54.8 (40.0)

Net cash (used in) provided by investingactivities (2,286.5) 560.1 (1,174.0)

Cash Flows From Financing Activities Net issuance (maturity) of short-term borrowings 14.0 (0.7) 10.7 Proceeds from issuance of Common stock 65.1 84.4 96.9 Long-term debt 698.2 852.0 12.0 Proceeds from initial public offering of CEP - 101.3 Common stock dividends paid (306.0) (264.0) (228.'8)

Reacquisition of common stock (409.5) -

Proceeds from contract and portfolio acquisitions 847.8 221.3 1,026.9 Repayment of long-term debt (745.3) (609.1) (362.3)

Derivative power sales contracts classified'as financing activities under SIAS No. 149 (32.2) (2.6) 72.6 Other 33.4 8.1 25.5 Net cash provided by financing activities, 165.5 390.7 653.5 Net (Decrease) Increase in Cash and Cash Equivalents (1,193.2) 1,476.1 106.7 Cash and Cash Equivalents at Beginning of Year 2,289.1 813.070.

Cash and Cash Equivalents at End of Year $ 1,095.9 $ 2,289.1 $ 813.0 Other Cash Flow Information:

Cash paid during the year for:

Interest (net of amounts capitalized) $ 291.8 $ 304.7 $ 301.3 Income taxes $ 282.4 $ 109.3 $ 115.3 See Notes to Consolidated Financial Statements.

Certain prior-year amounts have been reclassified to conform witb tbe currentyear's presentation.

74

o st ai E g G SI I I I Iia Constellation Energy Group, Inc. and Subsidiaries Accumulated Other Common Stock Retained Comprehensive Total Year Ended December 31, 2007, 2006, and 2005 Shares Amount Earnings Loss Amount (Dollar amounts in millions, number of shares in thousands)

Balance at December 31, 2004 176,333 $2,502.5 $2,425.9 $ (201.5) $ 4,726.9 Comprehensive Income Net income 623.1 623.1 Other comprehensive income Hedging instruments:

Reclassification of net gains on hedging instruments from OCI to net income, net of taxes of $492.2 (794.6) (794.6)

Net unrealized gain on hedging instruments, net of taxes of $335.9 534.7 534.7 Available-for-sale securities:

Reclassification of net gains on securities from OCI to net income, net of taxes of $1.2 (1.8) (1.8)

Net unrealized gain on securities, net of taxes of $15.7 23.8 23.8 Minimum pension liability, net of taxes of $50.4 (77.1) (77.1)

Net unrealized gain on foreign currency translation 1.0 1.0 Total Comprehensive Income 623.1 (314.0) 309.1 Common stock dividend declared ($1.34 per share) (238.4) (238.4)

Common stock issued and share-based awards 1,968 118.3 118.3 Other (0.4) (0.4)

Balance at December 31, 2005 178,301 2,620.8 2,810.2 (515.5) 4,915.5 Comprehensive Income Net income 936.4 936.4 Other comprehensive income Hedging instruments:

Reclassification of net losses on hedging instruments from OCI to net income, net of taxes of $375.6 620.8 620.8 Net unrealized loss on hedging instruments, net of taxes of

$1,025.8 (1,683.4) (1,683.4)

Available-for-sale securities:

Reclassification of net gains on securities from OCI to net income, net of taxes of $0.1 (0.2) (0.2)

Net unrealized gain on securities, net of taxes of $45.5 69.7 69.7 Minimum pension liability, net of taxes of $49.6 75.6 75.6 Net unrealized loss on foreign currency translation (1.1) (1.1)

Total Comprehensive Income 936.4 (918.6) 17.8 Effect of adoption of SFAS No. 158, net of taxes of $111.3 (169.5) (169.5)

Common stock dividend declared ($1.51 per share) (272.6) (272.6)

Common stock issued and share-based awards 2,218 117.8 117.8 Other 0.3 0.3 Balance at December 31, 2006 180,519 2,738.6 3,474.3 (1,603.6) 4,609.3 Comprehensive Income Net income 821.5 821.5 Other comprehensive income Hedging instruments:

Reclassification of net losses on hedging instruments from OCI to net income, net of taxes of $682.3 ' 1,124.8 1,124.8 Net unrealized loss on hedging instruments, net of taxes of $408.2 (671.1) (671.1)

Available-for-sale securities:

Reclassification of net gains on securities from OCI to net income, net of taxes of $1.0 (1.6) (1.6)

Net unrealized gain on securities, net of taxes of $25.5 26.5 26.5 Defined benefit plans:

Net gain arising during period, net of taxes of $7.8 11.6 11.6 Amortization of net actuarial loss, prior service cost, and transition obligation included in net periodic benefit cost, net of taxes of $15.9 24.6 24.6 Net unrealized gain on foreign currency translation, net of taxes of

$1.8 7.0 7.0 Other (10.8) (10.8)

Total Comprehensive Income 821.5 511.0 1,332.5 Effect of adoption of FIN 48 (7.3) (7.3)

Common stock dividend declared ($1.74 per share) (368.4) (368.4)

Common stock issued and share-based awards 1,789 184.2 184.2 Common stock purchased (1,847) (159.5) (159.5)

Common stock purchased and retired (2,024) (250.0) (250.0)

Other (0.6) (0.6)

Balance at December 31, 2007 178,437 $2,513.3 $3,919.5 $(1,092.6) $ 5,340.2 See Notes to Consolidated FinancialStatements.

75

COSOLIA.E STAEMN S OFCPTLZTO Constellation Energy Group, Inc. and Subsidiaries At December 31, 2007 2006 (In millions)

Long-Term Debt Long-term debt of Constellation Energy 6.35% Fixed-Rate Notes, due April 1, 2007 $ - $ 600.0 6.125% Fixed-Rate Notes, due September 1, 2009 500.0 500.0 7.00% Fixed-Rate Notes, due April 1, 2012 700.0 700.0 4.55% Fixed-Rate Notes, due June 15, 2015 550.0 550.0 7.60% Fixed-Rate Notes, due April 1, 2032 700.0 700.0 Fair Value of Interest Rate Swaps 11.8 (7.1)

Total long-term debt of Constellation Energy 2,461.8 3,042.9 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 4.10% Pollution control loan, due July 1, 2014 20.0 20.0 Economic development loan, due December 1, 2018 35.0 35.0 Floating-rate pollution control loan, due June 1, 2027 8.8 8.8 Tax-exempt variable rate notes, due April 1, 2024 75.0 75.0 Tax-exempt variable rate notes, due December 1, 2025 47.0 47.0 Tax-exempt variable rate notes, due December 1, 2037 65.0 -

District Cooling facilities loan, due December 1, 2031 25.0 25.0 CEP credit facility loan, due October 31, 2010 - 22.0 5.00% Mortgage note, due June 15, 2010 3.6 7.5 4.25% Mortgage note, due March 15, 2009 0.8 1.3 7.3% Fixed Rate Note, due June 1, 2012 1.8 1.8 South Carolina synthetic fuel facility loan, due January 15, 2008 (imputed interest rate of 3.47%) 3.0 20.0 Total long-term debt of nonregulated businesses 369.0 347.4 First Refunding Mortgage Bonds of BGE 7.50% Series, due January 15, 2007 - 121.4 6.625% Series, due March 15, 2008 119.7 123.1 Total First Refunding Mortgage Bonds of BGE 119.7 244.5 Other long-term debt of BGE 5.90% Notes, due October 1, 2016 300.0 300.0 5.20% Notes, due June 15, 2033 200.0 200.0 6.35% Notes, due October 1, 2036 400.0 400.0 Medium-term notes, Series E 174.5 174.5 Medium-term notes, Series G 140.0 140.0 Total other long-term debt of BGE 1,214.5 1,214.5 6.20% deferrable interest subordinated debentures due October 15, 2043 to BGE wholly owned BGE Capital Trust II relating to trust preferred securities 257.7 257.7 5.683% Rate stabilization bonds due April 1, 2017 623.2 -

Unamortized discount and premium (4.8) (5.9)

Current portion of long-term debt (380.6) (878.8)

Total long-term debt $4,660.5 $4,222.3 See Notes to Consolidated FinancialStatements.

continued on next page 76

CONSOIAE STT. INS OF CAIAIZTO Constellation Energy Group, Inc. and Subsidiaries At December 31, 2007 2006 (In millions)

Minority Interests $ 19.2 $ 94.5 BGE Preference Stock Cumulative preference stock not subject to mandatory redemption, 6,500,000 shares authorized 7.125%, 1993 Series, 400,000 shares outstanding, callable at $102.14 per share until June 30, 2008, and at lesser amounts thereafter 40.0 40.0 6.97%, 1993 Series, 500,000 shares outstanding, callable at $102.09 per share until September 30, 2008, and at lesser, amounts thereafter 50.0 50.0 6.70%, 1993 Series, 400,000 shares 'outstanding, callable at $102.01 per share until December 31, 2008, and at lesser-amounts thereafter 40.0 40.0 6.99%, 1995 Series, 600,000 shares 'outstanding, callable at $102.80 per share until September 30, 2008, and at lesser amounts thereafter 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; 178,437,208 and 180,519,180 shares issued and outstanding at December 31, 2007 and 2006, respectively.

(At December 31, 2007, 9,244,969 shares were reserved for the long-term incentive plans, 7,208,691 shares were reserved for the Shareholder Investment Plan, 1,520,000 shares were reserved for the continuous offering programs, and 1,508,553 shares were reserved for the employee savings plan.) 2,513.3 2,738.6 Retained earnings 3,919.5 3,474.3 Accumulated other comprehensive loss (1,092.6) (1,603.6)

Total common shareholders' equity 5,340.2 4609.3 Total Capitalization $10,209.9 $9,116.1 See Notes to Consolidated FinancialStatements.

77

COSLIAE STTMET I OF COME Baltimore Gas and Electric Company and Subsidiaries Year Ended December 31, 2007 2006 2005 (Inmillions)

Revenues Electric revenues $2,455.7 $2,115.9 $2,036.5 Gas revenues 962.8 899.5 972.8 Total revenues 3,418.5 3,015.4 3,009.3 Expenses Olperating Expenses Electricity purchased for resale 1,500.4 1,167.8 1,068.9 Gas purchased for resale 639.8 581.5 687.5 Operations and maintenance 533.6 496.1 450.2 Merger-related costs - 4.7 5.4 Depreciation and amortization 234.2 227.5 232.4 Taxes other than income taxes 176.2 168.7 168.4 Total expenses 3,084.2 2,646.3 2,612.8 Income from Operations 334.3 369.1 396.5 Other income 26.8 6.0 5.9 Fixed Charges 49.

Interest expense 127.9 104.6 9.

Allowance for borrowed funds used during construction (2.6) (2.0) (2.1)

Total fixed charges 125.3 102.6 93.5 Income Before Income Taxes 235.8 272.5 308.9 Income Taxes Current (2.4) (22.8) 122.6 Deferred 100.0 126.6 (0.9)

Investment tax credit adjustments (1.6) (1.6) (1.8)

Total income taxes 96.0 102.2 119.9 Net Inscome 139.8 170.3 189.0 Preference Stock Dividends 13.2 13.2 13.2 Earnings Applicable to Common Stock $ 126.6 $ 157.1 $ 175.8 See Notes to Consolidated FinancialStatements 78

CONSOIAE BA LACSET Baltimore Gas and Electric Company and Subsidiaries At December 31, 2007 2006 I (In millions)

Assets Current Assets Cash and cash equivalents $ 17.6 $ 10.9 Accounts receivable (net of allowance for uncollectibles of $20.3 and $15.5, respectively) 316.7 190.3 Accounts receivable, unbilled (net of'allowance for uncollectibles of $0.8 and $0.6, respectively) 209.5 154.4 Investment in cash pool, affiliated company 78.4 60.6 Accounts receivable, affiliated companies 4.2 2.5 Fuel stocks 98.8 110.9 Materials and supplies 42.7 40.2 Prepaid taxes other than income taxes 49.9 48.0 Regulatory assets (net) 74.9 62.5 Other 46.6 35.2 Total current assets 939.3 715.5 Investments and Other Assets Regulatory assets (net) 576.2 389.0 Receivable, affiliated company 149.2 150.5 Other 148.1 127.5 Total investments and other assets 873.5 667.0 Utility Plant Plant in service Electric 4,244.4 4,060.2 Gas 1,181.7 1,148.3 Common 456.1 444.6 Total plant in service 5,882.2 5,653.1 Accumulated depreciation (2,080.8) (1,994.7)

Net plant in service 3,801.4 3,658.4 Construction work in progress 166.4 97.1 Plant held for future use 2.4 2.7 Net utility plant 3,970.2 3,758.2 Total Assets $ 5,783.0 $ 5,140.7 See Notes to Consolidated FinancialStatements.

Certainprior-periodamounts have been reclassified to conform with the current period'spresentation.

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Baltimore Gas and Electric Company and Subsidiaries At December 31, 2007 2006 (In millions)

Liabilities and Equity Current Liabilities Current portion of long-term debt $ 375.0 $ 258.3 Accounts payable and accrued liabilities 182.4 187.3 Accounts payable and accrued liabilities, affiliated companies 164.5 163.4 Customer deposits 70.5 71.4 Current portion of deferred income taxes 44.1 47.4 Accrued taxes 34.4 18.8 Accrued expenses and other 96.3 79.5 Total current liabilities 967.2 826.1 Deferred Credits and Other Liabilities Deferred income taxes 785.6 697.7 Payable, affiliated company 243.7 250.7 Deferred investment tax credits 11.9 13.5 Other 33.6 14.0 Total deferred credits and other liabilities 1,074.8 975.9 Long-term Debt Rate stabilization bonds 623.2 -

First refunding mortgage bonds of BGE 119.7 244.5 Other long-term debt of BGE 1 1,214.5 1,214.5 6.20% deferrable interest subordinated debentures due October 15, 2043 to wholly owned BGE Capital Trust II relating to trust preferred securities 257.7 257.7 Long-term debt of nonregulated business 25.0 25.0 Unamortized discount and premium (2.6) (2.9)

Current portion of long-term debt (375.0) (258.3)

Total long-term debt 1,862.5 1,480.5 Minority Interest 16.8 16.7 Preference Stock Not Subject to Mandatory Redemption 190.0 190.0 Common Shareholder's Equity Common stock 912.2 912.2 Retained earnings 758.8 738.6 Accumulated other comprehensive income 0.7 0.7 Total common shareholder's equity 1,671.7 1,651.5 Commitments, Guarantees, and Contingencies (see Note 12)

Total Liabilities and Equity $5,783.0 $5,140.7 See Notes to Consolidated FinancialStatements.

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CONSOIAE STTMET F CAS FLW Baltimore Gas and Electric Company and Subsidiaries Year Ended December 31, 2007 2006 2005 (In millions)

Cash Flows From Operating Activities Net income $ 139.8 $ 170.3 $ 189.0 Adjustments to reconcile to net cash provided by operating activities Depreciation and amortization 246.7 241.1 250.5 Deferred income taxes 99.9 126.6 (0.9)

Investment tax credit adjustments (1.5) (1.7) (1.8)

Deferred fuel costs (248.0) (348.5) (11.9)

Defined benefit plan expenses 39.8 47.2 37.8 Allowance for equity funds used during construction (4.9) (3.7) (3.9)

Changes in Accounts receivable (181.5) 135.8 (98.7)

Receivables, affiliated companies (1.7) (0.7) (0.8)

Materials, supplies, and fuel stocksý 9.6 (8.2) (21.7)

Other current assets 25.9 (31.0) (0.5)

Accounts payable and accrued liabilities (4.9) 17.6 44.3 Accounts payable and accrued liabi'lities, affiliated companies 1.1 10.6 6.7 Other current liabilities 29.6 (0.9) 12.0 Long-term receivables and payables, affiliated companies (42.0) (70.1) (42.9)

Other 1 (44.7) (27.5) (37.4)

Net cash provided by operating activities 63.2 256.9 319.8 Cash Flows From Investing Activities Utility construction expenditures (excluding equity portion of allowance for funds used during construction) (376.4) (320.6) (270.5)

Change in cash pool at parent (17.8) (63.8) 131.1 Sales of investments and other assets 0.8 (0.4) 11.0 (Increase) decrease in restricted funds (42.3) 10.3 (10.4)

Net cash used in investing activities (435.7) (374.5) (138.8)

Cash Flows From Financing Activities Proceeds from issuance of long-term debt 623.2 700.0 Repayment of long-term debt (124.8) (445.3) (41.6)

Preference stock dividends paid (13.2) (13.2) (13.2)

Distribution to parent (106.0) (128.1) (119.3)

Net cash provided by (used in) financing activities 379.2 113.4 (174.1)

Net Increase (Decrease) in Cash and Cash Equivalents 6.7 (4.2) 6.9 Cash and Cash Equivalents at Beginning of Year 10.9 15.1 8.2 Cash and Cash Equivalents at End of Year $ 17.6 $ 10.9 $ 15.1 Other Cash Flow Information:

Cash paid (received) during the year for:

Interest (net of amounts capitalized) $ 126.3 $ 87.2 $ 88.6 Income taxes $ (37.6) $ 18.7 $ 123.3 See Notes to Consolidated FinancialStatements.

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Notes to Consolida, ed Financial Statements!

I Significant Accounting Policies Nature of Our Business The only time we do not use this method is if we can Constellation Energy Group, Inc. (Constellation Energy) is an exercise control over the operations and policies of the company.

energy company that conducts its business through various If we have control, accounting rules require us to use subsidiaries including a merchant energy business and Baltimore consolidation.

Gas and Electric Company (BGE). Our merchant energy business is a competitive provider of energy solutions for a The Cost Method variety of customers. BGE is a regulated electric transmission We usually use the cost method if we hold less than a 20%

and distribution utility company and a regulated gas distribution voting interest in an investment. Under the cost method, we utility company with a service territory that covers the City of report our investment at cost in our Consolidated Balance Baltimore and all or part of ten counties in central Maryland. Sheets. The only time we do not use this method is when we We describe our operating segments in Note 3. can exercise significant influence over the operations and policies This report is a combined report of Constellation Energy of the company. If we have significant influence, accounting and BGE. References in this report to "we" and "our" are to rules require us to use the equity method.

Constellation Energy and its subsidiaries. References in this report to the "regulated business(es)" are to BGE. Sale of Subsidiary Stock We may sell portions of our ownership interests through public Consolidation Policy offerings of a subsidiary's stock. We record any gains or losses on We use three different accounting methodý to report our public offerings in our Consolidated Statements of Income, as a investments in our subsidiaries or other companies: component of non-operating income.

consolidation, the equity method, and the'cost method.

Regulation of Electric and Gas Business Consolidation The Maryland Public Service Commission (Maryland PSC) and We use consolidation for two types of entities: the Federal Energy Regulatory Commission (FERC) provide the

" subsidiaries (other than variable interest entities) in final determination of the rates we charge our customers for our which we own a majority of the voting stock, and regulated businesses. Generally, we use the same accounting

" variable interest entities (VIEs) for which we are the policies and practices used by nonregulated companies for primary beneficiary. Financial Accounting Standards financial reporting under accounting principles generally Board (FASB) Interpretation No. (FIN) 46R, accepted in the United States of America. However, sometimes Consolidation of Variable Interest Entities, requires us to the Maryland PSC or the FERC orders an accounting treatment use consolidation when we are the primary beneficiary different from that used by nonregulated companies to of a VIE, which means that we have a controlling determine the rates we charge our customers.

financial interest in a VIE. We discuss our investments When this happens, we must defer (include as an asset or in VIEs in more detail in Note 4. liability in our, and BGE's, Consolidated Balance Sheets and Consolidation means that we combine the accounts of these exclude from our, and BGE's, Consolidated Statements of entities with our accounts. Therefore, our consolidated financial Income) certain regulated business expenses and income as statements include our accounts, the accounts of our majority- regulatory assets and liabilities. We have recorded these owned subsidiaries that are not VIEs, and the accounts of VIEs regulatory assets and liabilities in our, and BGE's, Consolidated for which we are the primary beneficiary. We have not Balance Sheets in accordance with Statement of Financial consolidated any entities for which we do not have a controlling Accounting Standards (SFAS) No. 71, Accountingfor the Effects voting interest. We eliminate all intercompany balances and of Certain Types of Regulation.

transactions when we consolidate these accounts. We summarize and discuss our regulatory assets and liabilities further in Note 6.

The Equity Method We usually use the equity method to report investments, Use of Accounting Estimates corporate joint ventures, partnerships, and ,affiliated companies Management makes estimates and assumptions when preparing (including qualifying facilities and power projects) where we financial statements under accounting principles generally hold a 20% to 50% voting interest. Under the equity method, accepted in the United States of America. These estimates and we report: assumptions affect various matters, including:

" our interest in the entity as an investment in our

• our reported amounts of revenues and expenses in our Consolidated Balance Sheets, and Consolidated Statements of Income during the reporting

" our percentage share of the earnings from the entity in periods, our Consolidated Statements of Income.

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• our reported amounts of assets and liabilities in our differs from current market prices. We recognize the cash Consolidated Balance Sheets at the dates of the financial payment at inception in our Consolidated Balance Sheets as an statements, and "Unamortized energy contract" 'asset or liability. We amortize

• our disclosure of contingent assets and liabilities at the these assets and liabilities into revenues based on the expected dates of the financial statements. cash flows provided by the contracts.

These estimates involve judgments with respect to During 2007, 2006, and 2005, we terminated or numerous factors that are difficult to predict and are beyond restructured in-the-money contracts in exchange for upfront cash management's control. As a result, actual amounts could payments and a reduction or cancellation of future performance materially differ from these estimates. obligations. The termination or restructuring of contracts allowed us to lower our exposure to performance risk under Reclassifications these contracts, and resulted in the realization of $17.8 million We have reclassified certain prior-year amounts for comparative of pre-tax earnings in 2007, $56.7 million of pre-tax earnings in purposes for the following: 2006, and $77.0 million of pre-tax earnings in 2005 that would

" we have combined "Risk management assets and have been recognized over the life of these contracts.

liabilities" and "Mark-to-market assets and liabilities" into one line item, called "Derivative assets and Mark-to-Market Accounting liabilities," in each applicable section of our We record revenues using the mark-to-market method of Consolidated Balance Sheets, accounting for derivative contracts for which we are not permitted

" we have separately presented 'Accrued expenses" and to use accrual accounting or hedge accounting. We discuss our use "Other current liabilities" that were previously combined of hedge accounting in the Derivatives and Hedging Activities into "Accrued expenses and other" on our Consolidated section later in this Note. These mark-to-market activities include Balance Sheets, and derivative contracts for energy and other energy-related

" we have separately presented "Accbunts receivable, commodities. Under the mark-to-market method of accounting, unbilled" that were previously reported within "Accounts we record the fair value of these derivatives as derivative assets receivable" on BGE's Consolidated Balance Sheets. and liabilities at the time of contract execution. We record changes in derivative assets and liabilities subject to Revenues mark-to-market accounting on a net basis in "Nonregulated Accrual Accounting revenues" in our Consolidated Statements of Income.

We record revenues from the sale of energy, energy-related Derivative assets and liabilities include contracts subject to products, and energy services under the accrual method of mark-to-market accounting. While some of these contracts accounting in the period when we deliver energy commodities or represent commodities or instruments for which prices are products, render services, or settle contracts. We use accrual available from external sources, other commodities and certain accounting for our merchant energy and other nonregulated contracts are not actively traded and are valued using modeling business transactions, including the generation or purchase and techniques to determine expected future market prices, contract sale of electricity, gas, and coal as part of our physical delivery quantities, or both. The market prices and quantities used to activities and for power, gas, and coal sales contracts that are not determine fair value reflect management's best estimate subject to mark-to-market accounting. Sales contracts that are considering various factors, including closing exchange and eligible for accrual accounting include non-derivative transactions over-the-counter quotations, time value, and volatility factors.

and derivatives that qualify for and are designated as normal However, future market prices and actual quantities will vary purchases and normal sales of commodities that will be from those used in recording derivative assets and liabilities physically delivered. We record accrual revenues, including subject to mark-to-market accounting, and it is possible that settlements with independent system operators, on a gross basis such variations could be material.

because we are a principal to the transaction and otherwise meet Mark-to-market revenues include:

the requirements of Emerging Issues Task Force (EITF) 03-11, " gains or losses on new transactions at origination to the Reporting Gains and Losses on Derivative Instruments That Are extent permitted by applicable accounting rules, Subject to FASB Statement No. 133, Accountingfor Derivative " unrealized gains and losses from changes in the fair Instruments and Hedging Activities, and Not Held for Trading value of open contracts, Purposes, and EITF 99-19, Reporting Revenue Gross as a Principal

• net gains and losses from realized transactions, and versus Net as an Agent. " changes in valuation adjustments.

While we generally elect accrual accounting whenever Origination gains, which are included in mark-to-market permitted, we sometimes use mark-to-market accounting for revenues, arise primarily from contracts that our wholesale physical delivery activities that are managed using economic marketing, risk management, and trading operation structures to hedges that do not qualify for accrual accounting. We discuss meet the risk management needs of our customers. Transactions mark-to-market accounting in further detail below. that result in origination gains may be unique and provide the We may make or receive cash paymeists at the time we potential for individually significant gains from a single assume a power sale agreement for which the contract price transaction.

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Origination gains represent the initial fair value recognized as we realize cash flows under the contract or when on these structured transactions. The recognition of origination observable market data becomes available.

gains is dependent on the existence of observable market data " Unobservable input valuation adjustment-upon that validates the initial fair value of the contract. Origination adoption of SFAS No. 157, this adjustment is necessary gains were: when we are required to determine fair value for

• $41.9 million pre-tax in 2007, derivative positions using internally developed models

• $13.5 million pre-tax in 2006, and that use unobservable inputs due to the absence of

• $61.6 million pre-tax in 2005. observable market information. Unobservable inputs to Origination gains arose primarily from: fair value may arise due to a number of factors,

• 1 transaction completed in 2007, including but not limited to, the term of the

• 3 transactions completed in 2006, of which no transaction transaction, contract optionality, delivery location, or contributed in excess of $10 million pre-tax, and product type. In the absence of observable market

• 6 transactions completed in 2005, one of which information that supports the model inputs, there is a contributed approximately $35 million pre-tax. presumption that the transaction price is equal to the market value of the contract when we transact in our Valuation Adjustments principal market, and SFAS No. 157 requires us to We record valuation adjustments to reflect: uncertainties recalibrate our estimate of fair value to equal the associated with certain estimates inherent in the determination transaction price. Therefore we do not recognize a gain of the fair value of derivative assets and liabilities subject to or loss at contract inception on these transactions. We mark-to-market accounting. To the extent possible, we utilize will recognize such gains or losses in earnings as we market-based data together with quantitatire methods for both realize cash flows under the contract or when observable measuring the uncertainties for which we record valuation market data becomes available.

adjustments and determining the level of such adjustments and " Credit-spread adjustment-for risk management changes in those levels. purposes we compute the value of our derivative assets We describe below the main types of valuation adjustments and liabilities subject to mark-to-market accounting we record and the process for establishing each. Generally, using a risk-free discount rate. In order to compute fair increases in valuation adjustments reduce our earnings, and value for financial reporting purposes, we adjust the decreases in valuation adjustments increase our earnings. value of our derivative assets to reflect the credit-However, all or a portion of the effect on earnings of changes in worthiness of each customer (counterparty) based upon valuation adjustments may be offset by changes in the value of either published credit ratings, or equivalent internal the underlying positions. As discussed below and later in this credit ratings and associated default probability Note, our valuation adjustments will be affected by the adoption percentages. We compute this adjustment by applying of SFAS No. 157, Fair Value Measurements, in 2008. the appropriate default probability percentage to our

• Close-out adjustment-represents the estimated cost to outstanding credit exposure, net of collateral, for each close out or sell to a third-party open mark-to-market counterparty. The level of this adjustment increases as positions. This valuation adjustment has the effect of our credit exposure to counterparties increases, the valuing "long" positions (the purchase of a commodity) maturity terms of our transactions increase, or the credit at the bid price and "short" positions (the sale of a ratings of our counterparties deteriorate, and it decreases commodity) at the offer price. We compute this when our credit exposure to counterparties decreases, adjustment based on our estimate lof the bid/offer spread the maturity terms of our transactions decrease, or the for each commodity and option price and the absolute credit ratings of our counterparties improve. Upon quantity of our net open positions for each year. The adoption of SFAS No. 157, we will also use a credit-level of total close-out valuation adljustments increases as spread adjustment in order to reflect our own credit risk we have larger unhedged positions, bid-offer spreads in determining the fair value of our derivative liabilities.

increase, or market information is.not available, and it decreases as we reduce our unhedged positions, bid-offer FinancialStatement Presentation spreads decrease, or market information becomes Certain transactions entered into under master agreements and available. Prior to the adoption of, SFAS No. 157 on other arrangements provide our wholesale competitive supply January 1, 2008, to the extent that we are not able to operation with a right of setoff in the event of bankruptcy or obtain observable market information for similar default by the counterparty. We report such transactions net in contracts, the close-out adjustment is equivalent to the our Consolidated Balance Sheets in accordance with FASB initial contract margin, thereby recording no gain or loss Interpretation No. 39, Offietting of Amounts Related to Certain at inception. In the absence of observable market Contracts. During 2007, the FASB issued Staff Position information, there is a presumption that the transaction FIN 39-1, Amendment of FASB Interpretation No. 39, which was price is equal to the market value of the contract, and effective January 1, 2008. We discuss Staff Position FIN 39-1 in therefore we do not recognize a gain or loss at more detail later in Note 1.

inception. We recognize such gains or losses in earnings 84

Equity in Earnings period. However, under an order issued by the Maryland PSC in We include equity in earnings from our investments in May 2007, as of June 1, 2007, we were required to reinstate qualifying facilities and power projects, joint ventures, and collection of the residential return component of the POLR investment in Constellation Energy Partners LLC (CEP) in administration charge and provide all residential electric "Nonregulated revenues" in our Consolidated Statements of customers a credit for the return component of the Income in the period they are earned. administrative charge.

In accordance with the POLR settlement agreement Fuel and Purchased Energy Expenses approved by the Maryland PSC, BGE defers the difference We incur costs for: between certain of its actual costs related to the electric

" the fuel we use to generate electricity, commodity and what it collects from customers under the

" purchases of electricity from others, and commodity charge in a given period. BGE either bills or refunds

" natural gas and coal that we resell. its customers the difference in the future. In addition, Senate These costs are included in "Fuel and purchased energy Bill 1 imposed a 15% rate cap for BGE residential electric expenses" in our Consolidated Statements'of Income. We discuss customers from July 1, 2006 until May 31, 2007. We discuss certain of these separately below. We also include certain this in more detail in Note 6.

non-fuel direct costs, such as ancillary services, transmission BGE's obligation to provide market-based standard offer costs, brokerage fees, and freight costs in "Fuel and purchased service to its largest commercial and industrial customers expired energy expenses" in our Consolidated Statements of Income. May 31, 2005. BGE continues to provide an hourly priced market-based standard offer service to those customers.

Fuel Used to Generate Electricity and Purchases of Electricity and Gas Regulated Gas Nonregulated Businesses BGE charges its gas customers for the natural gas they purchase We assemble a variety of power supply resources, including from BGE using "gas cost adjustment clauses" set by the baseload, intermediate, and peaking plants that we own, as well Maryland PSC. Under these clauses, BGE defers the difference as, a variety of power supply contracts that may have similar between certain of its actual costs related to the gas commodity characteristics, in order to enable us to meet our customers' and what it collects from customers under the commodity energy requirements, which vary on an hourly basis. The charge in a given period. BGE either bills or refunds its amount of power purchased depends on a number of factors, customers the difference in the future. The Maryland PSC including the capacity and availability of our power plants, the approved a modification of the gas cost adjustment clauses to level of customer demand, and the relative economics of provide a market-based rates incentive mechanism. Under the generating power versus purchasing power from the spot market.

market-based rates incentive mechanism, BGE's actual cost of We also have acquired contracts and certain power purchase agreements that qualify as operating leases: Under these gas is compared to a market index (a measure of the market operating leases, we record fuel and purchased energy expense as price of gas in a given period). The difference between BGE's we make fixed capacity payments, as well as variable payments actual cost and the market index is shared equally between based on the actual output of the plants. I shareholders and customers. The Maryland PSC also has We may make or receive cash payments at the time we approved a settlement that modifies certain provisions of the acquire a contract or assume a power purchase agreement when market-based rates incentive mechanism. These provisions the contract price differs from market prices at closing. We require that BGE secure fixed-price contracts for at least 10%,

recognize the cash payment or receipt at ifiception in our but not more than 20%, of forecasted system supply Consolidated Balance Sheets as an "Unamortized energy requirements for the November through March period. These contract" asset (payment) or liability (receipt). We amortize these fixed-price contracts are not subject to sharing under the market-assets and liabilities into fuel and purchased energy expenses based rates incentive mechanism.

based on the expected cash flows provided by the contracts.

Derivatives and Hedging Activities Regulated Electric We are exposed to market risk, including changes in interest BGE is obligated to provide market-based standard offer service rates and the impact of market fluctuations in the price and to residential and small commercial customers for the indefinite transportation costs of electricity, natural gas, and other future, and for large commercial and industrial customers for commodities as discussed further in Note 13. In order to manage varying periods beyond June 30, 2004, depending on customer these risks, we use both derivative and non-derivative contracts load. The Provider of Last Resort (POLR) rates charged during that may provide for settlement in cash or by delivery of a these time periods will recover BGE's wholesale power supply commodity, including:

costs and include an administrative fee. The administrative fee " forward contracts, which commit us to purchase or sell includes a shareholder return component and an incremental energy commodities in the future, cost component. Pursuant to Senate Bill 1, the energy legislation

• futures contracts, which are exchange-traded enacted in Maryland in June 2006, collection of the shareholder standardized commitments to purchase or sell a return component of the administrative fee for residential POLR commodity or financial instrument, or to make a cash service was suspended beginning January 1, 2007 for a 10-year settlement, at a specific price and future date, 85

• swap agreements, which require payments to or from We designate certain derivatives as fair value hedges. We counterparties based upon the differential between two record changes in the fair value of these derivatives and changes prices for a predetermined contractual (notional) in the fair value of the hedged assets or liabilities in earnings as quantity, and the changes occur. We summarize our fair value hedging

• option contracts, which convey the right to buy or sell a activities and the income statement classification of changes in commodity, financial instrument, or index at a the fair value of these hedges and the related hedged items as predetermined price. follows:

SPAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, requires that we recognize at fair Income Statement value all derivatives not qualifying for accrual accounting under Risk Derivative Classification the normal purchase and normal sale exception. We record all Optimize mix of Interest rate swaps Interest expense derivatives in "Derivative assest or liabilities" in our Consolidated fixed and Balance Sheets, including derivatives subject to mark-to-market floating-rate debt accounting and derivatives that are designated as hedges. Value of natural Forward contracts Nonregulated We record changes in the value of derivatives that are not gas in storage and price and revenues and designated as cash-flow hedges in earnings during the period of basis swaps Fuel and change. We record changes in the fair value of derivatives purchased energy designated as cash-flow hedges that are effective in offsetting the expenses variability in cash flows of forecasted transactions in other We record changes in the fair value of interest rate swaps comprehensive income until the forecasted transactions occur. At and the debt being hedged in "Derivative assets and liabilities" the time the forecasted transactions occur, we reclassify the and "Long-term debt" and changes in the fair value of the gas amounts recorded in other comprehensive income into earnings. being hedged and related derivatives in "Fuel stocks" and We record the ineffective portion of changes in the fair value of "Derivative assets and liabilities" in our Consolidated Balance derivatives used as cash-flow hedges immediately in earnings. Sheets. In addition, we record the difference between interest on We summarize our cash-flow hedging activities under SFAS hedged fixed-rate debt and floating-rate swaps in "Interest No. 133 and the income statement classification of amounts expense" in the periods that the swaps settle.

reclassified from "Accumulated other comprehensive income (loss)" as follows: Unamortized Energy Assets and Liabilities Income Staterhient Unamortized energy contract assets and liabilities represent the Risk Derivative Classification remaining unamortized balance of non-derivative energy contracts that we acquired or derivatives designated as normal Interest rate risk Interest rate swaps Interest expense associated with purchases and normal sales that we had previously recorded as new debt "Derivative assets or liabilities." The initial amount recorded issuances represents the fair value of the contract at the time of Interest rate risk Interest rate swaps Interest expense acquisition or designation, and the balance is amortized over the associated with life of the contract in relation to the present value of the variable-rate debt underlying cash flows. The amortization of these values is Nonregulated Futures and Nonregulated discussed in the Revenues and Fuel and PurchasedEnergy Expenses energy sales forward revenues sections of this Note.

contracts Nonregulated fuel Futures and Fuel and purchased Credit Risk and energy forward energy expenses Credit risk is the loss that may result from counterparty purchases contracts non-performance. We are exposed to credit risk, primarily Nonregulated gas Futures and Fuel and purchased through our merchant energy business. We use credit policies to purchases for forward energy expenses manage our credit risk, including utilizing an established credit resale contracts and approval process, daily monitoring of counterparty limits, price and basis employing credit mitigation measures such as margin, collateral swaps or prepayment arrangements, and using master netting Regulated gas Price and basis Fuel and purchased agreements. We measure credit risk as the replacement cost for purchases for swaps energy expenses open energy commodity and derivative positions (both resale mark-to-market and accrual) plus amounts owed from Regulated Price and basis Fuel and purchased counterparties for settled transactions. The replacement cost of electricity swaps energy expenses open positions represents unrealized gains, less any unrealized purchases for losses where we have a legally enforceable right of setoff.

resale 86

Electric and gas utilities, municipalities, cooperatives, corporate income tax rate from 7% to 8.25%. We discuss the generation owners, and energy marketers comprise the majority impact on our existing deferred income tax assets and liabilities of counterparties underlying our assets from our wholesale in more detail in Note 10.

marketing and risk management activities. We held cash A portion of our total deferred income tax liability relates collateral from these counterparties totaling $269.9 million as of to our regulated business, but has not been reflected in the rates December 31, 2007 and $252.6 million as of December 31, we charge our customers. We refer to this portion of the liability 2006. These amounts are included in "Customer deposits and as "Income taxes recoverable through future rates (net)." We collateral" in our Consolidated Balance Sheets. have recorded that portion of the net liability as a regulatory asset in our Consolidated Balance Sheets. We discuss this further Taxes in Note 6.

We summarize our income taxes in Note 10. BGE and our other subsidiaries record their allocated share of our consolidated State and Local Taxes federal income tax liability using the percentage complementary State and local income taxes are included in "Income taxes" in method specified in U.S. income tax regulations. As you read our Consolidated Statements of Income.

this section, it may be helpful to refer to Note 10.

Taxes Other Than Income Taxes Income Tax Expense BGE collects from certain customers franchise and other taxes We have two categories of income tax expense-current and that are levied by state or local governments on the sale or deferred. We describe each of these below: distribution of gas and electricity. We include these types of

" current income tax expense consists solely of regular tax taxes in "Taxes other than income taxes" in our Consolidated less applicable tax credits, and Statements of Income. Some of these taxes are imposed on the

" deferred income tax expense is equal to the changes in customer and others are imposed on BGE. The taxes imposed the net deferred income tax liability, excluding amounts on the customer are accounted for on a net basis, which means charged or credited to accumulated other comprehensive we do not recognize revenue and an offsetting tax expense for income. Our deferred income tax expense is increased or the taxes collected from customers. The taxes imposed on BGE reduced for changes to the "Income taxes recoverable are accounted for on a gross basis, which means we recognize through future rates (net)" regulatory asset (described revenue for the taxes collected from customers. Accordingly, the below) during the year. taxes accounted for on a gross basis are recorded as revenues in the accompanying Consolidated Statements of Income for BGE Tax Credits as follows:

We have deferred the investment tax credits associated with our regulated business and assets previously held by our regulated Year Ended December 31, 2007 2006 2005 business in our Consolidated Balance Sheets. The investment tax (In millions) credits are amortized evenly to income over the life of each property. We reduce current income tax expense in our Taxes other than income taxes Consolidated Statements of Income for the investment tax included in revenues-BGE $77.0 $74.0 $77.0 credits and other tax credits associated with our nonregulated businesses. Unrecognized Tax Benefits We have certain investments in facilities that manufactured We adopted FASB Interpretation No. 48, Accountingfor solid synthetic fuel produced from coal as defined under the Uncertainty in Income Taxes, on January 1, 2007 (FIN 48).

Internal Revenue Code for which we claim tax credits on our FIN 48 requires us to recognize in our financial statements the Federal income tax return. Because the federal tax credit for effects of uncertain tax positions if these positions meet a synthetic fuel produced from coal expired on December 31, "more-likely-than-not" threshold. For those uncertain tax 2007, these facilities ceased fuel production on that date. We positions that we have recognized in our financial statements, we recognize the tax benefit of these credits in our Consolidated establish liabilities to reflect the portion of those positions we Statements of Income when we believe it is highly probable that cannot conclude are "more-likely-than-not" to be realized upon the credits will be sustained. ultimate settlement. These are referred to as liabilities for unrecognized tax benefits under FIN 48. We recognize interest Deferred Income Tax Assets and Liabilities and penalties related to unrecognized tax benefits in "Income tax We must report some of our revenues and expenses differently expense" in our Consolidated Statements of Income. We discuss for our financial statements than for income tax return purposes. our unrecognized tax benefits in more detail in Note 10.

The tax effects of the temporary differences in these items are reported as deferred income tax assets or liabilities in our Earnings Per Share Consolidated Balance Sheets. We measure the deferred income Basic earnings per common share (EPS) is computed by dividing tax assets and liabilities using income tax rates that are currently earnings applicable to common stock by the weighted-average in effect. During 2007, the State of Maryland increased its number of common shares outstanding for the year. Diluted 87

EPS reflects the potential dilution of common stock equivalent Year Ended December 31, 2005 shares that could occur if securities or other contracts to issue (in millions, except per share amounts) common stock were exercised or converted into common stock.

Our dilutive common stock equivalent shares consist of Net income, as reported $623.1 Add: Actual stock-based compensation expense stock options and other stock-based compensation awards. The determined under intrinsic value method and following table presents stock options that were not dilutive and included in reported net income, net of related tax were excluded from the computation of diluted EPS in each effects 17.8" period, as well as the dilutive common stock equivalent shares as Deduct: Pro-forma stock-based compensation expense follows: determined under fair value based method for all awards, net of related tax effects (24.5)*

Year Ended December 31, 2007 2006 2005 Pro-forma net income $616.4 (In millions) Earnings per share:

Non-dilutive stock options - - 0.1 Basic-as reported $ 3.51 Dilutive common stock equivalent Basic-pro-forma $ 3.47 shares 2.3 2.0 2.2 Diluted-as reported $ 3.47 Diluted-pro-forma $ 3.43 Stock-Based Compensation - lRepresents expense for the nine mont/is ended September 30, Under our long-term incentive plans, we have granted stock 2005, which was prior to adoption of SFAS No. 123R options, performance-based units, service-based units, performance and service-based restricted stock, and equity to Cash and Cash Equivalents All highly liquid investments with original maturities of three officers, key employees, and members of the Board of Directors.

months or less' are considered cash equivalents.

We discuss these awards in more detail in Note 14.

We elected to early adopt SFAS No. 123 Revised (SFAS No. 123R), Share-Based Payment, on October 1, 2005, which Accounts Receivable and Allowance for Uncollectibles Accounts receivable, which includes cash collateral posted in our was prior to the required effective date of January 1, 2006. SFAS margin account with a third-party broker, are stated at the No. 123R requires companies to recognize compensation expense historical carrying amount net of write-offs and allowance for for all equity-based compensation awards issued to employees uncollectibles. We establish an allowance for uncollectibles based that are expected to vest. Equity-based compensation awards on our expected exposure to the credit risk of customers based include stock options, restricted stock, and any other share-based on a variety of factors.

payments. We recognized a small, favorable cumulative effect of change in accounting principle of $0.2 million after-tax due to Materials, Supplies, and Fuel Stocks the requirement to reduce compensation expense for estimated We record our fuel stocks, emissions credits, renewable energy forfeitures relating to outstanding unvested service-based credits, coal held for resale, and materials and supplies at the restricted stock awards and performance-based unit awards at lower of cost or market. We determine cost using the average October 1, 2005.

cost method for all of our inventory.

Under SFAS No. 123R, we recognize compensation cost ratably or in tranches (depending if the award has cliff or graded Financial Investments vesting) over the period during which an employee is required to In Note 4, we summarize the financial investments that are in provide service in exchange for the award,,which is typically a our Consolidated Balance Sheets.

one to five-year period. We use a forfeiture assumption based on SFAS No. 115, Accountingfor Certain Investments in Debt historical experience to estimate the number of awards that are and Equity Securities, applies particular requirements to some of expected to vest during the service period,, and ultimately our investments in debt and equity securities. We report those true-up the estimated expense to the actual expense associated investments at fair value, and we use either specific identification with vested awards. We estimate the fair value of stock option or average cost to determine their cost for computing realized awards on the date of grant using the Black-Scholes option-gains or losses.

pricing model and we remeasure the fair value of liability awards each reporting period. The following table presents the Available-for-Sale Securities pro-forma effect on net income and earnings per share for all We classify our investments in the nuclear decommissioning outstanding stock options and stock awards in each period that trust funds as available-for-sale securities. We describe the the fair value provisions of SFAS No. 123R were not in effect.

nuclear decommissioning trusts and the related asset retirement We do not capitalize any portion of our stock-based obligations later in this Note. In addition, we have investments compensation.

in marketable equity securities and trust assets securing certain executive benefits that are classified as available-for-sale securities.

We include any unrealized gains on our available-for-sale securities in 'Accumulated other comprehensive loss" in our 88

Consolidated Statements of Common Shareholders' Equity and Impairment and Its Application to Certain Investments. FSP Comprehensive Income and Consolidated Statements of FAS 115-1 requires us to determine whether a decline in fair Capitalization. value of an investment below book value is other than temporary. If we determine that the decline in fair value is Evaluation of Assets for Impairment and Other Than judged to be other than temporary, the cost basis of the Temporary Decline in Value investment must be written down to fair value as a new cost Long-Lived Assets basis. For securities held in our nuclear decommissioning trust We are required to evaluate certain assets that have long lives fund for which the market value is below book value, the (for example, generating property and equipment and real estate) decline in fair value for these securities is considered other than to determine if they are impaired when certain conditions exist. temporary and must be written down to fair value.

SFAS No. 144, Accountingfor the Impairment or Disposal of Long-Lived Assets, provides the accounting requirements for Intangible Assets impairments of long-lived assets and proved gas properties. We Goodwill is the excess of the purchase price of an acquired are required to test our long-lived assets and proved gas business over the fair value of the net assets acquired. We properties for recoverability whenever events or changes in account for goodwill and other intangibles under the provisions circumstances indicate that their carrying amount may not be of SFAS No. 142, Goodwill and Other Intangible Assets. We do recoverable. not amortize goodwill. SFAS No. 142 requires us to evaluate We determine if long-lived assets and proved gas properties goodwill for impairment at least annually or more frequently if are impaired by comparing their undiscounted expected future events and circumstances indicate the business might be cash flows to their carrying amount in our accounting records. impaired. Goodwill is impaired if the carrying value of the We would record an impairment loss if the undiscounted business exceeds fair value. Annually, we estimate the fair value expected future cash flows were less than the carrying amount of of the businesses we have acquired using techniques similar to the asset. Cash flows for long-lived assets, or a group of those used to estimate future cash flows for long-lived assets as long-lived assets, are determined at the lowest level for which previously discussed. If the estimated fair value of the business is identifiable cash flows are largely independent of the cash flows less than its carrying value, an impairment loss is required to be of other assets and liabilities. Proven gas p roperties' cash flows recognized to the extent that the carrying value of goodwill is are determined at the field level. Undiscounted expected future greater than its fair value. SFAS No. 142 also requires the cash flows include risk-adjusted probable and possible reserves. amortization of intangible assets with finite lives. We discuss the We are also required to evaluate our equity-method and changes in our intangible assets in more detail in Note 5.

cost-method investments (for example, in partnerships that own power projects) for impairment. Accounting Principles Board Property, Plant and Equipment, Depreciation, Depletion, (APB) No. 18, The Equity Method of Accountingfor Investments Amortization, and Accretion of Asset Retirement in Common Stock (APB No. 18), provides the accounting Obligations requirements for these investments. The standard for We report our property, plant and equipment at its original cost, determining whether an impairment must be recorded under unless impaired under the provisions of SFAS No. 144.

APB No. 18 is whether the investment has experienced a loss in Our original costs include:

value that is considered an "other than a temporary" decline in " material and labor, value. " contractor costs, and We are also required to evaluate unproved gas producing " construction overhead costs, financing costs, and costs properties at least annually to determine if it is impaired under for asset retirement obligations (where applicable).

SFAS No. 19, FinancialAccounting and Reporting by Oil and Gas We own an undivided interest in the Keystone and Producing Properties. Impairment for unproved property occurs if Conemaugh electric generating plants in Western Pennsylvania, there are no firm plans to continue drilling, lease expiration is at as well as in the transmission line that transports the plants' risk, or historical experience necessitates a valuation allowance. output to the joint owners' service territories. Our ownership We use our best estimates in making these evaluations and interests in these plants are 20.99% in Keystone and 10.56% in consider various factors, including forward price curves for Conemaugh. These ownership interests represented a net energy, fuel costs, legislative initiatives, and operating costs. investment of $210.3 million at December 31, 2007 and However, actual future market prices and project costs could $183.1 million at December 31, 2006. Each owner is vary from those used in our impairment evaluations, and the responsible for financing its proportionate share of the plants' impact of such variations could be material. working funds. Working funds are used for operating expenses and capital expenditures. Operating expenses related to these I

Debt and Equity Securities plants are included in "Operating expenses" in our Consolidated Our investments in debt and equity securities, which primarily Statements of Income. Capital costs related to these plants are consist of our nuclear decommissioning trust fund investments, included in "Nonregulated property, plant and equipment" in are subject to impairment evaluations under FASB Staff Position our Consolidated Balance Sheets.

(FSP) FAS 115-1, The Meaning of Other-Than-Temporary 89

The "Nonregulated property, plant and equipment" in our of approximately 3.5% per year for our regulated Consolidated Balance Sheets includes nonregulated generation business, construction work in progress of $329.6 million at " the group straight-line method using rates averaging December 31, 2007 and $229.5 million at,December 31, 2006. approximately 2.7% per year for our generating assets, WXhen we retire or dispose of property, plant and or equipment, we remove the asset's cost from our Consolidated

• the units-of-production method over the remaining life Balance Sheets. We charge this cost to accumulated depreciation of the estimated proved reserves at the field level for for assets that were depreciated under the group, straight-line acquisition costs and over the remaining life of proved method. This includes regulated property, plant and equipment developed reserves at the field level for development and nonregulated generating assets transfer 'red from BCE to our costs. The estimates for gas reserves are based on merchanst energy business. For all other assets, we remove the internal calculations.

accumulated depreciation and amortization amounts from our Other assets are depreciated primarily using the straight-line Consolidated Balance Sheets and record any gain or loss in our method and the following estimated useful lives:

Consolidated Statements of Income. I The costs of maintenance and certain, replacements are Asset Estimated Useful Lives charged to "Operating expenses" in our Consolidated Statements Building and improvements 5 50

- years of Income as incurred. Office equipment and furniture 3 - 20 years Our oil and gas exploration and production activities Transportation equipment 5 - 15 years consist of working interests in gas producing fields. We account Computer software 3 - 10 years for these activities under the successful efforts method of accounting. Acquisition, development, and exploration costs are Amortization Expense capitalized as permitted by SIAS No. 19. Costs of drilling Amortization is an accounting process of reducing an asset exploratory wells are initially capitalized and later charged to amount in our Consolidated Balance Sheets over a period of expense if reserves are not discovered or deemed not to be time that approximates the useful life of the related item. When commercially viable. Other exploratory costs a-re charged to we reduce amounts in our Consolidated Balance Sheets, we expense when incurred. increase amortization expense in our Consolidated Statements of Capitalized exploratory well costs were $16.8 million at Income.

December 31, 2007 and $7.0 million at December 31, 2006, and do not include amounts that were capitalized and Accretion Expense subsequently expensed within the same period. There were no SFAS No. 143, Accounting/or Asser Retirement Obligations, material well costs capitalized at December' 31, 2006 and 2005 provides the accounting requirements for recognizing an that were reclassified in 2007 and 2006, respectively, to wells, estimated liability for legal obligations associated with the facilities and equipment based on the determination of proved retirement of tangible long-lived assets. In the fourth quarter of reserves. 2005, we adopted FIN 47, Accounting/or ConditionalAsset There were no material capitalized exploratory well costs Retirement Obligations-an Interpretation of FASB Statement charged to expense in 2007, 2006 and 2005. However, there was No. 143. FIN 47 clarifies that asset retirement obligations that

$12.9 million, $4.1 million, and $1.7 million capitalized as are conditional upon a future event are subject to the provisions exploratory well costs pending the determination of proved of SFAS No. 143. Our conditional asset retirement obligations reserves during the years 2007, 2006, and 2005, respectively. relate primarily to asbestos removal at certain of our generating As of December 31, 2007, we have $3.9 million of facilities. In 2005, we recorded an asset retirement obligation of exploratory well costs, related to one project, that have been $13.9 million for these facilities and recorded a $7.4 million capitalized for a period greater than one year since the after-tax charge to earnings as a cumulative effect of change in completion of drilling. These capitalized exploratrty well costs accounting principle.

are related to wells that a-re being stimulated and will be At December 31, 2007, $897.3 million of our total asset evaluated upon completion of this program. retirement obligation of $917.6 million was associated with the decommissioning of our nuclear power plants-Calvert Cliffs Depreciation and Depletion Eepense Nuclear Power Plant (Calvert Cliffs), Nine Mile Point Nuclear We compute depreciation for our generating, electric Station (Nine Mile Point) and R. E. Ginna Nuclear Power Plant transmission and distribution, and gas distribution facilities. We (Ginna). The remainder of our asset retirement obligations is compute depletion for our exploitation and production activities. associated with our other generating facilities and certain other Depreciation and depletion are determined. using the following long-lived assets. From time to time, we will perform studies to methods: update our asset retirement obligations. We record a liability

• the group straight-line method, approved by the when we are able to reasonably estimate the fair value of any Maryland PSC, applied to the average investment, future legal obligations associated with retirement that have been adjusted for anticipated costs of removal less salvage, in incurred and capitalize a corresponding amount as part of the classes of depreciable property based on an average rate book value of the related long-lived assets.

90

The increase in the capitalized cost is included in funds for Calvert Cliffs were $8.8 million for 2007, determining depreciation expense over the estimated useful lives $8.8 million for 2006, and $17.6 million for 2005. Under the of these assets. Since the fair value of the asset retirement Maryland PSC's order deregulating electric generation, BCE's obligations is determined using a present value approach, customers must pay a total of $520 million in 1993 dollars, accretion of the liability due to the passage of time is adjusted for inflation, to decommission Calvert Cliffs. BCE is recognized each period to "Accretion of asset retirement collecting this a-mount on behalf of and passing it to Calvert obligations" in our Consolidated Statemen~ts of Income until Cliffs. Calvert Cliffs is responsible for any difference between the settlement of the liability. We record a gain or loss when this amount and the actual costs to decommission the plant.

the liability is settled after retirement for any difference In 2006, BCE received approval from the Maryland PSC between the accrued liability and actual costs. The change in to continue annual customer collections of $18.7 million per our "Asset retirement obligations" liability 'during 2007 was as year through December 31, 2016. BCE will be required to follows: submit a filing to determine the level of customer contributions after December 31, 2016. In addition, Senate Bill 1 required BCE to provide credits to residential electric customers equal (In millions) to the amount collected for decommissioning annually for ten Liability at January 1, 2007 $ 974.8 years beginning in 2007. Under the provisions of Senate Bill 1, Liabilities incurred 3.9 we are required to apply the collection of the nuclear Liabilities settled (1.4) decommissioning trust funds over the ten year period Accretion expense 68.3 beginning in 2007 toward fulfillment of the decommissioning Revisions to cash flows (125.1) obligations of BCE customers.

Other (2.9) We began to record decommissioning expense for Nine Liability at December 31, 2007 $ 917.6 Mile Point in accordance with SEAS No. 143 on January 1, 2003. The "Asset retirement obligations" liability associated Substantially all of the $125.1 million "Revisions to with the decommissioning was $341.9 million at December 31, expected future cash flows" represents the decrease to our 2007 and $408.1 million at December 31, 2006. We nuclear decommissioning asset retirement obligations in determined that the decommissioning trust funds established conjunction with site-specific studies that we completed in for Nine Mile Point are adequately funded to cover the future 2007 for all three of our nuclear sires. These studies reassessed costs to decommission the plant and as such, no contributions the key assumptions involved in estimating the expected future were made to the trust funds during the years ended cost of nuclear decommissioning activities:, The resulting December 31, 2007, 2006, and 2005.

decrease in the expected future cost of nuclea-r Upon the closing of the Cinna acquisition in 2004, the decommissioning and the related asset retirement obligation is seller transferred $200.8 million in decommissioning funds. In primarily due to a fleet-based approach incorporating recent return, we assumed all liability for the costs, to decommission industry experiences, technological advances, improved the unit. We believe that this transfer will be sufficient to cover economies of scale, and the impact of Nine Mile Point's license the future costs to decommission the plant and as such, no renewal, which was approved in late 2006j contributions were made to the trust funds during the years "Other" primarily represents CEP's asset retirement ended December 31, 2007, 2006, and 2005. Effective June obligation that is no longer included in our Consolidated 2004, we began to record decommissioning expense for Cinna Balance Sheets. We discuss the deconsolidation of CEP in in accordance with SEAS No. 143. The "Asset retirement Note 2.

obligations" liability associated with the decommissioning was Nuclear Fuel $245.9 million at December 31, 2007 and $209.9 million at We amortize the cost of nuclear fuel, including the quarterly December 31, 2006.

In accordance with Nuclear Regulatory Commission fees we pay to the Department of Energy for the future disposal of spent nuclear fuel, based on the energy produced (NRC) regulations, we maintain external decommissioning trusts to fund the costs expected to be incurred to over the life of the fuel. These fees are based on the kilowatt-decommission Calvert Cliffs, Nine Mile Point, and Cinna. The hours of electricity sold. We report the amortization expense NRC requires owners to provide financial assurance that they for nuclear fuel in "Fuel and purchased energy expenses" in our will accumulate sufficient funds to pay for the cost of nuclear Consolidated Statements of Income.

decommissioning. The assets in the trusts are reported in "Nuclear decommissioning trust funds" in our Consolidated Nuclear Decommissioning Balance Sheets. These amounts are legally restricted for funding Effective January 1, 2003, we began to record decommissioning the costs of decommissioning. We classify the investments in expense for Calvert Cliffs in accordance with SEAS No. 143.

the nuclear decommissioning trust funds as available-for-sale The 'Asset retirement obligations" liability' associated with the securities, and we report these investments at fair value in our decommissioning of Calvert Cliffs was $309.5 million at Consolidated Balance Sheets as previously discussed in this December 31, 2007 and $336.7 million at December 31, Note. Investments by nuclear decommissioning trust funds are 2006. Our contributions to the nuclear decommissioning trust guided by the "prudent man" investment principle. The funds 91

are prohibited from investing directly in Constellation Energy The most significant impact of SFAS No. 157 relates to or its affiliates and any other entity owning a nuclear power the accounting for derivatives, which is one of our critical plant. accounting policies, in the following ways:

As the owner of Calvert Cliffs we, along with other

• Prior to the adoption of SFAS No. 157, a component domestic utilities, were required by the Energy Policy Act of of our close-out reserve for derivatives subject to 1992 to make contributions to a fund for.decommissioning mark-to-market accounting included the initial margin and decontaminating the Department of Energy's uranium on contracts for which we were unable to obtain enrichment facilities. The contributions were paid by BGE over observable market information. As a result, we did not a 15 year period that ended in 2006. BGE amortizes the recognize gains or losses in earnings at the inception of deferred costs of decommissioning and decontaminating the such contracts; instead, we recognize gains or losses in Department of Energy's uranium enrichment facilities. earnings as we realize cash flows under the contract or when observable market data becomes available. Upon Capitalized Interest and Allowance for Funds Used adoption of SPAS No. 157, we continue to reflect a During Construction substantial portion of this reserve as an unobservable CapitalizedInterest input valuation adjustment because it relates to Our nonregulated businesses capitalize interest costs under contracts executed in our principal market for which SFAS No. 34, CapitalizingInterest Costs, for costs incurred to SPAS No. 157 requires us to recalibrate our estimate finance our power plant construction projects, real estate of fair value to reflect transaction price. Therefore, we developed for internal use, and other capital projects. do not expect to record a material adjustment in retained earnings at January 1, 2008 to reflect the Allowance for Funds Used During Construction (AFC) required adoption of this aspect of SFAS No. 157 BGE finances its construction projects with borrowed funds using a modified retrospective approach.

and equity funds. BGE is allowed by the Maryland PSC to

• Prior to the adoption of SFAS No. 157, we record the costs of these funds as part of the cost of determined fair value for derivative liabilities for which construction projects in its Consolidated Balance Sheets. BGE prices are not available from external sources by does this through the AFC, which it calculates using rates discounting the expected cash flows from the contracts authorized by the Maryland PSC. BGE bills its customers for using a risk-free discount rate. We did not reflect our the AFC plus a return after the utility property is placed in own credit risk in determining fair value for these service. liabilities. SFAS No. 157 requires us to record all The AFC rates are 9.4% for electric plant, 8.5% for gas liabilities measured at fair value including the effect of plant, and 9.2% for common plant. BGE'compounds AFC our own credit risk. As a result, we will apply a credit-annually. spread adjustment in order to reflect our own credit risk in determining fair value for these liabilities, which Long-Term Debt will reduce the recorded amount of these liabilities as We defer all costs related to the issuance of long-term debt. of the date of adoption. As a result of this change, we These costs include underwriters' commissions, discounts or expect to record a pre-tax gain in earnings of a range premiums, other costs such as legal, accounting, and regulatory of approximately $10-$15 million in the first quarter fees, and printing costs. We amortize these costs into interest of 2008.

expense over the life of the debt. SFAS No. 157 also establishes a three-level fair value When BGE incurs gains or losses on debt that it retires hierarchy, reflecting the extent to which inputs to the prior to maturity, it amortizes those gains or losses over the determination of fair value can be observed, and requires fair remaining original life of the debt. value disclosures based upon this hierarchy. We will include these disclosures in the Notes to our Consolidated Financial Accounting Standards Issued Statements subsequent to the adoption of SPAS No. 157.

SFAS No. 157 In September 2006, the FASB issued SFAS No. 157. SFAS SFAS No. 159 No. 157 defines fair value, establishes a framework for In February 2007, the FASB issued SFAS No. 159, The Fair measuring fair value, and requires new disclosures for fair value Value Option for FinancialAssets and FinancialLiabilities-measurements. SFAS No. 157 became effective for most fair including an amendment of FASB Statement No. 115. SFAS value measurements, other than leases and certain nonfinancial No. 159 provides the option to report at fair value certain assets and liabilities, beginning January 1, 2008. These financial instruments that are not currently required or exclusions from SEAS No. 157 did not have a material effect permitted to be measured at fair value. This option would be on our implementation of this statement. applied on an instrument by instrument basis. If elected, unrealized gains and losses on the affected financial instruments would be recognized in earnings at each subsequent reporting date. SPAS No. 159 is effective beginning January 1, 2008. We have assessed the provisions of SPAS No. 159 and we have 92

elected not to apply fair value accounting to our eligible the consolidated financial statements. SFAS No. 160 requires financial instruments. As a result, there will be no impact on that changes in a parent's ownership interest in a subsidiary be our, or BGE's, financial results. reported as an equity transaction in the consolidated financial statements when it does not result in a change in control of FSP FIN 39-1 the subsidiary. When a change in a parent's ownership interest In April 2007, the FASB issued Staff Position (FSP) FIN 39-1, results in deconsolidation, a gain or loss should be recognized Amendment of FASB Interpretation No. 39. FSP FIN 39-1 in the consolidated financial statements. SFAS No. 160 must permits an entity to report all derivatives recorded at fair value be applied prospectively as of January 1, 2009, except for the with any associated fair value cash collateral, which are with presentation and disclosure requirements, which are required to the same counterparty under a master netting arrangement, be applied retrospectively for all periods presented. We are together in the balance sheet. Our competitive supply operation currently evaluating the impact of SFAS No. 160 but do not reports derivative amounts under master netting arrangements expect the adoption of this standard to have a material impact net in accordance with FIN 39, Offietting 'ofAmounts Related to on our, or BGE's, financial results.

Certain Contracts; however, we report fair value cash collateral separately from our derivative amounts. Under the provisions of Accounting Standards Adopted this FSP, we expect to report all derivatives recorded at fair FIN 48 value net with the associated fair value cash collateral. The In July 2006, the FASB issued FIN 48. FIN 48 provides effects of FSP FIN 39-1 will be applied by adjusting all guidance for the recognition and measurement of an entity's financial statements presented beginning January 1, 2008. We uncertain tax positions. These are defined as positions taken in do not expect this standard to have a material impact on our a previously filed tax return or positions expected to be taken balance sheet presentation. in future tax returns and which result in, among other things, a permanent reduction of income taxes payable, a deferral of SFAS No. 141 Revised income taxes otherwise currently payable to future years, or a In December 2007, the FASB issued SFAS No. 141 Revised change in the expected ability to realize deferred tax assets.

(SFAS No. 141R), Business Combinations. SFAS No. 141R Under FIN 48, we are required to recognize the financial revises SFAS 141, Business Combinations. SFAS No. 141R statement effects of tax positions if they meet a "more-likely-than-not" threshold. In evaluating items relative to requires an acquirer to determine the fair value of the consideration exchanged as of the acquisition date (i.e., the this threshold, we must assess whether each tax position will be date the acquirer obtains control). Presently, an acquisition is sustained based solely on its technical merits assuming valued as of the date the parties agree upon the terms of the examination by a taxing authority.

transaction. SFAS No. 141R also modifies,' among other things, The adoption of FIN 48 on January 1, 2007, resulted in the accounting for direct costs associated with an acquisition, the recording of a $7.3 million incremental liability for contingencies acquired, and contingent consideration. We plan unrecognized tax benefits and a corresponding reduction in to adopt SFAS No. 141R for business combinations for which "Retained earnings" in our Consolidated Balance Sheets as a the acquisition date occurs after January 1, 2009. cumulative effect of change in accounting principle. We also reclassified $49.4 million from existing tax liabilities (primarily SFAS No. 160 deferred income taxes) to the new FIN 48 liability for In December 2007, the FASB issued SFAS No. 160, unrecognized tax benefits. Our resulting total $56.7 million NoncontrollingInterests in Consolidated FinincialStatements, an FIN 48 liability for unrecognized tax benefits included amendment ofARB No. 51. SFAS No. 160 clarifies that a $12.1 million of accrued interest and penalties.

noncontrolling interest in a subsidiary is an ownership interest We discuss the adoption of FIN 48 in more detail in in the consolidated entity that should be reported as equity in Note 10.

93

2Other Events 2007 Events Gain on Sales of Equity of CEP In November 2006, CEP, a limited liability company formed by Pre-Tax After-Tax Constellation Energy completed an initial public offering of (In millions) 5.2 million common units at $21 per unit. See details under Impairment losses and other costs $(20.2) $(12.2) 2006 Events later in this Note. In April 2007, CEP acquired Workforce reduction costs (2.3) (1.4) 100% ownership of certain coalbed methane properties located Gain on sales of equity of CEP 63.3 39.2 in the Cherokee Basin in Kansas and Oklahoma. This Loss from discontinued operations acquisition was funded through CEP's sale of equity in which High Desert (2.4) (0.3) we did not participate.

Puna - (0.6) As a result of the April 2007 equity issuance by CEP, our ownership percentage in CEP fell below 50 percent. Therefore, Total loss from discontinued during the second quarter of 2007, we deconsolidated CEP and operations (2.4) (0.9) began accounting for our investment using the equity method Total other items $ 38.4 $ 24.7 under Accounting Principles Board Opinion (APB) No. 18, The Equity Method ofAccountingfbr Investments in Common Stock.

We discuss the equity method of accounting in more detail in Impairment Losses and Other Costs Note 1.

In connection with the termination of the, merger agreement In July and September 2007, CEP issued additional equity.

with FPL Group, Inc. (FPL Group) in October 2006, which is In connection with our equity ownership in CEP, we recognize discussed further in Note 15, we acquired certain rights relating gains on CEP's equity issuances in the period that the equity is to a wind development project in Western, Maryland. In the second quarter of 2007, we elected not to make the additional sold as common units or when converted to common units. The details of the 2007 CEP equity issuances, as well as the gains investment that was required at that time to retain our rights in the project; therefore, we recorded a charge of $20.2 million recognized by us, are summarized below:

pre-tax to write-off our investment in these development rights.

Units Price/ Proceeds Pre-tax Issued Unit to CEP 9ain Workforce Reduction Costs In June 2007, we approved a restructuring of the workforce at (In millions, except price/unit) our Nine Mile Point nuclear facility related to the elimination of April 2007 Sale 23 positions. We recognized costs of $2.3 'million pre-tax related Common units 2.2 $26.12 $ 58 $12.5 to recording a liability for severance and other benefits under Class E units 0.1 25.84 2 0.4 our existing benefit programs. July 2007 Sale The following table summarizes the status of this Common units 2.7 35.25 94 20.0 involuntary severance liability for Nine Mile Point at Class F units 2.6 35.25 92 11.2 December 31, 2007: September 2007 Sale Common units 2.5 42.50 105 19.2 (In millions)

Initial severance liability balance (1) $ 2.6 Discontinued operations Amounts recorded as pension and postretirement In the fourth quarter of 2006, we completed the sale of six liabilities (1.5) natural gas-fired plants, including the High Desert facility, which was classified as discontinued operations. We recognized an Net cash severance liability 1.1 Cash severance payments after-tax loss of $0.3 million as a component of "Income (loss) from discontinued operations" for 2007 due to post-closing Other working capital and income tax adjustments. In addition, during Severance liability balance at December 31', 2007 $ 1.1 2007, we recognized an after-tax loss of $0.6 million relating to (1) Includes $0.3 million to be reimbursedfrom co-owner. income tax adjustments arising from the June 2004 sale of a I geothermal generating facility in Hawaii that was also previously classified as discontinued operations.

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Presented in the table below ate the amounts related to discontinued operations that are included in "Income from discontinued operations" in our Consolidated Statements of Income:

International High Desert Oleander Investments Total 2007 2006 2005 2007 2006 2005 2007 2006 2005 2007 2006 2005 (In millions)

Revenues $ - $161.2 $163.7 $ - $ - $14.7 $ - $ - $228.1 $ - $161.2 $406.5 (Loss) income before income taxes (2.4) 108.9 111.0 - - 8.5 - - 14.5 (2.4) 108.9 134.0 Net (loss) income (0.3), 70.2 70.8 - - 5.3 - - 4.5 (0.3) 70.2 80.6 Pre-tax impairment charge - - (4.8) - - - - - (4.8)

After-tax impairment charge - - - - - (3.0) - - - - - (3.0)

Pre-tax gain on sale - 185.2 - - - 1.2 - 1.4 25.6 - 186.6 26.8 After-tax gain on sale - 116.7 - - - 0.7 - 0.9 16.1 - 117.6 16.8 (Loss) income from discontinued operations, net of taxes (0.3) 186.9 70.8 - - 3.0 - 0.9 20.6 (0.3) 187.8 94.4 During 2007, we recognized an after-tax loss from discontinued operations of $(0. 6) million, related to tax adjustments from the sale of Puna, a Hawaiian Geothermalfacility, in 2004.

2006 Events At the time of the agreement for sale, we evaluated these Pre-Tax After-Tax plants for classification as discontinued operations under SFAS (In millions) No. 144. Discontinued operations classification only applies to Gain on sale of gas-fired plants $ 73.8 $ 47.1 assets held for sale that meet the definition of a component of Workforce reduction costs (28.2) (17.0) an entity. A component of an entity comprises operations and Merger-related costs (18.3) (5.7) cash flows that can be clearly distinguished, operationally and Gain on initial public offering of CEP 28.7 17.9 for financial reporting purposes, from the rest of the entity.

Income from discontinued operations I High Desert met the requirements to be classified as a High Desert 1294.1 186.9 discontinued operation because it had a power sales agreement International investments f 1.4 0.9 for its frilll output, was determined to be a component of Total income from discontinued Constellation Energy, and had separately identifiable cash flows.

operations 295.5 187.8 The table above provides additional detail about the a-mounts Total other items $351.5 $230.1 recorded in 'Income from discontinued operations" related to our High Desert facility.

Sale of Gas-FiredPlants The remaining gas-fired plants were managed within our In December 2006, we completed the sale of the following merchant business as a group or on a portfolio basis because natural gas-fired plants owned by our merchant energy they have aggregated risks, were hedged as a group, and business: generated joint cash flows. These gas-fired plants do not meet the requirements to be classified as discontinued operations.

The results of operations for these gas-fired plants, as well as Capacity the $73.8 million pre-tax gain on sale, remain classified in Facility (MW) Unit Type Location continuing operations.

High Desert 830 Combined Cycle California Rio Nogales 800 Cobie Cyl Texas International Investments Combined Cycle Holland 665 Illinois In the fourth quarter of 2005, we completed the sale of University PeakingdCyl Constellation Power International Investments, Ltd. (CPII). We Park 300 Illinois recognized an after-tax gain of $0.9 million for the year ended Peaking Big Sandy 300 West Virginia December 31, 2006 due to the resolution of an outstanding Peaking Wolf Hills 250 Virginia contingency related to the sale. We discuss the details of the We sold these gas-fired plants for cash of $1.6 billion, and outstanding contingency later in this Note.

recognized a pre-tax gain on the sale of $259.0 million of which $73.8 million was included in "Gain on sale of gas-fired Workforce Reduction Costs plants" and $185.2 million was included ih "Income from In March 2006, we approved a restructuring of the workforce discontinued operations" in our Consolidated Statements of at our Ginna nuclear facility. In connection with this Income. restructuring, 32 employees were terminated. During the quarter ended March 31, 2006, we recognized costs of 95

$2.2 million pre-tax related to recording a' liability for $35.3 million. The termination of our merger agreement with severance and other benefits under our existing benefit FPL Group is discussed further in Note 15.

programs.

We completed this workforce reducti6n effort in 2006. As InitialPublic Offering of CEP a result, no involuntary severance liability was recorded at In November 2006, CEP, a limited liability company formed December 31, 2006. by Constellation Energy, completed an initial public offering of In July 2006, we announced a planned restructuring of 5.2 million common units at $21 per unit. The initial public the workforce at our Nine Mile Point nuclear facility. We offering resulted in cash proceeds of $101.3 million, after recognized costs during the quarter ended;September 30, 2006 expenses associated with the offering, for Constellation Energy.

of $15.1 million pre-tax related to the elimination of 126 As a result of the initial public offering of CEP, we positions associated with this restructuring. We also initiated a recognized a pre-tax gain of $28.7 million, or $17.9 million restructuring of the workforce at our Calvert Cliffs nuclear after recording deferred taxes on the gain.

facility during the third quarter of 2006 ahd we recognized costs of $2.9 million pre-tax related to trh elimination of 30 2005 Events positions associated with this restructuring'.

Pre-Tax After-Tax In addition, we incurred a pre-tax settlement charge of

$12.7 million in accordance with Statement of Financial (In millions)

Accounting Standards (SFAS) No. 88, Employers' Accountingfor Merger-related costs $ (17.0) $(15.6)

Settlements and Curtailments of Defined Benefit Pension Plans Workforce reduction costs (4.4) (2.6) andfor Termination Benefits. This charge reflects recognition of Income from discontinued operations the portion of deferred actuarial gains and, losses associated High Desert 111.0 70.8 with employees who were terminated as part of the International investments 40.1 20.6 restructuring or retired in 2006 and who elected to receive Oleander 4.9 3.0 their pension benefit in the form of a lump-sum payment. In Total income from discontinued accordance with SFAS No. 88, a settlement charge must be operations 156.0 94.4 recognized when lump-sum payments exceed annual pension plan service and interest cost. The total SFAS No. 88 Total other items $134.6 $ 76.2 settlement charge incurred in 2006 includes a pre-tax charge of

$8.0 million as a result of the Nine Mile Point restructuring. Merger-Related Costs We discuss the settlement charges that we recorded during We incurred external costs associated with the execution of the 2006 in Note 7. agreement relating to our proposed merger with FPL Group.

The following table summarizes the status of the We discuss the terminated merger in more detail in Note 15.

involuntary severance liability for Nine Mile Point and Calvert Cliffs at December 31, 2007:

Workforce Reduction Costs As a result of the workforce reduction efforts initiated in 2004, (In millions) in 2005 we were required to record a pre-tax settlement charge Initial severance liability balance $ 19.6 in our Consolidated Statements of Income of $4.4 million for Amounts recorded as pension and one of our qualified pension plans under SFAS No. 88.

postretirement liabilities (7.3) In 2005, we completed the 2004 workforce reduction effort.

Net cash severance liability 12.3 Cash severance payments (11.0)

Discontinued Operations Other Oleander Severance liability balance at December 31, In March 2005, we reached an agreement in principle to sell 2007 $ 1.3 our Oleander generating facility, a four-unit peaking plant The severance liability above includes $1.6 million of costs that the located in Florida. Our merchant energy business classified joint owner of Nine Mile Point Unit 2 reinmbursed us. Oleander as held for sale and performed an impairment test under SFAS No. 144 as of March 31, 2005. The impairment test indicated that the carrying value of the plant was higher Merger-Related costs We incurred costs during 2006 related to the proposed merger than its fair value less costs to sell, and therefore in March with FPL Group. The merger was terminated in October 2006. 2005 we recorded an impairment charge of $4.8 million These costs totaled $18.3 million pre-tax for 2006. In addition, pre-tax as part of discontinued operations.

In June 2005, we completed the sale of this facility for during 2006 we recognized tax benefits of, $5.3 million on merger costs incurred in 2005 that were not considered $217.6 million, and recognized a pre-tax gain on the sale of

$1.2 million as part of discontinued operations.,

deductible for income tax purposes until the termination of the merger in 2006. Our total pre-tax merger-related costs were 96

International Investments sales price was contingent upon the collection of certain In October 2005, we sold CPI. CPII held our other receivables by March 31, 2006. At December 31, 2005, we nonregulated international investments, which represented an recognized approximately $2.2 million of this amount based on interest in a Panamanian electric distribution company and an cash collections, which was included in the $25.6 million investment in a fund that holds interests in two South pre-tax gain. We recognized the remaining $1.4 million of American energy projects. We received cash of $71.8 million contingent proceeds in 2006 once realization was assured and recognized a pre-tax gain of approximately $25.6 million, beyond a reasonable doubt.

or $16.1 million after-tax. An additional $3.6 million of the 3 Information by Operating Segmnent Our reportable operating segments are-Merchant Energy,

• Our regulated electric business purchases, transmits, Regulated Electric, and Regulated Gas: distributes, and sells electricity in Central Maryland.

• Our merchant energy business is nonregulated and

• Our regulated gas business purchases, transports, and includes: sells natural gas in Central Maryland.

- full requirements load-serving sales of energy and Our remaining nonregulated businesses:

capacity to utilities, cooperatives, and commercial,

• design, construct, and operate renewable energy, heating, industrial, and governmental customers, cooling, and cogeneration facilities for commercial,

- structured transactions and risk management industrial, and governmental customers throughout services for various customers (including hedging North America, and of output from generating facilities and fuel " provide home improvements, service electric and gas costs), appliances, service heating, air conditioning, plumbing,

- deployment of risk capital through portfolio electrical, and indoor air quality systems, and provide management and trading activities, natural gas marketing to residential customers in Central

- gas retail energy products and services to Maryland.

commercial, industrial, and governmental During 2006, we sold six of our gas-fired facilities. In customers, addition, we own several investments that we do not consider to fossil, nuclear, and interests in hydroelectric be core operations. These include financial investments and real generating facilities and qualifying facilities, fuel estate projects. During 2005, we sold our other nonregulated processing facilities, and power projects in the international investments. We discuss the sales of our gas-fired United States, plants and our international investments in more detail in

- upstream (exploration and production) and Note 2.

downstream (transportation and storage) natural Our Merchant Energy, Regulated Electric, and Regulated gas operations, Gas reportable segments are strategic businesses based principally

- coal sourcing and logistics services for the variable upon regulations, products, and services that require different or fixed supply needs of global customers, and technology and marketing strategies. We evaluate the generation operations and maintenance and new performance of these segments based on net income. We nuclear development, including consulting account for intersegment revenues using market prices. We services. present a summary of information by operating segment on the next page.

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Reportable Segments Merchant Regulated Regulated Other Energy Electric Gas Nonregulated Business Business Business Businesses Eliminations Consolidated (In millions) 2007 Unaffiliated revenues $17,545.1 $2,455.6 $ 943.0 $249.5 $ - $21,193.2 Intersegment revenues 1,199.4 0.1 19.8 0.3 (1,219.6) -

Total revenues 18,744.5 2,455.7 962.8 249.8 (1,219.6) 21,193.2 Depreciation, depletion, and amortization 269.9 187.4 46.8 53.7 - 557.8 Fixed charges 86.9 107.6 30.9 8.6 71.6 305.6 Income tax expense (benefit) 332.7 64.6 22.8 8.2 - 428.3 Income from discontinued operations (0.9) - - - (0.9)

Net income (a) 678.3 97.9 28.8 16.5 - 821.5 Segment assets 16,151.1 4,378.4 1,293.6 458.6 (336.0) 21,945.7 Capital expenditures 1,178.0 340.0 62.0 85.0 - 1,665.0 2006 Unaffiliated revenues $16,048.2 $2,115.9 $ 890.0 $230.8 $ - $19,284.9 Intersegment revenues 1,118.0 - 9.5 0.2 (1,127.7) -

Total revenues 17,166.2 2,115.9 899.5 231.0 (1,127.7) 19,284.9 Depreciation, depletion, and amortization 258.7 181.5 46.0 37.7 - 523.9 Fixed charges 191.7 86.9 28.9 10.5 10.7 328.7 Income tax expense (benefit) 250.2 78.0 27.0 (4.2) -. 351.0 Income from discontinued operations 186.9 - - 0.9 - 187.8 Net income (b) 767.0 120.2 37.0 12.2 936.4 Segment assets 16,387.3 3,783.2 1,252.8 887.8 (509.5) 21,801.6 Capital expenditures 768.0 297.0 63.0 21.0 - 1,149.0 2005 Unaffiliated revenues $13,763.1 $2,036.5 $ 961.7 $207.0 $ - $16,968.3 Intersegment revenues 859.3 - 11.1 - (870.4)

Total revenues 14,622.4 2,036.5 972.8 207.0 (870.4) 16,968.3 Depreciation, depletion and amortization 250.4 185.8 46.6 40.2 523.0 Fixed charges 178.0 80.3 26.4 10.0 15.5 310.2 Income tax expense (benefit) 41.7 101.2 21.2 (0.2) 163.9 Income from discontinued operations 73.8 20.6 94.4 Cumulative effects of changes in accounting principles (7.4) 0.2 (7.2)

Net income (c) 425.8 149.4 26.7 21.2 623.1 Segment assets 16,620.4 3,424.4 1,222.5 476.1 (269.5) 21,473.9 Capital expenditures 709.0 241.0 50.0 32.0 1,032.0 (a) Our merchant energy business recognized an after-tax loss of $12.2 million related to a cancelled wind development project, an after-tax gain of $39.2 million on sales of CEP equity, and an after-tax charge of $1.4 million for workforce reduction costs as described in more detail in Note 2.

(b) Our merchant energy business recognized an after-tax gain of $47.1 million on sale of gas-firedplants and an after-tax gain of

$17.9 million on the initialpublic offering of CEP as discussed in more detail in Note 2. Our merchant energy business, our regulated electric business, our regulatedgas business, and our other nonregulated businesses recognized after-tax charges of $21.3 million,

$0.8 million, $0.4 million, and $0.2 million for merger-relatedcosts and workforce reduction costs as described in more detail in Note 2.

(c) Our merchant energy business, our regulated electric business, our regulatedgas business, and our other nonregulatedbusinesses recognized after-tax charges of $13.0 million, $3.7 million, $1.3 million, and $0.2 million for merger-related costs and workforce reduction costs as described in more detail in Note 2.

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4Investments Investments in Qualifying Facilities and Power Projects, Investments in qualifying facilities, domestic power projects, CEP, and Joint Ventures joint ventures and CEP consist of the following:

QualiifingFacilities and Power Projects Our merchant energy business holds up to a 50% voting interest At December 31, 2007 2006 in 24 operating domestic energy projects that consist of electric generation, fuel processing, or fuel handling facilities. Of these (In millions) 24 projects, 17 are "qualifying facilities" tl4at receive certain Qualifying facilities and domestic power exemptions and pricing under the Public Utility Regulatory projects:

Policies Act of 1978 based on the facilities' energy source or the Coal $119.6 $125.7 use of a cogeneration process. Hydroelectric 54.7 55.1 Geothermal 37.6 40.5 CEP Biomass 43.6 46.6 In November 2006, CEP, a limited liability company formed by Fuel Processing 26.8 33.7 our merchant energy business, completed an initial public Solar 7.0 7.0 offering. As of December 31, 2006, we owned approximately CEP 143.0 54% of CEP and consolidated CEP During the second quarter Joint Ventures:

of 2007, CEP issued additional equity to ihe public and our Shipping JV 56.6 ownership percentage fell below 50%. Therefore, we UNE 52.2 deconsolidated CEP and began accounting for our investment Other 1.1 using the equity method under Accounting Principles Board Total $542.2 $308.6 Opinion (APB) No. 18, The Equity Method ofAccounting for Investments in Common Stock. As of December 31, 2007, we Investments in qualifying facilities, domestic power projects, hold a 28.5% voting interest in CEP. CEP and joint ventures were accounted for under the following methods:

Joint Ventures In December 2006, we formed a shipping'joint venture in At December 31, 2007 2006 which our merchant energy business has a 50% ownership (In millions) interest. The joint venture will own and operate six freight ships.

In 2007, we made cash contributions of approximately Equity method $535.2 $301.6

$57 million to the joint venture. Cost method 7.0 7.0 In August 2007, we formed a joint venture, UniStar Total $542.2 $308.6 Nuclear Energy, LLC (UNE) with an affiliate of Electricite de France, SA (EDF). We have a 50% ownership interest in this Our percentage voting interests in these investments joint venture to develop, own, and operate new nuclear projects accounted for under the equity method range from 16% to in the United States and Canada. The agreement with EDF 50%. Equity in earnings of these investments was $8.3 million includes a phased-in investment of $625 million by EDF in in 2007, $13.8 million in 2006, and $3.6 million in 2005.

UNE. In 2007, EDF invested $350 million in UNE, and we contributed the new nuclear line of businesses we have Investments Classified as Available-for-Sale developed over the past two years, which included assets with a We classify the following investments as available-for-sale:

book value of $48.7 million and the right'to develop possible " nuclear decommissioning trust funds, new nuclear projects at our existing nuclear plant locations. " marketable equity securities, and Upon reaching certain licensing milestones, EDF will contribute " trust assets securing certain executive benefits.

up to an additional $275 million in UNE. This means we do not expect to hold them to maturity, As of December 31, 2007, UNE's capitalized construction and we do not consider them trading securities.

work in progress was approximately $135 million. In the event that our portion of any losses incurred by UNE exceed our investment, we will continue to record those losses in earnings

.unless it is determined that UNE will cease operations and is subsequently dissolved.

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We show the fair values, gross unrealized gains and losses, At December 31, 2006 and book value basis for all of our available-for-sale securities in Less than 12 months the following tables. We use specific identification to determine 12 months or more Total cost in computing realized gains and losses. Description of Fair Unrealized Fair Unrealized Fair Unrealized Securities Value Losses Value Losses Value Losses Book Unrealized Unrealized Fair At December 31, 2007 Value Gains Losses Value (In millions)

(In' millions) Marketable equity securities $ 9.5 $(0.8) $12.4 $(1.7) $21.9 $(2.5)

Marketable equity Corporate debt and securities $ 819.9 $266.3 $(0.2) $1,086.0 U.S. treasuries 10.3 - 23.7 (0.3) 34.0 (0.3)

Corporate debt and State municipal U.S. treasuries 224.5 5.4 - 229.9 bonds 4.8 - 14.0 (0.2) 18.8 (0.2)

State municipal bonds 48.3 2.5 - 50.8 Total temporarily Totals impaired

$1,092.7 $274.2 $(0.2) $1,366.7 securities $24.6 $(0.8) $50.1 $(2.2) $74.7 $(3.0)

Book Unrealized Unrealized Fair Gross and net realized gains and losses on available-for-sale At December 31, 2006 Value Gains Losses Value securities were as follows:

(In millions)

Marketable equity Year ended December 31, 2007 2006 2005 securities $ 811.0 $221.1 $(3.3) $1,028.8 (In millions)

Corporate debt and U.S.

Gross realized gains $ 33.5 $13.3 $12.3 treasuries 160.1 1.9 (0.3) 161.7 Gross realized losses (30.9) (13.0) (9.3)

State municipal bonds 68.1 5.4 (0.2) 73.3 Net realized gains $ 2.6 $ 0.3 $ 3.0 Totals $1,039.2 $228.4 $(3.8) $1,263.8 Gross realized losses for 2007 include an $8.5 million In addition to the above securities, the nuclear pre-tax other than temporary impairment (as explained above) decommissioning trust funds included $1 1.7 million at for investments whose fair value declined below their book value.

December 31, 2007 and $24.1 million at December 31, 2006 of The corporate debt securities, U.S. Government agency cash and cash equivalents.

obligations, and state municipal bonds mature on the following The preceding tables include $256.7 million in 2007 of net schedule:

unrealized gains and $206.1 million in 2006 of net unrealized gains associated with the nuclear decommissioning trust funds At December 31, 2007 that are reflected as a change in the nuclear decommissioning trust funds in our Consolidated Balance Sheets. (In millions)

Our available-for-sale investments in our nuclear Less than 1 year $ 10.9 decommissioning trust funds are managedby third parties who 1-5 years 97.4 have independent discretion over the purchases and sales of 5-10 years 74.5 securities. Effective January 1, 2007, we recognize impairments More than 10 years 97.9 for any of these investments for which the fair value declines Total maturities of debt securities $280.7 below our book value. In 2007, we recognized $8.5 million pre-tax of impairment losses on our nuclear decommissioning trust investments.

Prior to 2007, we had unrealized losses relating to certain available-for-sale investments in our nuclear decommissioning trust funds that we considered to be temporary in nature and, therefore, we did not recognize an impairment for any security with an unrealized loss. We show the fair values and unrealized losses of our investments that were in a loss position at December 31, 2006 and were not impaired in the table below.

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Investments in Variable Interest Entities The maximum exposure to loss represents the loss that we RSB BondCo LLC would incur in the unlikely event that our interests in all of In 2007, BGE formed RSB BondCo LLC, (BondCo), a special these entities were to become worthless and we were required to purpose bankruptcy-remote limited liability company. In June fund the full amount of all guarantees associated with these 2007, BondCo purchased rate stabilization property from BGE, entities. Our maximum exposure to loss as of December 31, including the right to assess, collect, and receive non-bypassable 2007 consists of the following:

rate stabilization charges payable by all residential electric " outstanding receivables, loans, and letters of credit customers of BGE. These charges are being assessed in order to totaling $166.4 million, recover previously incurred power purchase costs that BGE

• the carrying amount of our investment totaling deferred pursuant to Senate Bill 1. $46.1 million, and BGE has determined that BondCo is a variable interest

• debt and performance guarantees totaling $2.0 million.

entity for which it is also the primary beneficiary. As a result, We assess the risk of a loss equal to our maximum exposure BGE consolidated BondCo. We discuss the consolidation to be remote.

method of accounting in more detail in Note 1.

Customer Contract Restructuring Unconsolidated Variable Interest Entities In March 2005, our merchant energy business closed a We have a significant interest in the follovking vsariable interest transaction in which we assumed from a counterparty two power entities (VIE) for which we are not the primary beneficiary: sales contracts with existing VIEs. Under the contracts, we sell power to the VIEs which, in turn, sell that power to an electric Nature of Date of distribution utility through 2013.

VIE Involvement. Involvement The VIEs previously were created by the counterparty to Prior to 2003 issue debt in order to monetize the value of the original Power projects and Equity investment contracts to purchase and sell power. The difference between the fuel supply entities and guarantees' contract prices at which the VIEs purchase and sell power is Power contract Power sale March 2005 used to service the debt of the VIEs, which totaled $558 million monetization agreements, loahs, at December 31, 2007.

entities and guarantees The market price for power at the closing of our transaction was higher than the contract price under the existing Oil & gas fields Equity investment power sales contracts we assumed. Therefore, we received Retail power supply Power sale agreement September 2006 compensation totaling $308.5 million, equal to the net present ith the power value of the difference between the contract price under the We discuss the nature of our involvement vtract power sales contracts and the market price of power at closing.

contract monetization VIEs in the Customer Con We used a portion of this amount to settle $68.5 million of Restructuring section below.

The following is summary information avai lable as of existing derivative liabilities with the same counterparty, and we also loaned $82.8 million to the holder of the equity in the December 31, 2007 about the VIEs in which wificiary: VIEs. As a result, we received net cash at closing of significant interest, but are not the primary bene $157.2 million. We also guaranteed our subsidiaries' performance under the power sales contracts.

Power The table below summarizes the transaction and the net Contract 1C

! Power ontract Monetization

• .l_ cash received at closing:

Monetization VIEsOthier VIEs VIEs Total (In millions)

In millions) Groks compensation from original power sales Total assets $736.6 $358.1 $1,094.7 contracts counterparty equal to fair value of Total liabilities 583.2 195.6 778.8 power sales contracts at closing $308.5 Our ownership interest 46.1 46.1 Settlement of existing derivative liabilities (68.5)

Other ownership interests 153.4 116.4 269.8 Our maximum exposure Third-party loan secured by equity in VIE (82.8) to loss 56.5 158.0 214.5 Net cash received at closing $157.2 101 i

We recorded the closing of this transaction in our financial We recorded the gross compensation we received to assume statements as follows: the power sales contracts as a financing cash inflow because it Cash Flows constitutes a prepayment for a portion of the market price of Balance Sheet power, which we will sell to the VIEs over the term of the Fair value of power Derivative liabilities Fin ancing cash contracts and does not represent a cash inflow from current sales contracts irnflow period operating activities. We record the ongoing cash flows assumed related to the sale of power to the VIEs as a financing cash (designated as inflow in accordance with SFAS No. 149, Amendment of FASB cash-flow hedge) Statement No. 133 on Derivative and Hedging Activities.

Settlement of Derivative liabilities, Op erating cash If the electric distribution utility were to default under its existing 0outflow obligation to buy power from the VIEs, the equity holder could derivative transfer its equity interests to us in lieu of repaying the loan. In liabilities this event, we would have the right to seek recovery of our losses Third-party loan Other assets Inv eting cafrom the electric distribution utility.

outflow 5 Intangible Assets Goodwill Intangible Assets Subject to Amortization Goodwill is the excess of the cost of an acquisition over the fair Intangible assets with finite lives are subject to amortization over value of the net assets acquired. Our goodwill balance is their estimated useful lives. The primary assets included in this primarily related to our merchant energy business acquisitions. category are as follows:

The changes in the carrying amount of goodwill for the years At December 31, 2007 2006 ended December 31, 2007 and 2006 are as follows: Accumul- Accumul-Balance at Goodwill Balance at Gross ated Gross ated Carrying Amortiz- Net Carrying Amortiz- Net 2007 January 1, Acquired Other(a) December 31, Amount ation Asset -Amount ation Asset (In millions) (In millions)

Goodwill $157.6 $103.4 $0.3 $261.3 Software $494.0 $(232.3) $261.7 $392.3 $(182.6) $209.7 Permits and licenses 62.3 (8.0) 54.3 60.4 (5.9) 54.5 Balance at Goodwill Balance at Operating 2006 January 1, Acquired Other(a) December 31, manuals and procedures 38.6 (8.4) 30.2 38.5 (7.1) 31.4 (In millions) Other 26.8 (19.9) 6.9 26.3 (17.2) 9.1 Goodwill $147.1 $11.1 $(0.6) $157.6 Total $621.7 $(268.6) $353.1 $517.5 $(212.8) $304.7 (a) Other represents purchase price adjustments.

BGE had intangible assets with a gross carrying amount of $194.1 million Goodwill is not amortized; rather, it is evaluated for and accumulatedamortization of $124.4 million at December 31, 2007 and

$191.3 million and accumulatedamortization of $109.2 million at impairment at least annually. We evaluated our goodwill in 2007 December 31, 2006 that are included in the table above. Substantially all of and 2006 and determined that it was not impaired. For tax BME's intangible assets relate to software.

purposes, $227.6 million of our goodwill balance is deductible.

We recognized amortization expense related to our intangible assets as follows:

Year Ended December 31, 2007 2006 2005 (In millions)

Nonregulated businesses $51.9 $37.2 $30.6 BGE 20.2 18.6 26.3 Total Constellation Energy $72.1 $55.8 $56.9 102

The following is our, and BGE's, estimated amortization We present separately in our Consolidated Balance Sheets expense for 2008 through 2012 for the intangible assets included the net unamortized energy contract assets and liabilities for in our, and BGE's, Consolidated Balance Sheets at these contracts. The table below presents the gross and net December 31, 2007: carrying amount and accumulated amortization of the net liability that we have recorded in our Consolidated Balance Year Ended December 31, 2008 2009 2010 2011 2012 Sheets:

(In millions) At December 31 2007 2006 Estimated amortization expense- Accumul- Accumul-Nonregulated businesses $61.4 $60.2 $53.9 $48.3 $37.2 aed ated Estimated amortization expense- Carrying Amortiz- Net Carrying Amortiz- Net BGE 18.3 15.0 13.1 10.9 6.1 Amount ation Liability Amount ation Liability (In millions)

Total estimated amortization Unamortized energy expense-Constellation Energy $79.7 $75.2 $67.0 $59.2 $43.3 contracts, net $(2,290.0) $889.5 $(1,400.5) $(1,642.0) $464.5 $(1,177.5)

Unamortized Energy Contracts The table below presents the estimated net favorable impact As discussed in Note 1, unamortized energy contract assets and on our operating results for the amortization for these assets and liabilities represent the remaining unamortized balance of liabilities over the next five-years:

nonderivative energy contracts acquired or derivatives designated Year Ended December 31, 2008 2009 2010 2011 2012 as normal purchases and normal sales, which we previously recorded as derivative assets and liabilities. (In millions)

During 2007, we acquired several pre-existing power-related Estimated amortization $358.9 $308.8 $289.4 $84.4 $79.3 contracts that had been originated by other parties in prior periods when market prices were lower than current levels. The net proceeds received in this transaction were primarily recorded as a net liability in "Unamortized energy contracts."

6Regulatory Assets (net)

As discussed in Note 1, the Maryland PSC and the FERC We summarize regulatory assets and liabilities in the provide the final determination of the rates we charge our following table, and we discuss each of them separately below.

customers for our regulated businesses. Generally, we use the same accounting policies and practices used by nonregulated At December 31, 2007 2006 companies for financial reporting under accounting principles (In millions) generally accepted in the United States of America. However, Deferred fuel costs sometimes the Maryland PSC or FERC orders an accounting Rate stabilization deferral $ 593.4 $ 326.9 treatment different from that used by nonregulated companies to Other 19.4 37.8 Electric generation-related regulatory asset 135.9 154.8 determine the rates we charge our customers. When this Net cost of removal (182.3) (161.3) happens, we must defer certain regulated expenses and income Income taxes recoverable through future rates in our Consolidated Balance Sheets as regulatory assets and (net) 63.9 67.1 liabilities. We then record them in our Consolidated Statements Deferred postretirement and postemployment of Income (using amortization) when we include them in the benefit costs 16.1 19.3 rates we charge our customers. Deferred environmental costs 8.9 10.0 Workforce reduction costs 2.4 4.9 Other (net) (6.6) (8.0)

Total regulatory assets (net) 651.1 451.5 Less: Current portion of regulatory assets (net) 74.9 62.5 Long-term portion of regulatory assets (net) $ 576.2 $ 389.0 103

Deferred Fuel Costs Another portion of this regulatory asset represents the Rate Stabilization Deferral decommissioning and decontamination fund payment for federal In June 2006, Senate Bill 1 was enacted in Maryland and uranium enrichment facilities that do not earn a regulated rate imposed a rate stabilization measure that calpped rate increases of return on the rate base investment. These amounts were by BGE for residential electric customers at 15% from July 1, $2.3 million at December 31, 2007 and $5.5 million at 2006 to May 31, 2007. As a result, BGE recorded a regulatory- December 31, 2006. Prior to the deregulation of electric asset on its Consolidated Balance Sheets equal to the difference generation, these costs were recovered through the electric fuel between the costs to purchase power and the revenues collected rate mechanism, and were excluded from rate base. We will from customers, as well as related carrying ',charges based on continue to amortize this amount through 2008.

short-term interest rates from July 1, 2006 to May 31, 2007. In addition, as required by Senate Bill 1, the Maryland PSC Net Cost of Removal approved a plan that allowed residential electric customers the As discussed in Note 1, we use the group depreciation method option to further defer the transition to market rates from for the regulated business. This method is currently an June 1, 2007 to January 1, 2008. Customers participating in the acceptable method of accounting under accounting principles deferral from June 1, 2007 to December 3 1, 2007 will repay the generally accepted in the United States of America and is widely deferred charges without interest. During 2007 and 2006, BGE used in the energy, transportation, and telecommunication deferred $306.4 million and $326.9 millioh, respectively, of industries.

electricity purchased for resale expenses and carrying charges, if Historically, under the group depreciation method, the applicable, as a regulatory asset related to the rate stabilization anticipated costs of removing assets upon retirement were plans. During 2007, BGE recovered $39.2, million of electricity provided for over the life of those assets as a component of purchased for resale expenses and carrying ,charges related to the depreciation expense. However, effective January 1, 2003, we rate stabilization plan regulatory asset. BGE began amortizing adopted SFAS No. 143, Accountingfor Asset Retirement the regulatory asset to earnings over a period not to exceed ten Obligations. In addition to providing the accounting years when collection from customers began in June 2007. requirements for recognizing an estimated liability for legal obligations associated with the retirement of tangible long-lived Other assets, SFAS No. 143 precludes the recognition of expected net As described in Note 1, deferred fuel costs 'are the difference future costs of removal as a component of depreciation expense between our actual costs of purchased energy and our fuel rate or accumulated depreciation.

revenues collected from customers. We reduce deferred fuel costs BGE is required by the Maryland PSC to use the group as we collect them from our customers and increase deferred fuel depreciation method, including cost of removal, under regulatory costs when we refund them to our customers. accounting. For ratemaking purposes, net cost of removal is a We exclude deferred fuel costs from rate base because their component of depreciation expense and the related accumulated existence is relatively short-lived. These costs are recovered in the depreciation balance is included as a net reduction to BGE's rate following year through our fuel rates. base investment. For financial reporting purposes, BGE continues to accrue for the future cost of removal for its Electric Generation-Related Regulato~ry Asset regulated gas and electric assets by increasing its regulatory As a result of the deregulation of electric generation, BGE ceased liability. This liability is relieved when actual removal costs are to meet the requirements for the application of SFAS No. 71 for incurred.

the previous electric generation portion of its business. In accordance with SFAS No. 101, Regulated Enterprises- Income Taxes Recoverable Through Future Rates (net)

Accountingfor the Discontinuation ofApplication of FASB As described in Note 1, income taxes recoverable through future Statement No. 71, and EITF 97-4, Deregulation of the Pricingof rates are the portion of our net deferred income tax liability that Electricity--Issues Related to the Applicationvof FASB Statements is applicable to our regulated business, but has not been reflected No. 71 and 101, BGE wrote-off all of its individual, generation- in the rates we charge our customers. These income taxes related regulatory assets and liabilities. BGE established a single, represent the tax effect of temporary differences in depreciation generation-related regulatory asset to be collected through its and the allowance for equity funds used during construction, regulated transmission and distribution business, which is being offset by differences in deferred tax rates and deferred taxes on amortized on a basis that approximates the pre-existing deferred investment tax credits. We amortize these amounts as individual regulatory asset amortization schedules. the temporary differences reverse.

A portion of this regulatory asset represents income taxes recoverable through future rates that do not earn a regulated rate of return. These amounts were $81.1 million as of December 31, 2007 and $89.4 million as of December 31, 2006. We will continue to amortize this amount through 2017.

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Deferred Postretirement and Postemployment Benefit Workforce Reduction Costs Costs The portions of the costs associated with our Voluntary Special Deferred postretirement and postemployment benefit costs are Early Retirement Program and workforce reduction programs the costs we recorded under SFAS No. 106, Employers' that relate to BGE's gas business are deferred as regulatory assets Accounting for Postretirement Benefits Other Than Pensions, and in accordance with the Maryland PSC's orders in prior rate SFAS No. 112, Employers'Accountingfor Pbstemployment Benefits, cases. As a result of a 2005 gas base rate case, the remaining in excess of the costs we included in the rates we charge our regulatory assets associated with workforce reductions totaling customers. We began amortizing these costs over a 15-year $7.3 million as of December 31, 2005 are being amortized over period in 1998. a 3-year period that began in January 2006. These remaining regulatory assets were previously amortized over 5-year periods Deferred Environmental Costs beginning in January and February 2002.

Deferred environmental costs are the estimated costs of investigating and cleaning up contaminated sites we own. We Other (Net) discuss this further in Note 12. We amortized $21.6 million of Other regulatory assets are comprised of a variety of current these costs (the amount we had incurred through October 1995) assets and liabilities that do not earn a regulatory rate of return and are amortizing $6.4 million of these costs (the amount we due to their short-term nature.

incurred from November 1995 through June 2000) over 10-year periods in accordance with the Maryland PSC's orders. We applied for and received rate relief for an additional $5.4 million of clean-up costs incurred during the period from July 2000 through November 2005. These costs are being amortized over a 10-year period that began in January 2006.

I 7Pension, Postretirement, Othe'r Postemployment, and Employee Savings Plan Benefits We offer pension, postretirement, other postemployment, and Pension Benefits employee savings plan benefits. BGE employees participate in We sponsor several defined benefit pension plans for our the benefit plans that we offer. We describe each of our plans employees. These include basic qualified plans that most separately below. Nine Mile Point offers its own pension, employees participate in and several non-qualified plans that are postretirement, other postemployment, and employee savings available only to certain employees. A defined benefit plan plan benefits to its employees. The benefits for Nine Mile Point specifies the amount of benefits a plan participant is to receive are included in the tables beginning below. using information about the participant. Employees do not We use a December 31 measurement date for our pension, contribute to these plans. Generally, we calculate the benefits postretirement, other postemployment, and employee savings under these plans based on age, years of service, and pay.

plans. The following table summarizes our: defined benefit Sometimes we amend the plans retroactively. These liabilities and their classification in our Consolidated Balance retroactive plan amendments require us to recalculate benefits Sheets: related to participants' past service. We amortize the change in the benefit costs from these plan amendments on a straight-line At December 31, 2007 22006 basis over the average remaining service period of active (In millio ?S) employees.

Pension benefits $385.7 $4468.6 We fund the qualified plans by contributing at least the Postretirement benefits 421.5 441.5 minimum amount required under IRS regulations. We calculate Postemployment benefits 66.3 57.0 the amount of funding using an actuarial method called the Total defined benefit obligations 873.5 9967.1 projected unit credit cost method. The assets in all of the plans Less: Amount recorded in other current liabilities 44.9 38.8 at December 31, 2007 and 2006 were mostly marketable equity Total noncurrent defined benefit obligations $828.6 $S928.3 and fixed income securities.

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Postretirement Benefits We were required to remeasure the additional minimum We sponsor defined benefit postretirement'health care and life pension liability prior to calculating the impact of adopting insurance plans that cover the majority of our employees. SFAS No. 158, Employer's Accountingfor Defined Benefit Pension Generally, we calculate the benefits under these plans based on and Other Postretirement Plans, an amendment of FASB Statement age, years of service, and pension benefit levels or final base pay. No. 87, 106 and 132(R), on December 31, 2006. We recorded We do not fund these plans. For nearly all of the health care additional minimum pension liability adjustments through plans, retirees make contributions to cover a portion of the plan December 31, 2006 as follows:

costs. For the life insurance plan, retirees do not make contributions to cover a portion of the plan costs. Increase (Decrease)

Effective in 2002, we amended our postretirement medical Pension Accumulated Other plans for all subsidiaries other than Nine Mile Point. Our Liability Intangible Comprehensive Loss contributions for retiree medical coverage for future retirees who Adjustment Asset

• Pre-tax After-tax were under the age of 55 on January 1, 2002 are capped at the (In millions) 2002 level. We also amended our plans to' increase the Medicare Cumulative through 2004 $ 359.6 $40.6 $(319.0) $(192.8) eligible retirees' share of medical costs. 2005 121.4 (6.1) (127.5) (77.1) 2006 (131.1) (5.9) 125.2 75.6 In 2003, the President signed into law the Medicare Prescription Drug Improvement and Modernization Act of 2003 Total $ 349.9 $28.6 $(321.3) $(194.3)

(the Act). This legislation provides a prescription drug benefit Included in "Other assets" in our ConsolidatedBalance Sheets.

for Medicare beneficiaries, a benefit that we provide to our Medicare eligible retirees. Our actuaries concluded that Under SFAS No. 158, we are required to reflect the funded prescription drug benefits available under our postretirement status of our pension plans in terms of the projected benefit medical plan are "actuarially equivalent" t6 Medicare Part D and obligation, which is higher than the accumulated benefit thus qualify for the subsidy under the Act. This subsidy reduced obligation because it includes the impact of expected future our 2007 Accumulated Postretirement Benefit Obligation by compensation increases on the pension obligation. In addition,

$40.8 million and our 2007 postretirement medical payments by SFAS No. 158 requires us to reflect the funded status of our

$2.7 million. postretirement benefits in terms of the accumulated postretirement benefit obligation.

Liability Adjustments Upon adoption of SFAS No. 158, we reversed the Our pension accumulated benefit obligation has exceeded the intangible asset associated with the minimum pension liability fair value of our plan assets since 2001. At December 31, 2007 adjustment above, increased our pension and postretirement and 2006, our pension obligations were greater than the fair liabilities, and reduced equity. The following table summarizes value of our plan assets for our qualified and our nonqualified the impact of SFAS No. 158 adjustments recorded at pension plans as follows: December 31, 2007 and 2006:

Qualified Plans Non-Qualified Increase (Decrease)

At December 31, 2007 Nine Mile Other Plans Total Accumulated Other (In millions) Postretiremeent Comprehensive Pension Benefit Intangible (Income) Loss Accumulated benefit Liability Liability Asset Pre-tax After-tax obligation $98.0 $1,332.2 $69.7 $1,499.9 Fair value of assets 78.6 1,179.9 - 1,258.5 (In millions)

Unfunded obligation $19.4 $ 152.3 $69.7 $ 241.4 December 31, 2007 (1) $ 3.1 $(22.5) $ - $ 19.4 $ 11.6 December 31, Qualified Plans Non-Qualified 2006 $152.5 $ 99.7 $(28.6) $(280.8) $(169.5)

At December 31, 2006 Nine Mile Other Plans Total (1) Amounts primarily reflect net impact of 2007 actuarialgains and losses.

(In millions)

Accumulated benefit obligation $107.5 $1,306.0 $63.8 $1,477.3 Obligations and Assets Fair value of assets 54.6 1,106.6 - 1,161.2 As a result of workforce reduction initiatives in the generation Unfunded obligation $ 52.9 $ 199.4 $63.8 $ 316.1 business, pension and postretirement special termination benefits were recorded in 2007 and 2006. We discuss the workforce reduction initiatives further in Note 2.

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We show the change in the benefit obligations and plan Net Periodic Benefit Cost and Amounts Recognized in assets of the pension and postretirement benefit plans in the Other Comprehensive Income following tables. Postretirement benefit plan amounts are We show the components of net periodic pension benefit cost in presented net of expected reimbursements under Medicare the following table:

Part D.

Year Ended December 31, 2007 2006 2005 Pension Postretirement (In millions)

Benefits Benefits Components of net periodic pension benefit cost 2007 2006 2007 2006 Service cost $ 49.4 $ 49.0 $ 44.8 (In millions) Interest cost 94.7 89.3 83.9 Change in benefit Expected return on plan assets (102.6) (96.6) (100.2) obligation (1) Amortization of unrecognized prior service Benefit obligation at cost 5.2 5.7 5.7 January 1 $1,629.8 $1,678.6 $441.5 $460.4 Recognized net actuarial loss 32.7 37.3 25.1 Service cost 49.4 49.0 6.5 7.7 Amount capitalized as construction cost (11.7) (13.4) (7.4)

Interest cost 94.7 89.3 24.4 23.7 Net periodic pension benefit cost (1) $ 67.7 $ 71.3 $ 51.9 Plan participants' (1) Net periodic pension benefit cost excludes SFAS No. 88 termination contributions - - 8.7 8.3 benefits of $1.2 million in 2007, SEAS No. 88 settlement charge of Actuarial (gain) loss (27.6) (49.1) (22.3) (27.1) $12.7 million and termination benefits of $4.2 million in 2006, and Special termination benefits 1.2 4.2 0.3 3.5 SFAS No. 88 settlement charge of $4.4 million in 2005. BGE' portion Benefits paid (2) (3) (103.3) (142.2) (37.6) (35.0) of our net periodicpension benefit costs, excluding amount capitalized, was $21.8 million in 2007, $25.0 million in 2006, and $15.0 million Benefit obligation at in 2005. The vast majority of our retirees are BGE employees.

December 31 $1,644.2 $1,629.8 $421.5 $441.5 We show the components of net periodic postretirement (1) Amounts reflect projected benefit obligationfor pension benefits and benefit cost in the following table:

accumulated postretirementbenefit obligation for postretirement benefits.

(2) Pension benefits paid include annuity payments, lump-sum distributions, Year Ended December 31, 2007 2006 2005 and transfers to nonqualifieddeferred compensation plans.

(3) Postretirementbenefits paid are net of Medicare Part D reimbursements. (In millions)

Components of net periodic postretirement benefit cost Pension Postretirement Service cost $ 6.5 $ 7.7 $ 7.6 Benefits Benefits Interest cost 24.4 23.7 23.8 2007 2006 2007 2006 Amortization of transition obligation 2.1 2.1 2.1 (In millions) Recognized net actuarial loss 4.1 6.6 6.4 Amortization of unrecognized prior service Change in plan assets cost (3.5) (3.5) (3.5)

Fair value of plan assets at Amount capitalized as construction cost (7.7) (8.2) (7.7)

January 1 $1,161.2 $1,107.1 $ - $ -

Actual return on plan assets 71.3 141.1 - - Net periodic postretirement benefit cost (1) $25.9 $28.4 $28.7 Employer contribution(1) 129.3 55.2 28.9 26.7 (1) Net periodic postretirement benefit cost excludes SFAS No. 106 Plan participants' termination benefits of $0.3 million in 2007 and $3.5 million in contributions - - 8.7 8.3 2006 BGE' portion of our net periodic postretirement benefit cost, Benefits paid(2) (3) (103.3) (142.2) (37.6) (35.0) excluding amounts capitalized, was $15.5 million in 2007,

$16.6 million in 2006, and $17.4 million in 2005.

Fair value of plan assets at December 31 $1,258.5 $1,161.2 $ - $ -

(1) Includes benefit payments for unfunded plans.

(2) Pension benefits paid include annuity payments, lump-sum distributions, and transfers to nonqualified deferred compensation plans.

(3) Postretirementbenefits paid are net of Medicare Part D reimbursements.

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As a result of adopting SFAS No. 158, the following is a Our discount rate is based on a bond portfolio analysis of summary of amounts we have recorded in "Accumulated other high quality corporate bonds whose maturities match our comprehensive income" and of expected amortization of those expected benefit payments. Our 8.75% overall expected amounts over the next twelve months: long-term rate of return on plan assets reflects our long-term investment strategy in terms of asset mix targets and expected Expected returns for each asset class.

Amortiz- Annual health care inflation rate assumptions also impact Pension Postretirement ation the calculation of our postretirement benefit obligation and Benefits Benefits Next periodic cost. We assumed the following health care inflation 2007 2006 2007 2006 12 Months rates to produce average claims by year as shown below:

(In millions)

Unrecognized At December 31, 2007 2006 actuarial loss $ 445.9 $ 475.7 $ 90.2 $116.6 $30.6 Unrecognized Next year 9.0% 8.5%

prior service Following year 8.0% 8.0%

cost 21.4 26.7 (26.2) (29.7) 1.4 Ultimate trend rate 5.0% 5.0%

Unrecognized Year ultimate trend rate reached 2014 2014 transition A one-percent increase in the health care inflation rate obligation - - 10.7 12.8 2.1 from the assumed rates would increase the accumulated Total $ 467.3 $ 502.4 $ 74.7 $ 99.7 $34.1 postretirement benefit obligation by approximately $29 million as of December 31, 2007 and would increase the combined Expected Cash Benefit Payments service and interest costs of the postretirement benefit cost by The pension and postretirement benefits we expect to pay in approximately $2 million annually.

each of the next five calendar years and in the aggregate for the A one-percent decrease in the health care inflation rate subsequent five years are shown below. These estimated benefits from the assumed rates would decrease the accumulated are based on the same assumptions used to measure the benefit postretirement benefit obligation by approximately $25 million obligation at December 31, 2007, but include benefits as of December 31, 2007 and would decrease the combined attributable to estimated future employee service. service and interest costs of the postretirement benefit cost by approximately $2 million annually.

Postretirement Benefits Qualified Pension Plan Assets Before After The asset allocations for our qualified pension plans were as Pension Medicare Medicare follows:

Benefits* Part D Subsidy Part D (In millions)

At December 31, 2007 2006 2008 $107.2 $ 31.2 $(2.4) $ 28.8 2009 102.3 32.3 (2.6) 29.7 Equity securities 62% 64%

2010 115.9 33.0 (2.8) 30.2 Debt securities 31 28 2011 108.4 33.6 (2.9) 30.7 Other 7 8 2012 121.8 33.9 (3.1) 30.8 2013-2017 763.4 178.6 (16.2) 162.4 Total 100% 100%

• Excludes transfers to nonqualified deferred compensation plans The category "Other" primarily represents investments in financial limited partnerships. Our long-term pension plan Assumptions investment strategy is to seek an asset mix of 58% equity, 30%

We made the assumptions below to calculate our pension and fixed income, and 12% other investments. We rebalance our postretirement benefit obligations and periodic cost. portfolio periodically when the sum of equity and other investments differs from 70% by three percentage points or Pension Postretirement Assumption Benefits Benefits Impacts more, we change an outside investment advisor, or we make 2007 2006 2007 2006 Calculation of contributions to the trust.

We determine expected return on plan assets using a Benefit Obligation and market-related value of plan assets that recognizes asset gains Discount rate 6.25% 6.00% 6.25% 6.00% Periodic Cost and losses ratably over a five-year period.

Expected return on plan assets 8.75 8.75 N/A N/A Periodic Cost Rate of Benefit compensation Obligation and increase 4.0 4.0 4.0 4.0 Periodic Cost 108

Contributions and Benefit Payments We recognized expense associated with our other We contributed $125 million to our qualified pension plans in postemployment benefits of $16.7 million in 2007, March 2007, even though there was no IRS required minimum $9.6 million in 2006, and $9.2 million in 2005. BGE's contribution in 2007. We expect to contribute $76 million to portion of expense associated with other postemployment our pension plans in 2008. Our non-qualified pension plans benefits was $10.2 million in 2007, $5.6 million in 2006, and and our postretirement benefit programs are not funded. We $5.4 million in 2005.

estimate that we will incur approximately $8 million in pension We assumed the discount rate for other postemployment benefits for our non-qualified pension plans and approximately benefits to be 5.25% in 2007 and 5.50% in 2006. This

$29 million for retiree health and life insurance costs net of assumption impacts the calculation of our other Medicare Part D during 2008. postemployment benefit obligation and periodic cost.

Employee Savings Plan Benefits Other Postemployment Benefits We sponsor defined contribution savings plans that are offered We provide the following postemployment benefits:

to all eligible employees. The savings plans are qualified 401(k)

" health and life insurance benefits to eligible employees plans under the Internal Revenue Code. In a defined determined to be disabled under our Disability contribution plan, the benefits a participant is to receive result Insurance Plan, from regular contributions to a participant account. Matching

" income replacement payments for Nine Mile Point contributions to participant accounts are made under these union-represented employees determined to be plans. Matching contributions to these plans were as follows:

disabled, and

" income replacement payments for other employees Year Ended December 31, 2007 2006 2005 determined to be disabled before November 1995 (In millions)

(payments for employees determined to be disabled Nonregulated businesses $16.1 $14.6 $13.5 after that date are paid by an insurance company, and BGE 5.8 5.4 5.1 the cost is paid by employees).

Total Constellation Energy $21.9 $20.0 $18.6 8 Credit Facilities and Short-Term Borrowings Our short-term borrowings may include bank loans, commercial In addition, Constellation Energy had $14.0 million of paper, and bank lines of credit. Short-term borrowings mature short-term borrowings outstanding at December 31, 2007 under within one year from the date of issuance. We pay commitment a three year $50 million line of credit expiring in 2010 relating fees to banks for providing us lines of credit. When we borrow to our merchant energy business. The weighted-average effective under the lines of credit, we pay market interest rates. interest rate for this outstanding borrowing was 7.44% at December 31, 2007. There were no short-term borrowings Constellation Energy outstanding under this line of credit at December 31, 2006.

Constellation Energy had a committed bank line of credit under In January 2008, we entered into a new six month line of a five-year credit facility, expiring in July 2012, of $3.85 billion credit totaling $500.0 million. This line of credit expires in July and a one year $250.0 million credit facility at December 31, 2008 and has an option to be extended for an additional six 2007 for short-term financial needs. months, subject to the lender's approval.

We enter into these facilities to ensure adequate liquidity to support our operations. Currently, we use the facilities to issue BGE letters of credit primarily for our merchant energy business. BGE had no commercial paper outstanding at December 31, Additionally, we can borrow directly from the banks or use the 2007 or 2006.

facilities to allow the issuance of commercial paper. BGE has a $400.0 million five-year revolving credit facility These facilities can issue letters of credit up to expiring in 2011. As of December 31, 2007, BGE had approximately $4.1 billion. Letters of credit issued under this $0.7 million of letters of credit issued under this facility. BGE facility totaled $1.8 billion at December 31, 2007. At can borrow directly from the banks or use the agreements to December 31, 2006, letters of credit issued under previous credit allow the issuance of commercial paper.

facilities that were replaced with the five-year facility in 2007 totaled $1.6 billion. The increase in letters of credit issued is primarily due to changes in collateral requirements with counterparties as a result of commodity price changes.

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9 Long-Term Debt, Common Stock and Preference Stock Long-term Debt BGE's Rate Stabilization Bonds Long-term debt matures in one year or more from the date of In June 2007, BondCo, a subsidiary of BGE, issued an issuance. We detail our long-term debt in our Consolidated aggregate principal amount of $623.2 million of rate Statements of Capitalization. As you read this section, it may stabilization bonds to recover deferred power purchase costs.

be helpful to refer to those statements. We discuss BondCo in more detail in Note 4. Below are the details of the rate stabilization bonds:

Constellation Energy In December 2007, we issued $65.0 million of tax-exempt Scheduled variable rate notes to finance the acquisition, construction, Principal Interest Rate Maturity Date installation and equipping of certain sewage and solid waste $284.0 5.47% October 2012 disposal facilities at one of our coal-fired power plants in 220.0 5.72 April 2016 Maryland. 119.2 5.82 April 2017 On October 31, 2006, CEP entered into a $200.0 million

.The bonds are secured primarily by a usage-based, secured revolving credit facility, and at December 31, 2006, non-bypassable charge payable by all of BGE's residential CEP had $22.0 million of borrowings outstanding under this electric customers over the next ten years. The charges will be facility. However, during 2007, CEP issued additional equity to the public and our ownership percentage fell below 50 percent. adjusted semi-annually to ensure that the aggregate charges Therefore, we deconsolidated CEP and began accounting for collected are sufficient to pay principal and interest on the our investment using the equity method of accounting. As a bonds, as well as certain on-going costs of administering and result, the borrowings outstanding under the CEP credit facility .servicing the bonds. BondCo cannot use the charges collected at the time of deconsolidation are no longer included in our to satisfy any other obligations. BondCo's assets are not assets Consolidated Balance Sheets. of any affiliate and are not available to pay creditors of any affiliate of BondCo. If BondCo is unable to make principal and interest payments on the bonds, neither Constellation BGE Energy, nor BGE, are required to make the payments on behalf BGEs First Refunding Mortgage Bonds of BondCo.

BGE's first refunding mortgage bonds are secured by a mortgage lien on all of its assets. The generating assets BGE BGE's Other Long-Term Debt transferred to subsidiaries of Constellation Energy also remain subject to the lien of BGE's mortgage, along with the stock of On July 1, 2000, BGE transferred $278.0 million of Safe Harbor Water Power Corporation and Constellation tax-exempt debt to our merchant energy business related to the Enterprises, Inc. We expect the assets to be released from this transferred generating assets. At December 31, 2007, BGE lien following payment in March 2008 of the last series of remains contingently liable for the $147.8 million outstanding bonds outstanding under the mortgage and the subsequent balance of this debt.

We show the weighted-average interest rates and maturity discharge of the mortgage.

BGE is required to make an annual sinking fund payment dates for BGE's fixed-rate medium-term notes outstanding at each August 1 to the mortgage trustee. The amount of the December 31, 2007 in the following table.

payment is equal to 1% of the highest principal amount of Weighted-Average Maturity bonds outstanding during the preceding 12 months. The Interest Rate Series Dates trustee uses these funds to retire bonds from any series through repurchases or calls for early redemption. However, the trustee E 6.66% 2008-2012 cannot call the 6518% Series, due 2008 outstanding bonds for G 6.08% 2008 early redemption.

BGE Deferrable Interest Subordinated Debentures On November 21, 2003, BGE Capital Trust II (BGE Trust II),

a Delaware statutory trust established by BGE, issued 10,000,000 Trust Preferred Securities for $250 million ($25 liquidation amount per preferred security) with a distribution rate of 6.20%.

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BGE Trust II used the net proceeds from the issuance of Failure by Constellation Energy, or BGE, to comply with common securities to BGE and the Trust Preferred Securities these covenants could result in the acceleration of the maturity to purchase a series of 6.20% Deferrable Interest Subordinated of the debt outstanding under these facilities. The credit Debentures due October 15, 2043 (6.20% debentures) from facilities of Constellation Energy contain usual and customary BGE in the aggregate principal amount of $257.7 million with cross-default provisions that apply to defaults on debt by the same terms as the Trust Preferred Securities. BGE Trust II Constellation Energy and certain subsidiaries over a specified must redeem the Trust Preferred Securities at $25 per preferred threshold.

security plus accrued but unpaid distributions when the 6.20% The BGE credit facility also contains usual and customary debentures are paid at maturity or upon any earlier cross-default provisions that apply to defaults on debt by BGE redemption. BGE has the option to redeem the 6.20% over a specified threshold. The indenture pursuant to which debentures at any time on or after November 21, 2008 or at BGE has issued and outstanding mortgage bonds provides that any time when certain tax or other events occur. a default under any debt instrument issued under the indenture BGE Trust II will use the interest paid on the 6.20% may cause a default of all debt outstanding under such debentures to make distributions on the Trust Preferred indenture.

Securities. The 6.20% debentures are the only assets of BGE Constellation Energy also provides credit support to Trust II. Calvert Cliffs, Ginna, and Nine Mile Point to ensure these BGE fully and unconditionally guarantees the Trust plants have funds to meet expenses and obligations to safely Preferred Securities based on its various obligations relating to operate and maintain the plants.

the trust agreement, indentures, 6.20% debentures, and the preferred security guarantee agreement. Maturities of Long-Term Debt For the payment of dividends and in the event of Our long-term borrowings mature on the following schedule:

liquidation of BGE, the 6.20% debentures are ranked prior to Constellation Nonregulated preference stock and common stock. Year Energy Businesses BGE Total (In millions)

Revolving Credit Agreement 2008 $ - $ 5.6 $ 350.0 $ 355.6 On December 18, 2001, BGE's subsidiary, District Chilled 2009 500.0 1.5 65.0 566.5 Water Partnership (ComfortLink) entered into a $25.0 million 2010 - 0.4 56.5 56.9 2011 - 36.0 81.7 117.7 loan agreement with the Maryland 'Energy Financing 2012 705.2 1.6 172.5 879.3 Administration (MEFA). The terms of the loan exactly match Thereafter 1,256.6 323.9 1,489.4 3,069.9 the terms of variable rate, tax exempt bonds due December 1, Total long-term debt at December 31, 2007 $2,461.8 $369.0 $2,215.1 $5,045.9 2031 issued by MEFA for ComfortLink to finance the cost of building a chilled water distribution system. The interest rate At December 31, 2007, we had long-term loans totaling on this debt resets weekly. These bonds, and the corresponding $339.8 million that mature after 2007, which are periodically loan, can be redeemed at any time at par plus accrued interest remarketed and could require repayment prior to maturity while under variable rates. The bonds can also be converted to following any unsuccessful remarketing. As a result of these a fixed rate at ComfortLink's option.

provisions, at December 31, 2007, $25.0 million is classified as current portion of long-term debt at BGE.

Debt Compliance and Covenants The credit facilities of Constellation Energy and BGE discussed Weighted-Average Interest Rates for Variable Rate Debt in Note 8 have limited material adverse change clauses, none of Our weighted-average interest rates for variable rate debt were:

which would prohibit draws under the existing facilities. The long-term debt indentures of Constellation Energy and BGE At December 31, 2007 2006 do not contain material adverse change clauses or financial NonregulatedBusinesses covenants. (including ConstellationEnergy)

Certain credit facilities of Constellation Energy contain a Loans under credit agreements 3.77% 3.69%

provision requiring Constellation Energy to maintain a ratio of Tax-exempt debt 3.53% 3.63%

debt to capitalization equal to or less than 65%. At Fixed-rate debt converted to floating* 6.43% 6.26%

• As discussed in Note 13, we have entered into interest rate swaps December 31, 2007, the debt to capitalization ratio as defined relating to $450.0 million of our fixed-rate debt.

in the credit agreements was 46%.

The credit agreement of BGE contains a provision requiring BGE to maintain a ratio of debt to capitalization equal to or less than 65%. At December 31, 2007, the debt to capitalization ratio for BGE as defined in this credit agreement was 47%. At December 31, 2007, no amounts were outstanding under these agreements.

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Common Stock Preference Stock Share Repurchase Program Each series of BCE preference stock has no voting power, In October 2007, our board of directors approved a common except for the following:

share repurchase program for up to $1 billion of our " the preference stock has one vote per share on any outstanding common shares. Subsequent to this approval, on charter amendment which would create or authorize October 31, 2007, we entered into an accelerated share any shares of stocký ranking prior to or on a parity repurchase agreement with a financial institution to repurchase with the preference stock as to either dividends or a total of $250.0 million, and, on November 2, 2007, we distribution of assets, or which would substantially purchased 2,023,527 of outstanding shares of our common adversely affect the contract rights, as expressly set stock, which represents the minimum number of shares forth in BCE's charter, of the preference stock, each of deliverable under the agreement, for a total of $187.5 million. which requires the affirmative vo'te of two-thirds of all We account for the accelerated share repurchase agreement the shares of preference stock outstanding; and as two separate transactions: as shares of common stock " whenever BGE fails to pay full dividends on the acquired at cost and a forward contract indexed to our own preference stock and such failure continues for one common stock. We accounted for the shares of common stock year, the preference stock shall have one vote per share repurchased in November as a reduction to common on all matters, until and unless such dividends shall shareholders' equity at cost. We accounted for the forward have been paid in full. Upon liquidation, the holders contract as a component of common shareholders' equity at of the preference stock of each series outstanding are fair value, which totaled $62.5 million at inception. The entitled to receive the par amount of their shares and forward contract was settled on January 23, 2008 based on a an amount equal to the unpaid accrued dividends.

discount to the volume-weighted average trading price of our common stock during that period. As a result, the financial institution delivered 514,376 additional shares to us to complete the transaction.

The remainder of the common share repurchase program is expected to be executed over the next 24 months in a manner that preserves flexibility to pursue additional strategic investment opportunities.

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1 0 Taxes The components of income tax expense are as follows:

Year Ended December 31, 2007 2006 2005 (Dollar amounts in millions)

Income Taxes Current Federal $168.2 $246.3 $ 14.3 State 40.6 37.2 32.7 Current taxes charged to expense 208.8 283.5 47.0 Deferred Federal 184.7 50.7 107.9 State 41.5 23.7 16.1 Deferred taxes charged to expense 226.2 74.4 124.0 Investment tax credit adjustments (6.7) (6.9) (7.1)

Income taxes per Consolidated Statements of Income $428.3 $351.0 $163.9 Total income taxes are different from the amount that would be computed by applying the statutory Federal income tax rate of 35% to book income before income taxes as follows:

Reconciliation of Income Taxes Computed at Statutory Federal Rate to Total Income Taxes Income from continuing operations before income taxes (excluding BCE preference stock divi-dends) $1,263.9 $1,112.8 $ 713.0 Statutory federal income tax rate 35% 35% 35%

Income taxes computed at statutory federal rate 442.4 389.5 249.5 Increases (decreases) in income taxes due to Depreciation differences not normalized on regulated activities 3.7 3.6 3.8 Amortization of deferred investment tax credits (6.7) (6.9) (7.1)

Synthetic fuel tax credits flowed through to income (166.2) (120.2) (114.9)

Estimated synthetic fuel tax credit phase-out 110.3 44.3 -

State income taxes, net of federal income tax benefit 53.4 42.6 31.5 Merger-related transaction costs - (5.3) 5.3 Other (8.6) 3.4 (4.2)

Total income taxes $ 428.3 $ 351.0 $ 163.9 Effective income tax rate 33.9% 31.5% 23-0%

In 2007, the State of Maryland increased its corporate tax rate from 7% to 8.25% effective January 1, 2008. In accordance with SEAS No. 109, Accounting for Income Taxes, the impact from adjusting all existing deferred income tax assets and liabilities for the effect of changes in tax laws or rates should be included in operating results in the period that includes the enactment date. In 2007, we recognized a $0.7 million after-tax charge for the net impact of the changes in the Maryland tax rate on deferred income tax assets and liabilities, net of the related federal deferred income tax benefit. The impact to BGE is discussed below.

Current income taxes will begin to be recorded at the higher Maryland corporate income tax rate effective in 2008 and will be reflected in our ongoing operating results beginning on January 1, 2008.

BGE's effective tax rate was 40.7% in 2007, 37.5% in 2006, and 38.8% in 2005. The difference between BCE's effective tax rate and the 35% statutory federal income tax rate is primarily related to Maryland corporate income taxes, net of the related federal income tax benefit. BCE's after-tax effective state rate of 7.6% for 2007 includes an adjustment of deferred income tax liabilities to reflect the November 19, 2007 enactment into law of a change in the Maryland corporate income tax rate, as discussed above. In 2006, BCE's effective tax rate includes the benefit of merger-related costs incurred in 2005 that were deductible in 2006 as a result of the termination of the merger with FPL Group (0.5%) and a deduction for dividends paid to the employee savings plan (0.5%).

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The major components of our net deferred income tax liability are as follows:

Constellation Energy BCE At December 31, 2007 2006 2007 2006 (In millions)

Deferred Income Taxes Deferred tax liabilities Net property, plant and equipment $1,570.7 $1,539.1 $ 583.8 $ 524.2 Qualified nuclear decommissioning trust funds 360.3 339.5 -

Regulatory assets, net 312.0 203.3 312.0 203.3 Mark-to-market energy assets and liabilities, net 217.8 154.7 -

Other 122.6 185.1 12.2 72.7 Total deferred tax liabilities 2,583.4 2,421.7 908.0 800.2-Deferred tax assets Asset retirement obligation 368.3 384.6 -

Defined benefit obligations 362.0 390.6 61.6 39.8 Financial investments and hedging instruments 426.1 757.2 -

Deferred investment tax credits 20.4 22.1 4.8 4.7 Other 118.8 105.7 11.9 10.6 Total deferred tax assets 1,295.6 1,660.2 78.3 55.1 Total deferred tax liability, net 1,287.8 761.5 829.7 745.1 Less: Current portion of deferred tax (asset) /liability (300.7) (674.3) 44.1 47.4 Long-term portion of deferred tax liability, net $1,588.5 $1,435.8 $ 785.6 $ 697.7 Synthetic Fuel Tax Credits The IRC provides for a phase-out of synthetic fuel tax Our merchant energy business has investments in facilities that credits if average annual wellhead oil prices increase above manufacture solid synthetic fuel produced from coal as defined certain levels. To determine the amount of the phase-out, we under the Internal Revenue Code (IRC) for which we can are required to compare average annual wellhead oil prices per claim tax credits on our Federal income tax return through barrel as published by the IRS (reference price) to a Gross 2007. We recognize the tax benefit of these credits in our National Product inflation adjusted oil price for the year, also Consolidated Statements of Income when we believe it is published by the IRS. The reference price is determined based highly probable that the credits will be sustained. The synthetic on wellhead prices for all domestic oil production as published fuel process involves combining coal material with a chemical by the Energy Information Administration (EIA). For 2007, we reagent to create a significant chemical change. A taxpayer may estimate the tax credit reduction would begin if the reference request a private letter ruling from the IRS to support its price exceeds approximately $56 per barrel and would be fully position that the synthetic fuel produced undergoes a phased out if the reference price exceeds approximately $71 per significant chemical change and thus qualifies for synthetic fuel barrel.

tax credits. Based on monthly EIA published wellhead oil prices for We own a minority ownership in four synthetic fuel the ten months ended October 31, 2007 and November and facilities located in Virginia and West Virginia. These facilities December NYMEX prices for light, sweet, crude oil (adjusted have received private letter rulings from the IRS. In 2004, the for the 2007 difference between EIA and NYMEX prices), we IRS concluded its examination of the partnership that owns estimate a 70% tax credit phase-out in 2007. We recorded the these facilities for the tax years 1998 through 2001 and the effect of this phase-out estimate as a reduction in tax credits of IRS did not disallow any of the previously recognized synthetic $110.3 million during 2007.

fuel credits. While we believe the production and sale of synthetic fuel We also have a 99% ownership in a South Carolina from all of our synthetic fuel facilities meet the conditions to facility that produces synthetic fuel. We have received favorable qualify for tax credits under the IRC, we cannot predict the private letter rulings from the IRS on the South Carolina timing or outcome of any future challenge by the IRS, facility. In 2006, the IRS concluded its examination of the legislative or regulatory action, or the ultimate impact of such partnership that owns the South Carolina facility for the 2003 events on the synthetic fuel tax credits that we have claimed to and 2004 tax years and the IRS did not disallow any of the date, but the impact could be material to our financial results.

previously recognized synthetic fuel credits.

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Income Tax Audits The following table summarizes the change in We file income tax returns in the United States and foreign unrecognized tax benefits during 2007 and our total jurisdictions. With few exceptions, we are no longer subject to unrecognized tax benefits at December 31, 2007:

U.S. federal, state and local, or non-U.S. income tax Ar December 31, 2007 examinations by tax authorities for the years before 2002. In (In millions)

February 2008, the IRS completed its examination of our consolidated federal income tax returns for the tax years 2002 Total unrecognized tax benefits, January 1, through 2004. We intend to file an administrative appeal of 2007 $104.0 certain audit adjustments made by the IRS as part of its Increases in tax positions related to the examination. Although the final outcome of the 2002-2004 current year 13.3 IRS audit and future tax audits is uncertain, we believe that Increases in tax positions related to prior years 3.8 adequate provisions for income taxes have been made for Reductions in tax positions related to prior potential liabilities resulting from such matters. years (6.0)

Reductions in tax positions as a result of a Unrecognized Tax Benefits lapse of the applicable statute of limitations (0.6)

The following table summarizes our total unrecognized tax Total unrecognized tax benefits, December 31, benefits at January 1, 2007, the date of adoption of FIN 48: 2007 (1) $114.5 At January 1, 2007 (1) BM~ portion of our total unrecognized tax benefits at (In millions) December 31, 2007 was $17.8 million.

Total liabilities reflected in our balance sheet Increases in current and prior year tax positions and for unrecognized tax benefits of reductions in prior year tax positions are primarily due to

$56.7 million less $12.1 million of interest unrecognized tax benefits for repair deductions measured at and penalties $ 44.6 amounts consistent with proposed IRS adjustments for prior Other unrecognized tax benefits not reflected years. There was no significant change in tax expense as a in our balance sheet 59.4 result of 2007 activity.

Total unrecognized tax benefits $104.0 Interest and penalties recorded in our Consolidated Statements. of Income as tax expense relating to liabilities for The adoption of FIN 48 did not have a material impact on unrecognized tax benefits were $4.7 million for the year ended BME' financial results.

December 31, 2007. As a result, accrued interest and penalties Other unrecognized tax benefits relate to outstanding recognized in our Consolidated Balance Sheets increased from federal and state refund claims for which no tax benefit was $12.1 million at January 1, 2007 to $16.8 million at previously provided in our financial statements because the December 31, 2007.

claims do not meet the 'more-likely-than-nor" threshold. If the total amount of unrecognized tax benefits of Included in this amount is $52.0 million of refund claims that $114.5 million as of December 31, 2007 were ultimately have been disallowed by the applicable tax authorities for which realized, our income tax expense would decrease by we assess the probability of tax benefit recognition to be approximately $71 million. The $71 million includes the remote. We discuss the adoption of FIN 48 in more detail in $52 million of disallowed refund claims discussed above.

No te 1. In 2007, the IRS proposed certain adjustments to our 2002-2004 deductions for repairs and casualty losses. We do not anticipate the adjustments, if any, would result in a material impact on our financial results. However, we anticipate that it is reasonably possible that we will make an additional payment in the range of $20 to $25 million by December 31, 2008, which will reduce our liabilities for Linrecognized tax benefits.

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I I Leases There are two types of leases---operating and capital. Capital - At December 31, 2007, we owed future minimum leases qualify as sales or purchases of property and are reported payments for long-term, noncancelable, operating leases as in our Consolidated Balance Sheets. Our capital leases are not follows:

material in amount. All other leases are operating leases and are reported in our Consolidated Statements of Income. We expense Power all lease payments associated with our regulated business. Lease Purchase Year Agreements Other Total expense and future minimum payments for long-term, (In millions) noncancelable, operating leases are not material to BGE's financial results. We present information about our operating 2008 $ 479.3 $ 26.3 $ 505.6 2009 235.8 24.6 260.4 leases below.

2010 171.1 23.1 194.2 2011 210.4 22.1 232.5 Outgoing Lease Payments 2012 219.0 19.2 238.2 We, as lessee, lease certain facilities and equipment. The lease Thereafter 782.8 109.7 892.5 agreements expire on various dates and have various renewal Total future minimum lease options. We also enter into certain power purchase agreements payments $2,098.4 $225.0 $2,323.4 which are accounted for as operating leases. Under these agreements, we are required to make Fixed capacity payments, as well as variable payments based on actual output of the plants. Sub-Lease Arrangements We record these payments as "Fuel and purchased energy We provide time charters of dry bulk freight vessels as part of expenses" in our Consolidated Statements of Income. We the logistical services provided to our global customers that exclude from our future minimum lease payments table the qualify as sub-leases of our time charter purchase contracts. In variable payments related to the output of the plant due to the 2007, we recorded sub-lease income of approximately contingency associated with these payments. $214 million related to our time charter sub-leases. We did not We also enter into time charter purchase agreements which have any material sub-lease income for 2006 or 2005. We record entitle us to the use of dry bulk freight vessels in the sub-lease income as part of "Nonregulared revenues" in our management of our global coal and logistics services. Certain of Consolidated Statements of Income. As of December 31, 2007, these contracts must be accounted for as leases. During 2007, the future minimum rentals to be received for these time we entered into time charter leases with terms ranging in charters is shown below:

duration from 1 to 60 months. These arrangements do not include provisions for material rent increases and do not have Time Charter provisions for rent holidays, contingent rentals or other Year Sub-Leases incentives. In 2007, we recognized aggregate lease expense of (In millions) approximately $535 million related to 65 dry bulk freight vessels 2008 $109.2 hired under time charter arrangements. The average term of 2009 30.7 these arrangements is approximately 4 months. We record the 2010 payments as "Fuel and purchased energy expenses" in our 2011 Consolidated Statements of Income. 2012 We recognized expense related to our operating leases as I nerearter follows:

Total future minimum lease rentals $139.9 Fuel and purchased energy Operating expenses expenses Total (In millions) 2007 $758.7 $28.2 $786.9 2006 162.6 24.7 187.3 2005 103.2 24.8 128.0 116

1 2Commitments, Guarantees, and Contingencies Commitments At December 31, 2007, we estimate our future obligations We have made substantial commitments in connection with our to be as follows:

merchant energy, regulated electric and gas, and other nonregulated businesses. These commitments relate to: Payments

" purchase of electric generating capacity and energy, 2009- 2011-2008 2010 2012 Thereafter Total

" procurement and delivery of fuels, (In millions)

• the capacity and transmission and transportation rights Merchant Energy:

for the physical delivery of energy to meet our Purchased capacity obligations to our customers, and and energy $ 425.2 $ 489.6 $213.8 $ 276.4 $1,405.0

" long-term service agreements, capital for construction Fuel and transportation 1,825.1 1,503.5 649.7 918.9 4,897.2 programs, and other. Long-term service Our merchant energy business enters into various long-term agreements, capital, contracts for the procurement and delivery of fuels to supply our and other 146.8 12.6 6.8 17.8 184.0 generating plant requirements. In most cases, our contracts Total merchant energy 2,397.1 2,005.7 870.3 1,213.1 6,486.2 contain provisions for price escalations, minimum purchase Corporate and Other:

levels, and other financial commitments. These contracts expire Long-term service agreements, capital.

in various years between 2008 and 2020. In addition, our and other 50.5 5.7 0.7 - 56.9 merchant energy business enters into long-term contracts for the Regulated:

capacity and transmission rights for the delivery of energy to Purchase obligations meet our physical obligations to our customers. These contracts and other 61.8 23.5 12.8 1.5 99.6 expire in various years between 2008 and 2019. Total futtire obligations $2,509.4 $2,034.9 $883.8 $1,214.6 $6,642.7 Our merchant energy business also has committed to long-term service agreements and other purchase commitments for our plants. Long-Term Power Sales Contracts Our regulated electric business enters into various contracts We enter into long-term power sales contracts in connection with differing terms for the procurement of electricity. These with our load-serving activities. We also enter into long-term contracts, representing approximately 66% of our estimated power sales contracts associated with certain of our power plants.

requirements, expire between 2008 and 2010. As discussed in Our load-serving power sales contracts extend for terms through Note 1, the cost of power under these contracts is fully 2019 and provide for the sale of energy to electricity distribution recoverable, and therefore is excluded from the table later in this utilities and certain retail customers. Our power sales contracts Note. associated with our power plants extend for terms into 2014 and Our regulated gas business enters into various long-term provide for the sale of all or a portion of the actual output of contracts for the procurement, transportation, and storage of gas. certain of our power plants. All long-term contracts were Our regulated gas business has gas transportation and storage executed at pricing that approximated market rates, including contracts that expire between 2008 and 2028. These contracts profit margin, at the time of execution.

are recoverable under BGE's gas cost adjustment clause discussed in Note 1, and therefore are excluded from the table later in this Guarantees Note. Our guarantees do not represent incremental Constellation Our other nonregulated businesses have committed to gas Energy Group obligations; rather they primarily represent purchases and to contributions of additional capital for parental guarantees of subsidiary obligations. The following table construction programs and joint ventures in which they have an summarizes the maximum exposure based on the stated limit of interest. our outstanding guarantees at December 31, 2007:

We have also committed to long-term service agreements At December 31, 2007 Stated Limit and other obligations related to our information technology systems. (In millions)

Competitive supply guarantees $13,538.0 Nuclear guarantees 807.8 BCE guarantees 263.3 Other non-regulated guarantees 105.3 Power project guarantees 47.2 Total guarantees $14,761.6 117

At December 31, 2007, Constellation Energy had a total of the date of FERC's original order (April 2006). Based on this

$14,761.6 million in guarantees in outstanding related to loans, FERC order, we recorded an immaterial liability during 2007 in credit facilities, and contractual performance of certain of its our Consolidated Balance Sheets for our share of the RSG subsidiaries as described below. charges. This liability was subsequently settled with MISO later

• Constellation Energy guaranteed $13,538.0 million on in 2007.

behalf of our subsidiaries for competitive supply activities. These guarantees are put into place in order Environmental Matters to allow our subsidiaries the flexibility needed to Solid and Hazardous Waste conduct business with counterparties without having to The Environmental Protection Agency (EPA) and several state post other forms of collateral. While the face amount of agencies have notified us that we are considered a potentially these guarantees is $13,538.0 million, our calculated fair responsible party with respect to the clean-up of certain value of obligations for commercial transactions covered environmentally contaminated sites. We cannot estimate the final by these guarantees was $3,460.6 million at clean-up costs for all of these sites, but the current estimated December 31, 2007. If the parent company was costs for, and current status of, each site is described in more required to fund these subsidiary obligations, the total detail below.

amount based on December 31, 2007 market prices would be $3,460.6 million. For those guarantees related 68th Street Dump to our derivative liabilities, the fair value of the In 1999, the EPA proposed to add the 68th Street Dump in obligation is recorded in our Consolidated Balance Baltimore, Maryland to the Superfund National Priorities List, Sheets. which is its list of sites targeted for clean-up and enforcement,

• Constellation Energy guaranteed $807.8 million and sent a general notice letter to BGE and 19 other parties primarily on behalf of our nuclear generating facilities identifying them as potentially liable parties at the site. In mostly due to nuclear insurance and for credit support March 2004, we and other potentially responsible parties formed to ensure these plants have funds to meet expenses and the 68th Street Coalition and entered into consent order obligations to safely operate and maintain the plants. negotiations with the EPA to investigate clean-up options for the

" BGE guaranteed the Trust Preferred Securities of site under the Superfund Alternative Sites Program. In May

$250.0 million of BGE Trust 1I, an unconsolidated 2006, a settlement among the EPA and 19 of the potentially investment, as discussed in Note 9. responsible parties, including BGE, with respect to investigation

" BGE guaranteed two-thirds of certain debt of Safe of the site became effective. The settlement requires the Harbor Water Power Corporation, an unconsolidated potentially responsible parties, over the course of several years, to investment. At December 31, 2007, Safe Harbor Water identify contamination at the site and recommend clean-up Power Corporation had outstanding debt of options. BGE is fully indemnified by a wholly-owned subsidiary

$20.0 million. The maximum amount of BGE's of Constellation Energy for costs related to this settlement, as guarantee is $13.3 million. well as any clean-up costs. The clean-up costs will not be known

" Constellation Energy guaranteed $95.1 million on until the investigation is closer to completion. However, those behalf of our other nonregulated businesses primarily for costs could have a material effect on our financial results.

loans and performance bonds of which $25.0 million was recorded in our Consolidated Balance Sheets at Kane and Lombard December 31, 2007. The EPA issued its record of decision for the Kane and

" Our other nonregulated business guaranteed Lombard Drum site located in Baltimore, Maryland on

$10.2 million primarily for performance bonds. September 30, 2003, which specified the clean-up plan for the

" Our merchant energy business guaranteed $47.2 million site, consisting of enhanced reductive dechlorination, a soil for loans and other performance guarantees related to management plan, and institutional controls. An EPA order certain power projects in which we have an investment. requiring cleanup of the site by 18 parties, including We believe it is unlikely that we would be required to Constellation Energy, became effective in November 2006. The perform or incur any losses associated with guarantees of our EPA estimates that total clean-up costs will be approximately subsidiaries' obligations. $7 million. Our share of site-related costs will be 11.1% of the total. We recorded a liability in our Consolidated Balance Sheets Contingencies for our share of the clean-up costs that we believe is probable.

Revenue Sufficiency Guarantee Costs During 2006, the FERC issued orders finding that the Midwest Spring Gardens Independent System Operator (MISO) violated its tariff by In December 1996, BGE signed a consent order with the incorrectly allocating revenue sufficiency guarantee (RSC) Maryland Department of the Environment that requires it to charges among market participants. In March 2007, after implement remedial action plans for contamination at and rejecting a methodology proposal from MISO, FERC ordered around the Spring Gardens site, located in Baltimore, Maryland.

MISO to reallocate RSG costs based on its existing tariff back to The Spring Gardens site was once used to manufacture gas from 118

coal and oil. Based on remedial action plans and cost modeling remediate contamination, replace drinking water supplies, and performed in late 2006, BCE estimates its probable clean-up monitor groundwater conditions. We estimate that it is costs will total $43 million. BCE has recorded these costs as a reasonably possible that we could incur additional costs of up to liability in its Consolidated Balance Sheets and has deferred approximately $10 million more than the liability that we these costs, net of accumulated amortization and amounts it accrued.

recovered from insurance companies, as a regulatory asset. Based In November 2007, a class action complaint was filed in on the results of studies at this site, it is reasonably possible that Baltimore City Circuit Court alleging that the subsidiary's ash additional costs could exceed the a-mount BCE has recognized placement operations at the third party site damaged by approximately $3 million. Through December 31, 2007, surrounding properties. The complaint seeks injunctive and BCE has spent approximately $41 million for remediation at remedial relief relating to the alleged contamination and this site. unspecified damages. We cannot predict the timing, or outcome, BCE also has investigated other small sites where gas was of this proceeding.

manufactured in the past. We do not expect the clean-up costs of the remaining smaller sites to have a material effect on our Litigation Financial results. In the normal course of business, we are involved in various legal proceedings. We discuss the significant matters below.

Air Quality In late July 2005, we received two Notices of Violation (NOVs) Challenges to the Illinois Auction from the Placer County Air Pollution Control District, Placer In March 2007, the Illinois Attorney Ceneral filed a complaint County California (District) alleging that the Rio Bravo Rocklin at FERC against the wholesale suppliers, including our wholesale facility located in Lincoln, California had violated certain marketing, risk management and trading operation, that were District air emission regulations. We have a combined 50% successful bidders in the recent Illinois auction. The complaint ownership interest in the partnership which owns the Rio Bravo alleged that the rates resulting from the auction were not "just Rocklin facility. The NOVs allege a total of 38 violations and reasonable" and requested that FERC commence a between January 2003 and March 2005 of either the facility's air proceeding to determine if the rates were just and reasonable permit or federal, state, and county air emission standards and to investigate evidence of price manipulation. In July 2007, related to nitrogen oxide, carbon monoxide, and particulate the Illinois legislature approved comprehensive legislation to emissions, as well as violations of certain monitoring and address several energy issues in the state. This legislation has reporting requirements during that time period. The maximum been signed into law by the Covernor of Illinois, and the civil penalties for the alleged violations range from $10,000 to Attorney General's claims have been dismissed.

$40,000 per violation. Management of the Rio Bravo Rocklin In addition, two class action complaints were filed in facility is currently discussing the allegations in the NOVs with Illinois state court against these wholesale suppliers alleging that District representatives. It is not possible to determine the actual they engaged in deceptive practices, including colluding in liability, if any, of the partnership that owns the Rio Bravo setting prices and actual price fixing. The complaints requested Rocklin facility. unspecified damages in an amount to be proven at trial. These In May 2007, a subsidiary of Constellation Energy entered complaints were moved to federal court and on December 21, into a consent decree with the Maryland Department of the 2007 the federal court dismissed the actions without prejudice Environment to resolve alleged violations of air quality opacity to the right of the plaintiffs to pursue claims at the FERC or at standards at three fossil fuel plants in Maryland. The consent the Illinois Commerce Commission.

decree requires the subsidiary to pay a $100,000 penalty, provide We believe we have meritorious defenses to any claims

$100,000 to a supplemental environmental project, and install challenging our conduct in the auction and intend to defend technology to control emissions from those plants. against any such claims vigorously. However, we cannot predict the timing, or outcome, of any such claims, or their possible Water Quality effect on our financial results.

In October 2007, a subsidiary of Constellation Energy entered into a consent decree with the Maryland Department of the Mercury Environment relating to groundwater contamination at a third Since September 2002, BCE, Constellation Energy, and several party facility that was licensed to accept fly ash, a byproduct other defendants have been involved in numerous actions filed generated by our coal-fired plants. The consent decree requires in the Circuit Court for Baltimore City, Maryland alleging the payment of a $1.0 million penalty, remediation of 'mercury poisoning from several sources, including coal plants groundwater contamination resulting from the ash placement 'formerly owned by BCE. The plants are now owned by a operations at the site, replacement of drinking water supplies in subsidiary of Constellation Energy. In addition to BCE and the vicinity of the site, and monitoring of groundwater Constellation Energy, approximately 11 other defendants, conditions. We recorded a liability in our Consolidated Balance consisting of pharmaceutical companies, manufacturers of Sheets of approximately $5 million, which includes the vaccines, and manufacturers of Thimerosal have been sued.

$1 million penalty and our estimate of probable costs to Approximately 70 cases, involving claims related to 119

approximately 132 children, have been filed to date, with each than January 31, 1998. The DOE has stated that it will not claimant seeking $20 million in compensatory damages, plus meet that obligation until 2017 at the earliest.

punitive damages, from us. This delay has required that we undertake additional In rulings applicable to all but three of the cases, involving actions related to on-site fuel storage at Calvert Cliffs and Nine claims related to approximately 47 children, the Circuit Court Mile Point, including the installation of on-site dry fuel storage for Baltimore City dismissed with prejudice all claims against capacity at Calvert Cliffs. In January 2004, we filed a complaint BCE and Constellation Energy. Plaintiffs may attempt to pursue against the federal government in the United States Court of appeals of the rulings in favor of BGE and Constellation Energy Federal Claims seeking to recover damages caused by the DOE's once the cases are finally concluded as to all defendants. We failure to meet its contractual obligation to begin disposing of believe that we have meritorious defenses and intend to defend spent nuclear fuel by January 31, 1998. The case is currently the remaining actions vigorously. However, we cannot predict stayed, pending litigation in other related cases.

the timing, or outcome, of these cases, or their possible effect on In connection with our purchase of Cinna, all of Rochester our, or BCE's, financial results. Cas & Electric Corporation's (RC&E) rights and obligations related to recovery of damages for DOE's failure to meet its Asbestos contractual obligations were assigned to us. However, we have an Since 1993, BCE and certain Constellation Energy subsidiaries obligation to reimburse RC&E for up to $10 million in have been involved in several actions concerning asbestos. The recovered damages for such claims.

actions are based upon the theory of "premises liability," alleging that BCE and Constellation Energy knew of and exposed Nuclear Insurance individuals to an asbestos hazard. In addition to BCE and We maintain nuclear insurance coverage for Calvert Cliffs, Nine Constellation Energy, numerous other parties are defendants in Mile Point, and Cinna in four program areas: liability, worker these cases. radiation, property, and accidental outage. These policies contain Approximately 538 individuals who were never employees certain industry standard exclusions, including, but not limited of BCE or Constellation Energy have pending claims each to, ordinary wear and tear, and war.

seeking several million dollars in compensatory and punitive In November 2002, the President signed into law the damages. Cross-claims and third-party claims brought by other Terrorism Risk Insurance Act ("TRIA') of 2002, which was defendants may also be filed against BCE and Constellation extended by the Terrorism Risk Insurance Extension Act of 2005 Energy in these actions. To date, most asbestos claims against us and the Terrorism Risk Insurance Program Reauthorization Act have been dismissed or resolved without any payment and a of 2007. Under the TRIA, property and casualty insurance small minority have been resolved for amounts that were not companies are required to offer insurance for losses resulting material to our financial results. The remaining claims are from Certified acts of terrorism. Certified acts of terrorism are currently pending in state Courts in Maryland and Pennsylvania. determined by the Secretary of the Treasury, in concurrence with BCE and Constellation Energy do not know the specific the Secretary of State and Attorney Ceneral, and primarily are facts necessary to estimate its potential liability for these claims. based upon the occurrence of significant acts of terrorism that The specific facts we do not know include: intimidate the civilian population of the United States or

" the identity of the facili 'ties at which the plaintiffs attempt to influence policy or affect the conduct of the United allegedly worked as contractors, States Covernment. Our nuclear liability, nuclear property and

" the names of the plaintiffs' employers, accidental outage insurance programs, as discussed later in this

• the dates on which and the places where the exposure section, provide coverage for Certified acts of terrorism.

allegedly occurred, and If there were an accident or an extended outage at any unit

" the facts and circumstances relating to the alleged of Calvert Cliffs, Nine Mile Point or Cinna, it could have a exposure. substantial adverse impact on our financial results.

Until the relevant facts are determined, we are unable to estimate what our, or BCE's, liability might be. Although Nuclear Liability Insurance insurance and hold harmless agreements from contractors who Pursuant to the Price-Anderson Act, we are required to insure employed the plaintiffs may cover a portion of any awards in the against public liability claims resulting from nuclear incidents to actions, the potential effect on our, or BCE's, Financial results the full limit of public liability. This limit of liability consists of could be material. the maximum available commercial insurance of $300 million and mandatory participation in an industry-wide retrospective Storage of Spent Nuclear Fuel premium assessment program. The retrospective premium The Nuclear Waste Policy Act of 1982 (N'"VA) required the assessment is $100.6 million per reactor, increasing the total federal government through the Department of Energy (DOE), amount of insurance for public liability to approximately to develop a repository for, and disposal of, spent nuclear fuel $10.8 billion. Under the retrospective assessment program, we and high-level radioactive waste. The NWPA and our contracts can be assessed up to $503 million per incident at any with the DOE required the DOE to begin taking possession of commercial reactor in the country, payable at no more than spent nuclear fuiel generated by nuclear generating units no later $75 million per incident per year. This assessment also applies in 120

excess of our worker radiation claims insurance and is subject to addition, we maintain $1.77 billion of excess coverage at Ginna inflation and state premium taxes. In addition, the U.S. and $2.25 billion in excess coverage under a blanket excess Congress could impose additional revenue-raising measures to program offered by the industry mutual insurer at both Calvert pay claims. Cliffs and Nine Mile Point. Under the blanket excess policy, Calvert Cliffs and Nine Mile Point share $1.0 billion of the Worker Radiation Claims Insurance total $2.25 billion of excess property coverage. Therefore, in the We participate in the American Nuclear Insurers Master Worker unlikely event of two full limit property damage losses at Calvert Program that provides coverage for worker tort claims filed for Cliffs and Nine Mile Point, we would recover $4.5 billion radiation injuries. Effective January 1, 1998, this program was instead of $5.5 billion. This coverage currently is purchased modified to provide coverage to all workers whose nuclear- through the industry mutual insurance company. If accidents at related employment began on or after the commencement date plants insured by the mutual insurance company cause a of reactor operations. Waiving the right to make additionai shortfall of funds, all policyholders could be assessed, with our claims under the old policy was a condition for coverage under share being up to $97.4 million.

the new policy. We describe the old and new policies below: Losses resulting from non-certified acts of terrorism are

" All nuclear worker claims reported on or after covered as a common occurrence, meaning that if non-certified January 1, 1998 are covered by a new insurance policy. terrorist acts occur against one or more commercial nuclear The new policy provides a single industry aggregate power plants insured by our nuclear property insurance company limit of $200 million for occurrences of radiation injury within a 12-month period, they would be treated as one event claims against all those insured by this policy prior to and the owners of the plants where the acts occurred would January 1, 2003 and $300 million for occurrences of share one full limit of liability (currently $3.24 billion).

radiation injury claims against all those insured by this policy on or after January 1, 2003. Accidental Nuclear Outage Insurance

" All nuclear worker claims reported prior to January 1, Our policies provide indemnification on a weekly basis for losses 1998 are still covered by the old policy. Insureds under resulting from an accidental outage of a nuclear unit. Coverage the old policies, with no current operations, are not begins after a 12-week deductible period and continues at 100%

required to purchase the new policy described above, of the weekly indemnity limit for 52 weeks and then 80% of and may still make claims against the old policies the weekly indemnity limit for the next 1 10 weeks. Our through 2007. If radiation injury claims under these old coverage is up to $490.0 million per unit at Calvert Cliffs and policies exceed the policy reserves, all policyholders Ginna, $420.0 million for Unit 1 of Nine Mile Point, and could be retroactively assessed, with our share being up $401.8 million for Unit 2 of Nine Mile Point. This amount can to $6.3 million. Effective December 31, 2007, the be reduced by up to $98.0 million per unit at Calvert Cliffs and discovery period under the old policy expired. All claims $84.0 million for Nine Mile Point if an outage of more than are closed and no new claims can be filed. one unit is caused by a single insured physical damage loss.

The sellers of Nine Mile Point retain the liabilities for existing and potential claims that occurred prior to November 7, Non-Nuclear Property Insurance 2001. In addition, the Long Island Power Authority, which Our conventional property insurance provides coverage of continues to own 18% of Unit 2 at Nine Mile Point, is $1.0 billion per occurrence for Certified acts of terrorism as obligated to assume its pro rata share of any liabilities for defined under TRIA, Terrorism Risk Insurance Extension Act of retrospective premiums and other premium assessments. RC&E, 2005 and the Terrorism Risk Insurance Program Reauthorization the seller of Cinna, retains the liabilities for existing and Act of 2007. Our conventional property insurance program also potential claims that occurred prior to June 10, 2004. If claims provides coverage for non-certified acts of terrorism up to an under these policies exceed the coverage limits, the provisions of annual aggregate limit of $1.0 billion. If a terrorist act occurs at the Price-Anderson Act would apply. any of our facilities, it could have a significant adverse impact on our financial results.

Nuclear Property Insurance Our policies provide $500 million in primacy coverage at each nuclear plant-Calvert Cliffs, Nine Mile Point, and Ginna. In 121

I 3Hedging Activities and Fair Value of Financial Instruments SPAS No. 133 Hedging Activities In addition, during 2007, we de-dlesignared contracts We are exposed to market risk, including changes in interest previously designated as cash-flow hedges for which the rates and the impact of market fluctuations in the price and forecasted transactions originally hedged are probable of not transportation costs of electricity, natural gas, and other occurring, and as a result we recognized a pre-tax loss of commodities. $24.4 million. The majority of the pre-tax loss associated with de-designated contracts in 2007 resulted from the Commodity Prices deconsolidlation of CEP. During 2006, we de-designated MerchantEnergy Busines contracts previously designated as cash-flow hedges for which the Our merchant energy business uses a variety of derivative and forecasted transactions originally hedged are probable of not non-derivative instruments to manage the commodity price risk occurring, and as a result we recognized a pre-tax loss of of our competitive supply activities and our electric generation $35.3 million. The majority of the pre-tax loss associated with facilities, including power sales, fuel and energy purchases, gas de-designated contracts in 2006 resulted from the initial public purchased for resale, emission credits, weather risk, freight and offering of CEP and the sale of our gas-fired plants. During the market risk of outages. In order to manage these risks, we 2005, we terminated a contract previously designated as a may enter into fixed-price derivative or non-derivative contracts cash-flow hedge. The forecasted transaction originally hedged to hedge the variability in future cash flows from forecasted sales was probable of not occurring and as a result we recognized a of energy and purchases of fuel and energy. The objectives for pre-tax loss of $6.1 million.

entering into such hedges include: Our merchant energy business also enters into natural gas

" fixing the price for a portion of anticipated future storage contracts under which the gas in storage qualifies for fair electricity sales at a level that provides an acceptable value hedge accounting treatment under SFAS No. 133. We return on our electric generation operations, record changes in fair value of these hedges related to our retail

" fixing the price of a portion of anticipated fuel competitive supply operations as a component of "Fuel and purchases for the operation of our power plants, purchased energy expenses" in our Consolidated Statements of

" fixing the price for a portion of anticipated energy Income. We record changes in fair value of these hedges related purchases to supply our load-serving customers, to our wholesale competitive supply operations as a component

" fixing the price for a portion of anticipated sales of of "Nonregulared revenues" in our Consolidated Statements of natural gas to customers, and Income.

" fixing the price for a portion of anticipated sales or We recorded in earnings the following pre-tax gains (losses) purchases of freight and coal. related to hedge ineffectiveness:

The portion of forecasted transactions hedged may vary based upon management's assessment of market, weather, Year ended December 31, 2007 2006 2005 operational, and other factors. (In millions)

Our merchant energy business designated certain fixed-price Cash-flow hedges $(31.4) $13.4 $(19.4) forward contracts as cash-flow hedges of forecasted sales of Fair value hedges 24.4 27.7 (2.2) energy and forecasted purchases of fuel and energy for the years Total $ (7.0) $41.1 $(21.6) 2007 through 2016 under SFAS No. 133. Our merchant energy business had net unrealized pre-tax losses on these cash-flow The ineffectiveness amounts in the table above exclude hedges recorded in "Accumulated other comprehensive income" $7.3 million of pre-tax losses that we recognized as a result of of $1,498.7 million at December 31, 2007 and $2,227.1 million market price changes for the year ended December 31, 2007.

at December 31, 2006. These losses represent the change in fa-ir value of derivatives that We expect to reclassify $760.4 million of net pre-tax losses no longer qualify for cash-flow hedge accounting due to reduced on cash-flow hedges from "Accumulated other comprehensive price correlation between the hedge and the risk being hedged, income" into earnings during the next twelve months based on but remain designated as hedges prospectively. In addition, we the market prices at December 31, 2007. However, the actual recognized a $3.8 million pre-tax loss in 2007 and a amount reclassified into earnings could vary from the a-mounts $8.9 million pre-tax gain in 2006 related to the change in value recorded at December 31, 2007, due to future changes in for the portion of our fair value hedges excluded from market prices. Additionally, for cash-flow hedges settled by ineffectiveness testing.

physical delivery of the underlying commodity, "Reclassification of net gains on hedging instruments from OCI to net income" Regulated Gas Business represents the fair value of those derivatives, which is realized BCE uses basis swaps in the winter months (November through March) to hedge its price risk associated with natural gas through gross settlement at the contract price.

purchases under its market-based rates incentive mechanism and 122

under its off-system gas sales program. BCE also uses During 2004, to optimize the mix of fixed and floating-rate fixed- to-floati ng and floati ng-to-Fixed swaps to hedge its price debt, we entered into interest rate swaps qualifying as fair value risk associated with irs off-system gas sales. The fixed portion hedges relating to $450 million of our fixed-rate debt maturing represents a specific dollar amount that BGE will pay or receive, in 2012 and 2015, and converted this notional amount of debt and the floating portion represents a fluctuating amount based to floating-rate. The fair value of these hedges was an unrealized on a published index that BCE will receive or pay. BGE's gain of $11.8 million at December 31, 2007 and was recorded regulated gas business internal guidelines do not permit the use as an increase in our "Derivative assets" and an increase in our of swap agreements for any purpose other than to hedge price "Long-term debt." The fair value of these hedges was an risk. The impact of these swaps on our, and BCE's, financial unrealized loss of $7.1 million at December 31, 2006 and was results is immaterial. recorded as an increase in our "Derivative liabilities" and a decrease in our "Long-term debt." We had no hedge Regulated Electric Business ineffectiveness on these interest rate swaps.

BCE uses basis swaps to hedge its price risk associated with electricity purchases. BCE's regulated electric business internal Fair Value of Financial Instruments guidelines do nor permit the use of swap agreements for any The fair value of a financial instrument represents the amount at purpose other than to hedge price risk. The impact of these which the instrument could be exchanged in a current swaps on our, and BCE's, Financial results is immaterial. transaction between willing parties, other than in a forced sale or liquidation. Significant differences can occur between the fair Interest Rates value and carrying a-mount of financial instruments that are We use interest rate swaps to manage our interest rate exposures recorded at historical amounts. We use the following methods associated with new debt issuances, to manage our exposure to and assumptions for estimating fair value disclosures for financial fluctuations in interest rates on variable rate debt, and to instruments:

optimize the mix of fixed and floating-rate debt. The swaps used " cash and cash equivalents, net accounts receivable, other to manage our exposure prior to the issuance of new debt and current assets, certain current liabilities, short-term to manage the exposure to fluctuations in interest rates on borrowings, current portion of long-term debt, and variable rate debt are designated as cash-flow hedges under SEAS certain deferred credits and other liabilities: because of No. 133, with the effective portion of gains and losses, net of their short-term nature, the amounts reported in our associated deferred income tax effects, recorded in "Accumulated Consolidated Balance Sheets approximate fair value, other comprehensive income" in our Consolidated Statements of

• investments and other assets: the fair value is based on Common Shareholders' Equity and Comprehensive Income and quoted market prices where available, and Consolidated Statements of Capitalization, in anticipation of " long-term debt: the fair value is based on quoted market planned financing transactions. We reclassify gains and losses on prices where available or by discounting remaining cash the hedges from "Accumulated other comprehensive income" flows at current market rates.

into "Interest expense" in our Consolidated Statements of We show the cartying a-mounts and fair values of financial Income during the periods in which the interest payments being instruments included in our Consolidated Balance Sheets in the hedged occur. following table:

The swaps used to optimize the mix of fixed and floating-rate debt are designated as fair value hedges under SEAS At December 31, 2007 2006 No. 133. We record any gains or losses on swaps that qualify for Carrying Fair Carrying Fair Amount Value Amnount Value fair value hedge accounting treatment, as well as changes in the (In millions) fair value of the debt being hedged, in "Interest expense," and Investments and we record any changes in fair value of the swaps and the debt in other assets-

"Derivative assets and liabilities" and "Long-term debt" in our Constellation Consolidated Balance Sheets. In addition, we record the Energy $1,634.2 $1,634.5 $1,468.8 $1,469.3 difference between interest on hedged fixed-rate debt and Fixed-rate long-term floating-rate swaps in "Interest expense" in the periods that the debt:

Constellation swaps settle. Energy 4,244.3 4,307.5 4,383.8 4,513.8 "Accumulated other comprehensive income" includes net BCE 2,215.1 2,178.6 1,716.7 1,712.6 unrealized pre-tax gains on interest rate cash-flow hedges Variable-rate terminated upon debt issuance totaling $11.9 million at long-term debt:

December 31, 2007 and $12.5 million at December 31, 2006. Constellation Energy 801.6 801.6 723.2 723.2 We expect to reclassify $0.1 million of pre-tax net gains on these BCE cash-flow hedges from "Accumulated other comprehensive income" into "Interest expense" during the next twelve months.

We had no hedge ineffectiveness on these swaps.

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14 Stock-Based Compensation Under our long-term incentive plans, we grant stock options, using the Black-Scholes option pricing model based on the performance and service-based restricted stock, performance- and following weighted- average assumptions:

service-based units, and equity to officers, key employees, and 2007 2006 2005 members of the Board of Directors. In May 2007, shareholders Risk-free interest rate 4 6

. 9% - 4.10%

approved Constellation Energy's 2007 Long-Term Incentive Plan, Expected life (in years) 4.0 - 2.9*

under which we can grant up to a total of 9,000,000 shares. Expected market price volatility factor 20.3% - 21.3%

Any shares covered by an outstanding award under any of our Expected dividend yield 2.5% - 3.0%

long-term incentive plans that are forfeited or cancelled, expire *Includes 2.0 million fully vested options granted in December 2005, which would have been cancelled upon a change in control if or are settled in cash will become available for issuance under our proposed merger with FPL Group would have been consummated the 2007 Long-Term Incentive Plan. At December 31, 2007, andfor which an expected life of one year was used to value the there were 9,244,969 shares available for issuance under the grant. Excluding this grant, we used a weighted-average expected life 2007 Long-Term Incentive Plan. At December 31, 2007, we had assumption of 5 yearsfor 2005 grants.

stock options, restricted stock, performance unit and equity During 2006, no stock options were granted to employees grants outstanding as discussed below. We may issue new shares, in anticipation of the proposed merger with FPL Group, which reuse forfeited shares, or buy shares in the market in order to was terminated in October 2006. We discuss the termination of deliver shares to employees for our equity grants. BGE officers the merger in more detail in Note 15.

and key employees participate in our stock-based compensation We use the historical data related to stock option exercises plans. The expense recognized by BGE in 2007, 2006, and in order to estimate the expected life of our stock options. We 2005 was not material to BGE's financial results. also use historical data in order to estimate the volatility factor (measured on a daily basis) for a period equal to the duration of Non-Qualified Stock Options the expected life of option awards. We believe that the use of Options are granted with an exercise price equal to the market historical data to estimate these factors provides a reasonable value of the common stock at the date of grant, become vested basis for our assumptions. The risk-free interest rate for the over a period up to three years (expense recognized in tranches),

periods within the expected life of the option is based on the and expire ten years from the date of grant. The fair value of U.S Treasury yield curve in effect and the expected dividend our stock-based awards was estimated as of the date of grant yield is based on our current estimate for dividend payout at the time of grant. We disclose the pro-forma effect on net income and earnings per share for the periods prior to adoption of SFAS No. 123R in Note 1.

Summarized information for our stock option grants is as follows:

2007 2006 2005 Weighted- Weighted- Weighted-Average Average Average Shares Exercise Price Shares Exercise Price Shares Exercise Price (Shares in thousands)

Outstanding, beginning of year 6,051 $47.23 7,172 $45.24 7,365 $31.62 Granted with exercise prices at fair market value 1,759 76.22 - - 3,840 54.94 Exercised (1,411) 41.91 (1,050) 33.77 (3,935) 29.32 Forfeited/expired (254) 67.85 (71) 45.22 (98) 42.19 Outstanding, end of year 6,145 $55.90 6,051 $47.23 7,172 $45.24 Exercisable, end of year 4,043 $48.51 4,401 $46.94 4,022 $45.31 Weighted-average fair value per share of options granted with exercise prices at fair market value $13.76 $ - $ 7.13 124

The following table summarizes additional information Summarized share information for our restricted stock awards is about stock options during 2007, 2006 and 2005: as follows:

2007 2006 2005 2007 2006 2005 (Shares in thousands)

... Outstanding, beginning of year 1,207 1,272 1,223 Stock Option Expense 710 511 485 Granted Recognized

$15.1 $ 6.7 $ 14.4 Released to participants (552) (502) (359)

Stock Options Exercised:

Cancelled (43) (74) (77)

Cash Received for Exercise Price 43.4 35.5 35.3 Outstanding, end of year 1,322 1,207 1,272 Intrinsic Value Realized by Weighted-average fair value of Employee 67.6 27.6 109.8 restricted stock granted Realized Tax Benefit 26.7 10.9 43.4 (per share) $75.29 $58.68 $51.23 Fair Value of Shares that Vested 82.7 82.6 232.0 Total fair value of shares for As of December 31, 2007, we had $11.5 million of which restriction has lapsed unrecognized compensation cost related to the unvested portion (in millions) $ 44.5 $ 27.6 $ 19.0 of outstanding stock option awards, of which $8.1 million is expected to be recognized during 2008. As of December 31, 2007, we had $26.8 million of The following table summarizes additional information unrecognized compensation cost related to the unvested portion about stock options outstanding at December 31, 2007 (stock of outstanding restricted stock awards expected to be options in thousands): recognized within a 26-month period. At December 31, 2007, we have recorded in "Common shareholders' equity" Outstanding Exercisable Weighted- approximately $42.3 million and approximately $31.7 million Average Range of Aggregate Aggregate Remaining at December 31, 2006 for the unvested portion of service-Exercise Stock Intrinsic Stock Intrinic Contractual based restricted stock granted from 2003 until 2007 to officers Prices Options Value Options Value Life and other employees that is contingently redeemable in cash (In millions) (In millions) (In years) upon a change in control.

$ 20.00 - $40.00 1,435 $ 97.7 1,435 $ 97.7 5.2

$ 40.00 - $60.00 3,128 149.9 2,608 123.0 5.6

$ 60.00 - $80.00 1,537 41.9 - - 9.1 Performance-Based Units

$80.00 - $100.00 45 0.6 - - 9.5 In accordance with SFAS No. 123R, we recognize 6,145 $290.1 4,043 $220.7 compensation expense ratably for our performance-based awards, which are classified as liability awards, for which the fair value of the award is remeasured at each reporting period.

Restricted Stock Awards Each unit is equivalent to $1 in value and cliff vests at the end In addition to stock options, we issue common stock based on of a three-year service and performance period. The level of meeting certain service goals. This stock vests to participants at payout is based on the achievement of certain performance various times ranging from one to five years if the service goals goals at the end of the three-year period and will be settled in are met. In accordance with SFAS No. 123R, we account for cash. We recorded compensation expense of $17.6 million in our service-based awards as equity awards, whereby we 2007, $24.0 million in 2006, and $7.0 million in 2005 for recognize the value of the market price of the underlying stock these awards. During the 12 months ended December 31, on the date of grant to compensation expense over the service 2007, our 2004 performance-based unit award vested and we period either ratably or in tranches (depending if the award has paid $19.7 million in cash to settle the award. As of cliff or graded vesting). December 31, 2007 we had $17.2 million of unrecognized We recorded compensation expense related to our compensation cost related to the unvested portion of restricted stock awards of $35.8 million in 2007, $24.5 million outstanding performance-based unit awards expected to be in 2006, and $28.2 million in 2005. The tax benefits received recognized within a 26-month period.

associated with our restricted awards were $17.6 million in 2007, $10.9 million in 2006, and $7.5 million in 2005. Equity-Based Grants We recorded compensation expense of $0.9 million in 2007,

$0.6 million in 2006, and $0.5 million in 2005 related to equity-based grants to members of the Board of Directors.

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I 5 Merger and Acquisitions Subsequent Event-Asset Acquisition The pro-forma impact of the CLI acquisition would not In February 2008, we acquired the Hillabee Energy Center, a have been material to our results of operations for the years partially completed 774 MW gas fired combined-cycle power ended December 31, 2007, 2006 and 2005.

generation facility located in Alabama for $155.5 million. We plan to complete the construction of this facility and expect it to Acquisitions of Working Interests In Gas Producing he ready for commercial operation in early 2010. Fields In 2007, we acquired working interests of 41% and 55% in two Cornerstone Energy gas and oil producing properties in Oklahoma for On July 1, 2007, we acquired Cornerstone Energy, Inc (CEI). $208.9 million, subject to closing adjustments. We purchased We include CEL, part of our retail competitive supply operation, leases, producing wells, inventory, and related equipment. We in our merchant energy business segment and have included its have included the results of operations from these properties in results of operations in our consolidated financial statements our merchant energy business segment since the date of since the date of acquisition. CEI provides natural gas supply acquisition.

and related services to commercial, industrial and institutional Our purchase price was allocated to the net assets acquired customers across the central United States. CLI is expected to as follows:

add approximately 100 billion cubic feet of natural gas to our annual volumes served. At March 23, 2007 We acquired 100% ownership for $108.3 million, which (In millions) was paid in cash. As part of the purchase, we acquired Property, Plant and Equipment

$7.3 million in cash. Inventory $ 0.2 The total consideration for accounting purposes, consisting Unproved property 28.8 of cash and other noncash consideration, including the fair value Proved property 179.9 of certain preexisting contracts with CLI, was equal to Net Assets Acquired $ 208.9

$137.6 million.

Our final purchase price allocation for the net assets The pro-forma impact of the acquisition of these working acquired is as follows: interests would not have been material to our results of operations for the years ended December 31, 2007, 2006 and At July 1, 2007 2005.

(In millions) In the first quarter of 2006, we acquired working interests Cash $ 7.3 in gas and oil producing properties for approximately Other Current Assets 89.6 $100 million in cash. We purchased leases, producing wells, and Total Current Assets 96.9 related equipment. We have included the results of operations in Goodwill (1) 103.4 our merchant energy business segment since the date of Net Property, Plant and Equipment 0.5 acquisition.

Other Assets 6.7 Total Assets Acquired 207.5 Termination of Merger Agreement with FPL Group, Inc.

Current Liabilities (66.3) On October 24, 2006, Constellation Energy and FPL Group Deferred Credits and Other Liabilities (3.6) agreed to terminate the Agreement and Plan of Merger the Total Liabilities (69.9) parties had entered into on December 18, 2005. In connection with the termination of the merger agreement, Constellation Net Assets Acquired $137.6 Energy acquired certain development rights from FPL Group

1) Approximately $99 million is deductible for tax purposes. relating to a wind power project in Western Maryland. During 2007, we wrote-off our investment in these development rights.

See Note 2 for further detail.

We incurred merger costs during the year ended December 31, 2006 totaling $18.3 million pre-tax. Our total pre-tax merger-related costs were $35.3 million.

126

6 Related Party Transactions-BGE Income Statement The following table presents the costs Constellation Energy BGE is obligated to provide market-based standard offer service charged to BGE in each period.

to all of its electric customers for varying periods. Bidding to supply BGE's market-based standard offer service to electric Year ended December 31, 2007 2006 2005 customers will occur from time to time through a competitive (In millions) bidding process approved by the Maryland PSC. Charges to BGE $ 160.8 $ 148.8 $130.3 Our wholesale marketing, risk management, and trading operation supplied a substantial portion of BGE's market-based Balance Sheet standard offer service obligation to residential electric customers BGE participates in a cash pool under a Master Demand Note through May 31, 2007, and will supply a portion of BGE's agreement with Constellation Energy. Under this arrangement, market-based standard offer service obligations for all electric participating subsidiaries may invest in or borrow from the pool customers from June 1, 2007 through May 31, 2009. at market interest rates. Constellation Energy administers the The cost of BGE's purchased energy from nonregulated pool and invests excess cash in short-term investments or issues subsidiaries of Constellation Energy to meet its standard offer commercial paper to manage consolidated cash requirements.

service obligation was as follows: Under this arrangement, BGE had invested $78.4 million at December 31, 2007 and $60.6 million at December 31, 2006.

BGE's Consolidated Balance Sheets include intercompany Year Ended December 31, 2007 2006 2005 (In millions) amounts related to corporate functions performed at the Electricity purchased for resale expenses $ 1,139.6 $1,062.0 $805.9 Constellation Energy holding company, BGE's purchases to meet its standard offer service obligation, BGE's charges to In addition, Constellation Energy charges BGE for the Constellation Energy and its nonregulated affiliates for certain costs of certain corporate functions. Certain costs are directly services it provides them, and the participation of BGE's assigned to BGE. We allocate other corporate function costs employees in the Constellation Energy defined benefit plans.

based on a total percentage of expected use by BGE. We believe We believe our allocation methods are reasonable and this method of allocation is reasonable and approximates the cost approximate the costs that would be charged to unaffiliated BGE would have incurred as an unaffiliated entity.

entities.

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7 Quarterly Financial Data (Unaudited)

Our quarterly financial information has not been audited but, in management's opinion, includes all adjustments necessary for a fair statement. Our business is seasonal in nature with the peak sales periods generally occurring during the summer and winter months.

Accordingly, comparisons among quarters of a year may not represent overall trends and changes in operations.

2007 Quarterly Data-Constellation Energy 2007 Quarterly Data-BGE E;arnings Earnings Pe r Share Earnings Per Income Applicable from Share of Earnings Income from to Co ntinuing Common Income Applicable from Continuing Common Op erations- Stock- from to Common Revenues Operations Operations Stock Diluted Diluted Revenues Operations Stock (In millions, except per share amounts) (In millions)

Quarter Ended Quarter Ended t)

March 31 $ 5,111.1 $ 302.4 $197.3 $195.7 $1.08 $1.07 March 31 $ 922.1 $136.0 $ 66.0 June 30 4,876.3 154.4 116.3 116.3 0.64 0.64 June 30 707.1 50.5 13.6l September 30 5,856.4 425.1 250.7 251.4 1.37 1.38 September 30 896.9 66.5 24.4 December 31 5,349.4 452.5 258.1 258.1 1.42 1.42 December 31 892.4 81.3 22.6 Year Ended Year Ended 6 December 31 $21,193.2 $1,334.4 $822.4 $821.5 $4.51 $4.50 December 31 $3,418.5 $334.3 $126.6 The sum of the quarterly earnings per share amounts may not equal the totalfor the year due to the effects of rounding and dilution as a result of issuing common shares during the year. Constellation Energy revenues for the quarter ended March 31, 2007 andJune 30, 2007 have been reclassified to conform with the currentpresentation.

First quarter results include:

• a $1.6 million loss after-tax for the discontinued operations of our High Desert Facility.

Second quarter results include:

" a $8.0 million gain after-tax on sales of equity of CEP,

• a $12.2 million charge after-tax related to a cancelled wind development project, and

" workforce reduction costs totaling $1.4 million after-tax.

Third quarter results include:

" a $24.3 million gain after-tax on sales of equity of CEP, and

" a $0.6 million loss after-tax for the discontinued operations of our Hawaiian geothermal facility, and

• a $1.3 million gain after-tax for the discontinued operations of our High Desert Facility.

Fourth quarter results include:

• a $6.9 million gain after-tax on sales of equity of CEP.

We discuss these items in Note 2.

2006 Quarterly Data-Constellation Energy Eaarnngs 2006 Quarterly Data-BGE Earnings Pe r Share Earnings Per Income Applicable from Share of Earnings Income from to Cointinuing Common Income Applicable from Continuing Common Op erations- Stock- from to Common Revenues Operations Operations Stock oiluted Diluted Revenues Operations Stock (In millions, except per share amounts) (In millions)

Quarter Ended Quarter Ended March 31 $ 4,859.2 $ 204.0 $101.6 $113.9 $0.56 $0.63 March 31 $ 924.2 $141.1 $ 68.4 June 30 4,378.8 178.3 74.0 93.1 0.41 0.52 June 30 642.3 58.5 18.4 September 30 5,393.4 530.9 306.4 324.4 1.69 1.79 September 30 764.5 83.0 35.6 December 31 4,653.5 420.3 266.6 405.0 1.46 2.22 December 31 684.4 86.5 34.7 Year Ended Year Ended December 31 $19,284.9 $1,333.5 $748.6 $936.4 $4.12 $5.16 December 31 $3,015.4 $369.1 $157.1 The sum of the quarterly earnings per share amounts may not equal the totalfor the year due to the effects of roundingand dilution as a result of issuing common shares during the year.

128

First quarter results include:

" an $11.4 million gain after-tax for the discontinued operations of our High Desert facility,

" a $0.9 million gain after-tax for the discontinued operations of our other nonregulated international operations,

• merger-related costs totaling $1.5 million after-tax, of which BGE recorded $0.5 million after-tax, and

" workforce reduction costs totaling $1.3 million after-tax.

Second quarter results include:

• a $19.1 million gain after-tax for the discontinued operations of our High Desert facility, and

• merger-related costs totaling $6.0 million after-tax, of which BGE recorded $1.6 million after-tax.

Third quarter results include:

• an $18.0 million gain after-tax for the discontinued operations of our High Desert facility,

" workforce reduction costs totaling $13.1 million after-tax, and

" merger-related costs totaling $2.5 million after-tax, of which BGE recorded $0.7 million after-tax.

Fourth quarter results include:

" a $47.1 million gain after-tax on sale of gas-fired plants,

" a $17.9 million gain after-tax on the initial public offering of CEP,

" a $138.4 million gain after-tax for the discontinued operations of our High Desert facility,

" workforce reduction costs totaling $2.6 million after-tax, and

• tax benefits associated with merger-related costs totaling $(4.3) million after-tax, of which BGE recorded $(1.6) million after-tax.

We discuss these items in Note 2.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None.

Items 9A and 9A(T). Controls and Procedures Evaluation of Disclosure Controls and Procedures The principal executive officers and principal financial officer of both Constellation Energy and BGE have evaluated the effectiveness of the disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act")) as of December 31, 2007 (the "Evaluation Date"). Based on such evaluation, such officers have concluded that, as of the Evaluation Date, Constellation Energy's and BGE's disclosure controls and procedures are effective.

Internal Control Over FinancialReporting Each of Constellation Energy and BGE maintains a system of internal control over financial reporting as defined in Exchange Act Rule 13a-15(f). The Management's Reports on Internal Control Over Financial Reporting of each of Constellation Energy and BGE are included in Item 8. FinancialStatements and Supplementary Data included in this report. As BGE is not an accelerated filer as defined in Exchange Act Rule 12b-2, its Management's Report on Internal Control Over Financial Reporting is not deemed to be filed for purposes of Section 18 of the Exchange Act as permitted by the rules and regulations of the Securities and Exchange Commission.

Changes in Internal Control During the quarter ended December 31, 2007, there has been no change in either Constellation Energy's or BGE's internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that has materially affected, or is reasonably likely to materially affect, either Constellation Energy's or BGE's internal control over financial reporting.

Item 9B. Other Information None.

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PART III The information required by this item with respect BCE meets the conditions set forth in General to executive officers of Constellation Energy Group, Instruction I(l)(a) and (b) of Form 10-K for a reduced pursuant to instruction 3 of paragraph (b) of Item 401 disclosure format. Accordingly, all items in this section of Regulation S-K, is set forth following Item 4 of related to BCE ate not presented. Part I of this Form 10-K under Executive Officers of the Registrant.

Item 10. Directors and Executive Officers of the Registrant Item 11. Executive Compensation The information required by this item with respect to The information required by this item will be set forth directors will be set forth under Election of Directors in under Executive and Director Compensation and Report of the Proxy Statement and incorporated herein by Compensation Committee in the Proxy Statement and reference. incorporated herein by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters The additional information required by this item will be set forth under Stock Ownership in the Proxy Statement and incorporated herein by reference.

Equity Compensation Plan Information The following table reflects our equity compensation plan information as of December 31, 2007:

(a) (b) (c)

Number of securities Number of securities remaining to be issued upon Weigh ted-average available for future issuance exercise of exercise price of under equity compensation outstanding options, outstanding options, plans (excluding securities Plan Category warrants, and rights warrants, and rights reflected in item (a))

(In thousands) (In thousands)

Equity compensation plans approved by security holders 5,097 $58.79 9,245 Equity compensation plans not approved by security holders 1,048 $41.83 Total 6,145 $55.90 9,245 The plans that do not require shareholder approval are the Constellation Energy Group, Inc. 2002 Senior Management Long-Term Incentive Plan (Designated as Exhibit No. 10(p)) and the Constellation Energy Group, Inc. Management Long-Term Incentive Plan (Designated as Exhibit No. 1O(q)). A brief description of the material features of each of these plans is set forth below.

2002 Senior Management Long- Term Incentive Plan The 2002 Senior Management Long-Term Incentive Plan became effective May 24, 2002 and authorized the issuance of up to 4,000,000 shares of Constellation Energy common stock in connection with the grant of equity awards. No further awards will be made under this plan. Any shares covered by an outstanding award that is forfeited or cancelled, expires or is settled in cash will become available for issuance under the shareholder-approved 2007 Long-Term Incentive Plan. Shares delivered pursuant to awards under this plan may be authorized and unissued shares or shares purchased on the open market in accordance with the applicable securities laws. Restricted stock, restricted stock unit, and performance unit award payouts will be accelerated and stock options and stock appreciation rights gains will be paid in cash in the event of a change in control, as defined in the plan. The plan is administered by Constellation Energys Chief Executive Officer.

130

Management Long-Term Incentive Plan The Management Long-Term Incentive Plan became effective February 1, 1998 and authorized the issuance of up to 3,000,000 shares of Constellation Energy common stock in connection with the grant of equity awards. No further awards will be made under this plan. Any shares covered by an outstanding award that is forfeited or cancelled, expires or is settled in cash will become available for issuance under the shareholder-approved 2007 Long-Term Incentive Plan.

Shares delivered pursuant to awards under the plan may be authorized and unissued shares or shares purchased on the open market in accordance with applicable securities laws. Restricted stock, restricted stock units, and performance unit award payouts will be accelerated and stock options and stock appreciation rights will become fully exercisable in the event of a change in control, as defined by the plan. The plan is administered by Constellation Energy's Chief Executive Officer.

Item 13. Certain Relationships and Related Transactions, and Director Independence The additional information required by this item will be set forth under Related Persons Transactions and Determination of Independence in the Proxy Statement and incorporated herein by reference.

Item 14. Principal Accountant Fees and Services The information required by this item will be set forth under Ratification of PricewaterhouseCoopersLLP as Independent Registered Public Accounting Firmfor 2008 in the Proxy Statement and incorporated herein by reference.

131

PART IV Item 15. Exhibits and Financial Statement Schedules (a) The following documents are filed as a part of this Report:

1. Financial Statements:

Reports of Independent Registered Public Accounting Firm dated February 26, 2008 of.

PricewaterhouseCoopers LLP Consolidated Statements of Income-Constellation Energy Group for three years ended December 31, 2007 Consolidated Balance Sheets-Constellation Energy Group at December 31, 2007 and December 31, 2006 Consolidated Statements of Cash Flows-Constellation Energy Group for three years ended December 31, 2007 Consolidated Statements of Common Shareholders' Equity and Comprehensive Income-Constellation Energy Group for three years ended December 31, 2007 Consolidated Statements of Capitalization-Constellation Energy Group at December 31, 2007 and December 31, 2006 Consolidated Statements of Income-Baltimore Gas and Electric Company for three years ended December 31, 2007 Consolidated Balance Sheets-Baltimore Gas and Electric Company at December 31, 2007 and December 31, 2006 Consolidated Statements of Cash Flows-Baltimore Gas and Electric Company for three years ended December 31, 2007 Notes to Consolidated Financial Statements

2. Financial Statement Schedules:

Schedule II-Valuation and Qualifying Accounts Schedules other than Schedule II are omitted as not applicable or not required.

3. Exhibits Required by Item 601 of Regulation S-K.

Exhibit Number

• 2 - Agreement and Plan of Share Exchange between Baltimore Gas and Electric Company and Constellation Energy Group, Inc. dated as of February 19, 1999. (Designated as Exhibit No. 2 to the Registration Statement on Form S-4 dated March 3, 1999, File No. 33-64799.)

• 2(a) - Agreement and Plan of Reorganization and Corporate Separation (Nuclear). (Designated as Exhibit No. 2(a) to the Current Report on Form 8-K dated July 7, 2000, File Nos. 1-12869 and 1-1910.)

• 2(b) - Agreement and Plan of Reorganization and Corporate Separation (Fossil). (Designated as Exhibit No. 2(b) to the Current Report on Form 8-K dated July 7, 2000, File Nos. 1-12869 and 1-1910.)

"2(c) - Purchase and Sale Agreement by and between Constellation Power, Inc. and TPF Generation Holdings, LLC dated as of October 10, 2006. (Designated as Exhibit 2(a) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2006, File Nos. 1-12869 and 1-1910.)

• 2(d) - Termination and Release Agreement, dated October 24, 2006, by and among Constellation Energy Group, Inc., FPL Group, Inc. and CF Merger Corporation (Designated as Exhibit 2.1 to the Current Report on Form 8-K dated October 25, 2006, File Nos. 1-12869 and 1-1910.)

• 3(a) - Articles of Amendment and Restatement of the Charter of Constellation Energy Group, Inc. as of April 30, 1999. (Designated as Exhibit No. 99.2 to the Current Report on Form 8-K dated April 30, 1999, File No. 1-1910.)

• 3(b) - Articles Supplementary to the Charter of Constellation Energy Group, Inc., as of July 19, 1999.

(Designated as Exhibit No. 3(a) to the Quarterly Report on Form lO-Q for the quarter ended June 30, 1999, File Nos. 1-12869 and 1-1910.)

• 3(c) - Certificate of Correction to the Charter of Constellation Energy Group, Inc. as of September 13, 1999.

(Designated as Exhibit No. 3(c) to the Annual Report on Form 10-K for the year ended December 31, 1999, File Nos. 1-12869 and 1-1910.)

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• 3(d) - Charter of BGE, restated as of August 16, 1996. (Designated as Exhibit No. 3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 1996, File No. 1-1910.)

• 3(e) - Articles Supplementary to the Charter of Constellation Energy Group, Inc. as of November 20, 2001.

(Designated as Exhibit No. 3(e) to the Annual Report on Form 10-K for the year ended December 31, 2001, File Nos. 1-12869 and 1-1910.)

• 3(f) - Bylaws of BGE, as amended to October 16, 1998. (Designated as Exhibit No. 3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 1998, File No. 1-1910.)

• 3(g) - Articles Supplementary to the Charter of Constellation Energy Group, Inc. as of April 10, 2007 (Designated as Exhibit 3(a) to the Current Report on Form 8-K dated April 10, 2007, File No. 1-12869.)

3(h) - Bylaws of Constellation Energy Group, Inc., as amended to February 22, 2008.

• 4(a) - Indenture between Constellation Energy Group, Inc. and the Bank of New York, Trustee dated as of March 24, 1999. (Designated as Exhibit No. 4 (a) to the Registration Statement on Form S-3 dated March 29, 1999, File No. 333-75217.)

• 4(b) - First Supplemental Indenture between Constellation Energy Group, Inc. and the Bank of New York, Trustee dated as of January 24, 2003. (Designated as Exhibit No. 4(b) to the Registration Statement on Form S-3 dated January 24, 2003, File No. 333-102723.)

• 4(c) - Supplemental Indenture between BGE and Bankers Trust Company, as Trustee, dated as of June 20, 1995, supplementing, amending and restating Deed of Trust dated February 1, 1919. (Designated as Exhibit No. 4 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 1995, File No. 1-1910); as supplemented by Supplemental Indentures dated as of June 15, 1996 (Designated as Exhibit No. 4 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 1996,) and as of June 26, 2000 (Designated as Exhibit 4(c) to the Annual Report on Form 10-K for the year ended December 31, 2006, File Nos. 1-12869 and 1-1910.)

• 4(d) - Indenture dated July 1, 1985, between BGE and The Bank of New York (Successor to Mercantile-Safe Deposit and Trust Company), Trustee. (Designated as Exhibit 4(a) to the Registration Statement on Form S-3, File No. 2-98443); as supplemented by Supplemental Indentures dated as of October 1, 1987 (Designated as Exhibit 4 (a) to the Current Report on Form 8-K, dated November 13, 1987, File No. 1-1910) and as of January 26, 1993 (Designated as Exhibit 4(b) to the Current Report on Form 8-K, dated January 29, 1993, File No. 1-1910.)

• 4(e) - Form of Subordinated Indenture between the Company and The Bank of New York, as Trustee in connection with the issuance of the Junior Subordinated Debentures. (Designated as Exhibit 4(d) to the Registration Statement on Form S-3 dated August 5, 2003, File No. 333-107681.)

• 4(f) - Form of Supplemental Indenture between the Company and The Bank of New York, as Trustee in connection with the issuances of the Junior Subordinated Debentures. (Designated as Exhibit 4 (e) to the Registration Statement on Form S-3 dated August 5, 2003, File No. 333-107681.)

• 4(g)- Form of Preferred Securities Guarantee (Designated as Exhibit 4(f) to the Registration Statement on Form S-3 dated August 5, 2003, File No. 333-107681.)

• 4(h) - Form of Junior Subordinated Debenture (Designated as Exhibit 4(h) to the Registration Statement on Form S-3 dated August 5, 2003, File No. 333-107681.)

• 4(i) - Form of Amended and Restated Declaration of Trust (including Form of Preferred Security) (Designated as Exhibit 4(c) to the Registration Statement on Form S-3 dated August 5, 2003, File No. 333-107681.)

• 4(j) - Indenture dated as of July 24, 2006 between Constellation Energy Group, Inc. and Deutsche Bank Trust Company Americas, as trustee. (Designated as Exhibit 4(a) to the Registration Statement on Form S-3 filed July 24, 2006, File No. 333-135991.)

• 4(k) - Indenture dated as of July 24, 2006 between Baltimore Gas and Electric Company and Deutsche Bank Trust Company Americas, as trustee. (Designated as Exhibit 4(b) to the Registration Statement on Form S-3 filed July 24, 2006, File No. 333-135991.)

133

"4(1) - First Supplemental Indenture between Baltimore Gas and Electric Company and Deutsche Bank Trust 4

Company Americas, as trustee, dated as of October 13, 2006. (Designated as Exhibit (a) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2006, File Nos. 1-12869 and 1-1910.)

• 4(m) - Indenture dated as of June 29, 2007, by and between RSB BondCo LLC and Deutsche Bank Trust Company Americas, as Trustee and Securities Intermediary. (Designated as Exhibit 4.1 to the Current Report on Form 8-K dated July 5, 2007, File No. 1-1910.)

• 4(n) - Series Supplement to Indenture dated as of June 29, 2007 by and between RSB BondCo LLC and Deutsche Bank Trust Company Americas, as Trustee and Securities Intermediary (Designated as Exhibit 4.2 to the Current Report on Form 8-K dated July 5, 2007, File No. 1-1910.)

• 10(a) - Executive Annual Incentive Plan of Constellation Energy Group, Inc., as amended and restated.

(Designated as Exhibit No. 10(a) to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, File Nos. 1-12869 and 1-1910.)

• 10(b) - Constellation Energy Group, Inc. 1995 Long-Term Incentive Plan, as amended and restated. (Designated as Exhibit No. 10(b) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2004, File Nos. 1-12869 and 1-1910.)

• 10(c) - Constellation Energy Group, Inc. Nonqualified Deferred Compensation Plan, as amended and restated.

(Designated as Exhibit No. 10(c) to the Annual Report on Form 10-K for the year ended December 31, 2002, File Nos. 1-12869 and 1-1910.)

• 10(d) - Constellation Energy Group, Inc. Deferred Compensation Plan for Non-Employee Directors, as amended and restated. (Designated as Exhibit 10(a) to the Quarterly Report on Form 10-Q for the Quarter ended September 30, 2006, File Nos. 1-12869 and 1-1910.)

• 10(e) - Amended and restated change in control severance agreement between Constellation Energy Group, Inc.

and Thomas V. Brooks. (Designated as Exhibit 10(f) to the Annual Report on Form 10-K for the year ended December 31, 2005.)

• 10(f) - Grantor Trust Agreement Dated as of February 27, 2004 between Constellation Energy Group, Inc. and Citibank, N.A. (Designated as Exhibit No. 10(d) to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, File Nos. 1-12869 and 1-1910.)

• 10(g) - Amended and restated change in control severance agreement between Constellation Energy Group, Inc.

and Mayo A. Shattuck III. (Designated as Exhibit 10.2 to the Current Report on Form 8-K dated December 19, 2005, File Nos. 1-12869 and 1-1910.)

• 10(h) - Grantor Trust Agreement dated as of February 27, 2004 between Constellation Energy Group, Inc. and T Rowe Price Trust Company. (Designated as Exhibit No. 10(b) to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, File Nos. 1-12869 and 1-1910.)

• 10(i) - Constellation Energy Group, Inc. Benefits Restoration Plan, as amended and restated. (Designated as Exhibit No. 10(m) to the Annual Report on Form 10-K for the year ended December 31, 2001, File Nos. 1-12869 and 1-1910.)

• 10(j) - Constellation Energy Group, Inc. Supplemental Pension Plan, as amended and restated. (Designated as Exhibit No. 10(d) to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, File Nos. 1-12869 and 1-1910.)

• 10(k) - Constellation Energy Group, Inc. Senior Executive Supplemental Plan, as amended and restated.

(Designated as Exhibit No. 10(e) to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, File Nos. 1-12869 and 1-1910.)

• 10(1) - Constellation Energy Group, Inc. Supplemental Benefits Plan, as amended and restated. (Designated as Exhibit No. 10(p) to the Annual Report on Form 10-K for the year ended December 31, 2001, File Nos. 1-12869 and 1-1910.)

• 10(m) - Constellation Energy Group, Inc. Executive Long-Term Incentive Plan, as amended and restated.

(Designated as Exhibit 10(b) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2006, File Nos. 1-12869 and 1-1910.)

134

• 10(n) - Constellation Energy Group, Inc. 2002 Executive Annual Incentive Plan, as amended and restated.

(Designated as Exhibit 10(o) to the Annual Report on Form 10-K for the year ended December 31, 2006, File Nos. 1-12869 and 1-1910.)

• 10(o) - Constellation Energy Group, Inc. 2002 Senior Management Long-Term Incentive Plan, as amended and restated. (Designated as Exhibit 10(c) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2006, File Nos. 1-12869 and 1-1910.)

• 10(p) - Constellation Energy Group, Inc. Management Long-Term Incentive Plan, as amended and restated.

(Designated as Exhibit 10(d) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2006, File Nos. 1-12869 and 1-1910.)

• 10(q) - Summary of Constellation Energy Group, Inc. Board of Directors Non-Employee Director Compensation Program. (Designated as Exhibit 10(x) to the Annual Report on Form 10-K for the year ended December 31, 2004, File Nos. 1-12869 and 1-1910.)

• 10(r) - Constellation Energy Group, Inc. 2007 Long-Term Incentive Plan. (Designated as Exhibit 10(t) to the Annual Report on Form 10-K for the year ended December 31, 2006, File Nos. 1-12869 and 1-1910.)

• 10(s) - Investor Agreement, dated July 20, 2007, by and between Constellation Energy Group, Inc. and Electricite de France International, SA (Designated as Exhibit 10.1 to the Current Report on Form 8-K dated July 25, 2007, File No. 1-12869.)

• 10(t) - Agreed Upon Departure Term Sheet, dated May 18, 2007, by and between Constellation Energy Group, Inc. and E. Follin Smith (Designated as Exhibit 10(b) to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2007, File Nos. 1-12869 and 1-1910.)

• 10(u) - Letter Agreement, dated October 31, 2007, by and between Constellation Energy Group, Inc. and J.P Morgan Securities Inc., as agent for JPMorgan Chase Bank, National Associates, London Branch (Designated as Exhibit 10.1 to the Current Report on Form 8-K dated November 1, 2007, File No. 1-12869.)

• 10(v) - Rate Stabilization Property Purchase and Sale Agreement dated as of June 29, 2007 by and between RSB BondCo LLC and Baltimore Gas and Electric Company, as seller (Designated as Exhibit 10.1 to the Current Report on Form 8-K dated July 5, 2007, File No. .1-1910.)

• 10(w) - Rate Stabilization Property Service Agreement dated as of June 29, 2007 by and between RSB BondCo LLC and Baltimore Gas and Electric Company, as servicer (Designated as Exhibit 10.2 to the Current Report on Form 8-K dated July 5, 2007, File No. 1-1910.)

• 10(x) - Administration Agreement dated as of June 29, 2007 by and between RSB BondCo LLC and Baltimore Gas and Electric Company, as administrator (Designated as Exhibit 10.3 to the Current Report on Form 8-K dated July 5, 2007, File No. 1-1910.)

• 10(y) - Amended and restated change in control severance agreement between Constellation Energy Group, Inc.

and John R. Collins (Designated as Exhibit 10(bb) to the Annual Report on Form 10-K for the year ended December 31, 2005, File Nos. 1-12869 and 1-1910.)

12(a) - Constellation Energy Group, Inc. and Subsidiaries Computation of Ratio of Earnings to Fixed Charges.

12(b) - Baltimore Gas and Electric Company and Subsidiaries Computation of Ratio of Earnings to Fixed Charges and Computation of Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements.

21 - Subsidiaries of the Registrant.

23 - Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm.

31(a) - Certification of Chairman of the Board, President and Chief Executive Officer of Constellation Energy Group, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31(b) - Certification of Executive Vice President and Chief Financial Officer of Constellation Energy Group, Inc.

pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31(c) - Certification of President and Chief Executive Officer of Baltimore Gas and Electric Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

135

31(d) - Certification of Senior Vice President and Chief Financial Officer of Baltimore Gas and Electric Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32(a) - Certification of Chairman of the Board, President and Chief Executive Officer of Constellation Energy Group, Inc. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32(b) - Certification of Executive Vice President and Chief Financial Officer of Constellation Energy Group, Inc.

pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32(c) - Certification of President and Chief Executive Officer of Baltimore Gas and Electric Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32(d) - Certification of Senior Vice President and Chief Financial Officer of Baltimore Gas and Electric Company pursuant to 18 U.S.C. Section, 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Incorporated by Reference.

136

CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES AND BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES SCHEDULE II-VALUATION AND QUALIFYING ACCOUNTS Column A Column B Column C Column D Column E Additions Balance Charged Charged to at to costs Oh Balance at beginning and Accounts- (Deductions)- end of Description of period expenses Describe Describe period (In millions)

Reserves deducted in the Balance Sheet from the assets to which they apply:

Constellation Energy Accumulated Provision for Uncollectibles 2007 $ 48.9 $31.3 $ $ (35.3)(A) $ 44.9 2006 47.4 29.7 (28.2)(A) 48.9 2005 43.1 30.9 (26.6)(A) 47.4 Valuation Allowance Net unrealized (gain) loss on available for sale securities 2007 (18.5) - 1.2 (B) - (17.3) 2006 0.6 -- (19.1)(B) - (18.5) 2005 0.1 -- 0.5 (B) - 0.6 Net unrealized (gain) loss on nuclear decommissioning trust funds 2007 (206.1) -- (50.6)(B) - (256.7) 2006 (110.3) - (95.8)(B) - (206.1) 2005 (73.3) -- (37.0)(B) -- (110.3)

BGE Accumulated Provision for Uncollectibles 2007 16.1 21.0 (16.0)(A) 21.1 2006 13.0 18.1 (15.0)(A) 16.1 2005 13.0 14.1 (14.1)(A) 13.0 (A) Represents principally net amounts charged off as uncollectible.

(B) Represents amounts recorded in or reclassified from accumulated other comprehensive income.

137

SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Constellation Energy Group, Inc., the Registrant, has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.

CONSTELLATION ENERGY GROUP, INC.

(REGISTRANT)

Date: February 26, 2008 By /s/ MAYO A. SHATTUCK III Mayo A. Shattuck III Chairman of the Board, President and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of Constellation Energy Group, Inc., the Registrant, and in the capacities and on the dates indicated.

Signature Title Date Principal executive officer and director:

By /s/ M. A. Shattuck III Chairman of the Board, February 26, 2008 President, Chief Executive M. A. Shattuck III Officer, and Director Principal financial officer:

By /s/ J. R. Collins Executive Vice President and February 26, 2008 Chief Financial Officer J. R. Collins Principal accounting officer:

By Is/ R. K. Feuerman Vice President, Controller and February 26, 2008 Chief Accounting Officer R. K. Feuerman Directors:

/s/ Y. C. de Balmann Director February 26, 2008 Y. C. de Balmann

/s/ A. C. Berzin Director February 26, 2008 A. C. Berzin

/s/ J. T Brady Director February 26, 2008 J. T. Brady

/s/ E. A. Crooke Director February 26, 2008 E. A. Crooke

/s/ J. R. Curtiss Director February 26, 2008 J. R. Curtiss 138

Signature Tide Date Is/ F. A. Hrabowski, III Director February 26, 2008 E A. Hrabowski, III Is/ N. Lampton Director February 26, 2008 N. Lampton Is/ R. J. Lawless Director February 26, 2008 R. J. Lawless

/s/ J. L. Skolds Director February 26, 2008 J. L. Skolds

/s/ M. D. Sullivan Director February 26, 2008 M. D. Sullivan 139

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Baltimore Gas and Electric Company, the Registrant, has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.

BALTIMORE GAS AND ELECTRIC COMPANY (REGISTRANT)

February 26, 2008 By Is/ KENNETH W. DEFONTES, JR.

Kenneth W. DeFontes, Jr.

Presidentand Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of Baltimore Gas and Electric Company, the Registrant, and in the capacities and on the dates indicated.

Signature Tide Date Principal executive officer and director:

By Is/ K. W. DeFontes, Jr. President, Chief Executive February 26, 2008 Officer, and Director K. W. DeFontes, Jr.

Principal financial and accounting officer:

By /s/ 1. R. Collins Senior Vice President and February 26, 2008 Chief Financial Officer J. R. Collins Directors:

/s/ T F. Brady Chairman of the Board of February 26, 2008 Directors T. E Brady Is/ M. A. Shattuck III Director February 26, 2008 M. A. Shattuck III 140

EXHIBIT INDEX Exhibit Number

• 2 - Agreement and Plan of Share Exchange between Baltimore Gas and Electric Company and Constellation Energy Group, Inc. dated as of February 19, 1999. (Designated as Exhibit No. 2 to the Registration Statement on Form S-4 dated March 3, 1999, File No. 33-64799.)

• 2(a) - Agreement and Plan of Reorganization and Corporate Separation (Nuclear). (Designated as Exhibit No. 2(a) to the Current Report on Form 8-K dated July 7, 2000, File Nos. 1-12869 and 1-1910.)

• 2(b) - Agreement and Plan of Reorganization and Corporate Separation (Fossil). (Designated as Exhibit No. 2(b) to the Current Report on Form 8-K dated July 7, 2000, File Nos. 1-12869 and 1-1910.)

• 2(c) - Purchase and Sale Agreement by and between Constellation Power, Inc. and TPF Generation Holdings, LLC dated as of October 10, 2006. (Designated as Exhibit 2(a) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2006, File Nos. 1-12869 and 1-1910.)

• 2(d) - Termination and Release Agreement, dated October 24, 2006, by and among Constellation Energy Group, Inc., FPL Group, Inc. and CF Merger Corporation (Designated as Exhibit 2.1 to the Current Report on Form 8-K dated October 25, 2006, File Nos. 1-12869 and 1-1910.)

• 3(a) - Articles of Amendment and Restatement of the Charter of Constellation Energy Group, Inc. as of April 30, 1999. (Designated as Exhibit No. 99.2 to the Current Report on Form 8-K dated April 30, 1999, File No. 1-1910.)

'3(b) - Articles Supplementary to the Charter of Constellation Energy Group, Inc., as of July 19, 1999.

(Designated as Exhibit No. 3(a) to the Quarterly Report on Form 10-Q for the quarter ended June 30, 1999, File Nos. 1-12869 and 1-1910.)

• 3(c) - Certificate of Correction to the Charter of Constellation Energy Group, Inc. as of September 13, 1999.

(Designated as Exhibit No. 3(c) to the Annual Report on Form 10-K for the year ended December 31, 1999, File Nos. 1-12869 and 1-1910.)

• 3(d) - Charter of BGE, restated as of August 16, 1996. (Designated as Exhibit No. 3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 1996, File No. 1-1910.)

• 3(e) - Articles Supplementary to the Charter of Constellation Energy Group, Inc. as of November 20, 2001.

(Designated as Exhibit No. 3(e) to the Annual Report on Form 10-K for the year ended December 31, 2001, File Nos. 1-12869 and 1-1910.)

• 3(f) - Bylaws of BGE, as amended to October 16, 1998. (Designated as Exhibit No. 3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 1998, File No. 1-19 10.)

• 3(g) - Articles Supplementary to the Charter of Constellation Energy Group, Inc. as of April 10, 2007 (Designated as Exhibit 3(a) to the Current Report on Form 8-K dated April 10, 2007, File No. 1-12869.)

3(h) - Bylaws of Constellation Energy Group, Inc., as amended to February 22, 2008.

• 4 (a) - Indenture between Constellation Energy Group, Inc. and the Bank of New York, Trustee dated as of March 24, 1999. (Designated as Exhibit No. 4(a) to the Registration Statement on Form S-3 dated March 29, 1999, File No. 333-75217.)

• 4(b) - First Supplemental Indenture between Constellation Energy Group, Inc. and the Bank of New York, Trustee dated as of January 24, 2003. (Designated as Exhibit No. 4(b) to the Registration Statement on Form S-3 dated January 24, 2003, File No. 333-102723.)

"4(c) -- Supplemental Indenture between BGE and Bankers Trust Company, as Trustee, dated as of June 20, 1995, supplementing, amending and restating Deed of Trust dated February 1, 1919. (Designated as Exhibit No. 4 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 1995, File No. 1-1910); as supplemented by Supplemental Indentures dated as of June 15, 1996 (Designated as Exhibit No. 4 to the 'Quarterly Report on Form 10-Q for the quarter ended June 30, 1996,) and as of June 26, 2000 (Designated as Exhibit 4(c) to the Annual Report on Form 10-K for the year ended December 31, 2006, File Nos. 1-12869 and 1-1910.)

141

• 4(d) - Indenture dated July 1, 1985, between BGE and The Bank of New York (Successor to Mercantile-Safe Deposit and Trust Company), Trustee. (Designated as Exhibit 4(a) to the Registration Statement on Form S-3, File No. 2-98443); as supplemented by Supplemental Indentures dated as of October 1, 1987 (Designated as Exhibit 4(a) to the Current Report on Form 8-K, dated November 13, 1987, File No. 1-1910) and as of January 26, 1993 (Designated as Exhibit 4(b) to the Current Report on Form 8-K, dated January 29, 1993, File No. 1-1910.)

• 4(e) - Form of Subordinated Indenture between the Company and The Bank of New York, as Trustee in connection with the issuance of the Junior Subordinated Debentures. (Designated as Exhibit 4(d) to the Registration Statement on Form S-3 dated August 5, 2003, File No. 333-107681.)

• 4(f) - Form of Supplemental Indenture between the Company and The Bank of New York, as Trustee in connection with the issuances of the Junior Subordinated Debentures. (Designated as Exhibit 4(e) to the Registration Statement on Form S-3 dated August 5, 2003, File No. 333-107681.)

• 4 (g)- Form of Preferred Securities Guarantee (Designated as Exhibit 4(f) to the Registration Statement on Form S-3 dated August 5, 2003, File No. 333-107681.)

• 4(h) - Form of Junior Subordinated Debenture (Designated as Exhibit 4(h) to the Registration Statement on Form S-3 dated August 5, 2003, File No. 333-107681.)

• 4(i) - Form of Amended and Restated Declaration of Trust (including Form of Preferred Security) (Designated as Exhibit 4(c) to the Registration Statement on Form S-3 dated August 5, 2003, File No. 333-107681.)

• 4(j) - Indenture dated as of July 24, 2006 between Constellation Energy Group, Inc. and Deutsche Bank Trust 4

Company Americas, as trustee. (Designated as Exhibit (a) to the Registration Statement on Form S-3 filed July 24, 2006, File No. 333-135991.)

• 4(k) - Indenture dated as of July 24, 2006 between Baltimore Gas and Electric Company and Deutsche Bank Trust Company Americas, as trustee. (Designated as Exhibit 4(b) to the Registration Statement on Form S-3 filed July 24, 2006, File No. 333-135991.)

"4(1) - First Supplemental Indenture between Baltimore Gas and Electric Company and Deutsche Bank Trust 4

Company Americas, as trustee, dated as of October 13, 2006. (Designated as Exhibit (a) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2006, File Nos. 1-12869 and 1-1910.)

• 4(m) -- Indenture dated as of June 29, 2007, by and between RSB BondCo LLC and Deutsche Bank Trust Company Americas, as Trustee and Securities Intermediary. (Designated as Exhibit 4.1 to the Current Report on Form 8-K dated July 5, 2007, File No. 1-1910.)

• 4(n) - Series Supplement to Indenture dated as of June 29, 2007 by and between RSB BondCo LLC and Deutsche Bank Trust Company Americas, as Trustee and Securities Intermediary (Designated as Exhibit 4.2 to the Current Report on Form 8-K dated July 5, 2007, File No. 1-1910.)

• 10(a) - Executive Annual Incentive Plan of Constellation Energy Group, Inc., as amended and restated.

(Designated as Exhibit No. 10(a) to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, File Nos. 1-12869 and 1-1910.)

• 10(b) - Constellation Energy Group, Inc. 1995 Long-Term Incentive Plan, as amended and restated. (Designated as Exhibit No. 10(b) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2004, File Nos. 1-12869 and 1-1910.)

• 10(c) - Constellation Energy Group, Inc. Nonqualified Deferred Compensation Plan, as amended and restated.

(Designated as Exhibit No. 10(c) to the Annual Report on Form 10-K for the year ended December 31, 2002, File Nos. 1-12869 and 1-1910.)

• 10(d) - Constellation Energy Group, Inc. Deferred Compensation Plan for Non-Employee Directors, as amended and restated. (Designated as Exhibit 10(a) to the Quarterly Report on Form 10-Q for the Quarter ended September 30, 2006, File Nos. 1-12869 and 1-1910.)

• 10(e) - Amended and restated change in control severance agreement between Constellation Energy Group, Inc.

and Thomas V. Brooks. (Designated as Exhibit 10(f) to the Annual Report on Form 10-K for the year ended December 31, 2005.)

• 10(f) - Grantor Trust Agreement Dated as of February 27, 2004 between Constellation Energy Group, Inc. and Citibank, N.A. (Designated as Exhibit No. 10(d) to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, File Nos. 1-12869 and 1-1910.)

• 10(g) - Amended and restated change in control severance agreement between Constellation Energy Group, Inc.

and Mayo A. Shattuck I11. (Designated as Exhibit 10.2 to the Current Report on Form 8-K dated December 19, 2005, File Nos. 1-12869 and 1-1910.)

142

• 10(h) - Grantor Trust Agreement dated as of February 27, 2004 between Constellation Energy Group, Inc. and T. Rowe Price Trust Company. (Designated as Exhibit No. 10(b) to the Quarterly Report on Form 1O-Q for the quarter ended June 30, 2004, File Nos. 1-12869 and 1-1910.)

• 10(i) - Constellation Energy Group, Inc. Benefits Restoration Plan, as amended and restated. (Designated as Exhibit No. 10(m) to the Annual Report on Form 10-K for the year ended December 31, 2001, File Nos. 1-12869 and 1-1910.)

• 10(j) - Constellation Energy Group, Inc. Supplemental Pension Plan, as amended and restated. (Designated as Exhibit No. 10(d) to the Quarterly Report on Form IO-Q for the quarter ended March 31, 2004, File Nos. 1-12869 and 1-1910.)

• 10(k) - Constellation Energy Group, Inc. Senior Executive Supplemental Plan, as amended and restated.

(Designated as Exhibit No. 10(e) to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, File Nos. 1-12869 and 1-1910.)

• 10(1) - Constellation Energy Group, Inc. Supplemental Benefits Plan, as amended and restated. (Designated as Exhibit No. lO(p) to the Annual Report on Form IO-K for the year ended December 31, 2001, File Nos. 1-12869 and 1-1910.)

• 10(m) - Constellation Energy Group, Inc. Executive Long-Term Incentive Plan, as amended and restated.

(Designated as Exhibit 10(b) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2006, File Nos. 1-12869 and 1-1910.)

• 10(n) - Constellation Energy Group, Inc. 2002 Executive Annual Incentive Plan, as amended and restated.

(Designated as Exhibit 10(o) to the Annual Report on Form 10-K for the year ended December 31, 2006, File Nos. 1-12869 and 1-1910.)

• 10(o) - Constellation Energy Group, Inc. 2002 Senior Management Long-Term Incentive Plan, as amended and restated. (Designated as Exhibit 10(c) to the Quarterly Report on Form 1O-Q for the quarter ended September 30, 2006, File Nos. 1-12869 and 1-1910.)

• 10(p) - Constellation Energy Group, Inc. Management Long-Term Incentive Plan, as amended and restated.

(Designated as Exhibit 10(d) to the Quarterly Report on Form IO-Q for the quarter ended September 30, 2006, File Nos. 1-12869 and 1-1910.)

• lO(q) - Summary of Constellation Energy Group, Inc. Board of Directors Non-Employee Director Compensation Program. (Designated as Exhibit 10(x) to the Annual Report on Form 10-K for the year ended December 31, 2004, File Nos. 1-12869 and 1-1910.)

• 10(r) - Constellation Energy Group, Inc. 2007 Long-Term Incentive Plan. (Designated as Exhibit 10(t) to the Annual Report on Form 10-K for the year ended December 31, 2006, File Nos. 1-12869 and 1-1910.)

• 10(s) - Investor Agreement, dated July 20, 2007, by and between Constellation Energy Group, Inc. and Electricite de France International, SA (Designated as Exhibit 10.1 to the Current Report on Form 8-K dated July 25, 2007, File No. 1-12869.)

• 10(t) - Agreed Upon Departure Term Sheet, dated May 18, 2007, by and between Constellation Energy Group, Inc. and E. Follin Smith (Designated as Exhibit 10(b) to the Quarterly Report on Form IO-Q for the quarter ended June 30, 2007, File Nos. 1-12869 and 1-1910.)

• 10(u) - Letter Agreement, dated October31, 2007, by and between Constellation Energy Group, Inc. and J.P.

Morgan Securities Inc., as agent for JPMorgan Chase Bank, National Associates, London Branch (Designated as Exhibit 10.1 to the Current Report on Form 8-K dated November 1, 2007, File No. 1-12869.)

• 10(v) - Rate Stabilization Property Purchase and Sale Agreement dated as of June 29, 2007 by and between RSB BondCo LLC and Baltimore Gas and Electric Company, as seller (Designated as Exhibit 10.1 to the Current Report on Form 8-K dated July 5, 2007, File No. 1-1910.)

• 10(w) - Rate Stabilization Property Service Agreement dated as of June 29, 2007 by and between RSB BondCo LLC and Baltimore Gas and Electric Company, as servicer (Designated as Exhibit 10.2 to the Current Report on Form 8-K dated July 5, 2007, File No. 1-1910.)

• 10(x) - Administration Agreement dated as of June 29, 2007 by and between RSB BondCo LLC and Baltimore Gas and Electric Company, as administrator (Designated as Exhibit 10.3 to the Current Report on Form 8-K dated July 5, 2007, File No. 1-1910.)

• 10(y) -- Amended and restated change in control severance agreement between Constellation Energy Group, Inc.

and John R. Collins (Designated as Exhibit 10(bb) to the Annual Report on Form 10-K for the year ended December 31, 2005, File Nos. 1-12869 and 1-1910.)

12(a) - Constellation Energy Group, Inc. and Subsidiaries Computation of Ratio of Earnings to Fixed Charges.

143

12(b) - Baltimore Gas and Electric Company and Subsidiaries Computation of Ratio of Earnings to Fixed Charges and Computation of Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements.

21 - Subsidiaries of the Registrant.

23 - Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm.

31(a) - Certification of Chairman of the Board, President and Chief Executive Officer of Constellation Energy Group, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31(b) - Certification of Executive Vice President and Chief Financial Officer of Constellation Energy Group, Inc.

pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31(c) - Certification of President and Chief Executive Officer of Baltimore Gas and Electric Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31(d) - Certification of Senior Vice President and Chief Financial Officer of Baltimore Gas and Electric Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32(a) - Certification of Chairman of the Board, President and Chief Executive Officer of Constellation Energy Group, Inc. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32(b) - Certification of Executive Vice President and Chief Financial Officer of Constellation Energy Group, Inc.

pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32(c) - Certification of President and Chief Executive Officer of Baltimore Gas and Electric Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32(d) - Certification of Senior Vice President and Chief Financial Officer of Baltimore Gas and Electric Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Incorporated by Reference.

144

Exhibit 12(a)

CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES 12 Months Ended December December December December December 2007 2006 2005 2004 2003 (In millions)

Income from Continuing Operations (Before Extraordinary Loss and Cumulative Effects of Changes in Accounting Principles) ........................ $ 822.4 $ 748.6 $ 535.9 $ 498.4 $409.4 Taxes on income, Including Tax Effect for BCE Preference Stock Dividends ....................... 419.2 343.1 155.4 110.2 213.7 Adjusted Income ................................. $1,241.6 $1,091.7 $ 691.3 $ 608.6 $623.1 Fixed Charges:

Interest and Amortization of Debt Discount and Expense and Premium on all Indebtedness, net of amounts capitalized ........................... $ 292.8 $ 315.9 $ 297.6 $ 315.9 $325.6 Earnings Required for BCE Preference Stock Dividends................................... 22.3 21.1 21.6 21.4 21.7 Capitalized Interest and Allowance for Funds Used During Construction .......................... 19.4 13.7 9.9 9.7 11.7 Interest Factor in Rentals ........................ 96.7 4.5 6.1 4.1 3.5 Total Fixed Charges............................. $ 431.2 $ 355.2 $ 335.2 $ 351.1 $362.5 Amortization of Capitalized Interest ................. $ 3.5 $ 4.3 $ 3.7 $ 2.8 $ 2.4 Earnings (1)..................................... $1,656.9 $1,437.5 $1,020.3 $ 952.8 $976.3 Ratio of Earnings to Fixed Charges .................. 3.84 4.05 3.04 2.71 2.69 (1) Earnings are deemed to consist of income from continuing operations (before extraordinary items, cumulative effects of changes in accounting principles, and income (loss) from discontinued operations) that includes earnings of Constellation Energys consolidated subsidiaries, equity in the net income of unconsolidated subsidiaries, income taxes (including deferred income taxes, investment tax credit adjustments, and the tax effect of BCE's preference stock dividends), and fixed charges (including the amortization of capitalized interest but excluding the capitalization of interest).

Exhibit 12(b)

BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED AND PREFERENCE DIVIDEND REQUIREMENTS 12 Months Ended December December December December December 2007 2006 2005 2004 2003 (In millions)

Income from Continuing Operations (Before Extraordinary Loss) ......................... $139.8 $170.3 $189.0 $166.3 $163.2 Taxes on Income.............................. 96.0 102.2 119.9 102.5 105.2 Adjusted Income.............................. $235.8 $272.5 $308.9 $268.8 $268.4 Fixed Charges:

Interest and Amortization of Debt Discount and Expense and Premium on all Indebtedness, net of amounts capitalized ..................... $127.9 $104.6 $ 95.6 $ 97.3 $112.8 Interest Factor in Rentals..................... 0.3 0.3 0.3 0.5 0.7 Total Fixed Charges ......................... $128.2 $104.9 $ 95.9 $ 97.8 $113.5 Preferred and Preference Dividend Requirements: (1)

Preferred and Preference Dividends............. $ 13.2 $ 13.2 $ 13.2 $ 13.2 $ 13.2 Income Tax Required ....................... 9.1 8.0 8.4 8.1 8.6 Total Preferred and Preference Dividend Requirements............................ $ 22.3 $ 21.2 $ 21.6 $ 21.3 $ 21.8 Total Fixed Charges and Preferred and Preference Dividend Requirements ...................... $150.5 $126.1 $117.5 $119.1 $135.3 Earnings (2) ................................. $364.0 $377.4 $404.8 $366.6 $381.9 Ratio of Earnings to Fixed Charges ............... 2.84 3.60 4.22 3.75 3.36 Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements.. 2.42 2.99 3.45 3.08 2.82 (1) Preferred and preference dividend requirements consist of an amount equal to the pre-tax earnings that would be required to meet dividend requirements on preferred stock and preference stock.

(2) Earnings are deemed to consist of income from continuing operations (before extraordinary loss) that includes earnings of BGE's consolidated subsidiaries, income taxes (including deferred income taxes and investment tax credit adjustments), and fixed charges other than capitalized interest.

Exhibit 21 SUBSIDIARIES OF CONSTELLATION ENERGY GROUP, INC.-

jurisdiction of Incorporation Baltimore Gas and Electric Company..................................................... Maryland Constellation Holdings, Inc............................................................. Maryland Constellation investments, Inc........................................................... Maryland Constellation Power, Inc................................................................ Maryland Constellation Real Estate Group, Inc.................................. ................... Maryland Constellation Enterprises, Inc ........................................................... Maryland Constellation Energy Commodities Group, Inc............................................. Delaware Constellation Energy Projects and Services Group, Inc....................................... Delaware Safe Harbor Water Power Corporation.................................................... Pennsylvania BGE Home Products & Services, Inc .................................................... Maryland Constellation Energy Resources, LLC..................................................... Delaware Constellation NewEnergy, Inc........................................................... Delaware Constellation Energy Nuclear Group, LLC................................................ Maryland Calvert Cliffs Nuclear Power Plant, Inc ................................................... Maryland Constellation Power Source Generation, Inc................................................ Maryland Constellation Power Source Holdings, Inc.............................. I................... Maryland BGE Capital Trust 11.................................................................. Delaware Nine Mile Point Nuclear Station, LLC ................................................... Delaware R. E. Ginna Nuclear Power Plant, LLC................................................... Maryland The names of certain indirectly owned subsidiaries have been omitted because, considered in the aggregate as a single subsidiary, they would not constitute a significant subsidiary pursuant to Rule 1-02(w) of Regulation S-X.

Exhibit 23 CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM Constellation Energy We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 and Form S-8 (Nos. 333-135991, 333-24705, and 33-49801, and 33-59545, 333-45051, 333-46980, 333-89046, 333-129802, 333-81292, 33-56084, and 333-143260, respectively) of Constellation Energy Group, Inc. of our report dated February 26, 2008 relating to the financial statements, financial statement schedule, and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.

PRICEWATERHOUSECOOPERS LLP Baltimore, Maryland February 26, 2008 Baltimore Gas and Electric Company We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-135991) of Baltimore Gas and Electric Company of our report dated February 26, 2008 relating to the financial statements and Financial statement schedule, which appears in this Form 10-K.

PRICEWATERHOUSECOOPERS LLP Baltimore, Maryland February 26, 2008

Exhibit 31 (a)

CONSTELLATION ENERGY GROUP, INC.

CERTIFICATION 1, Mayo A. Shattuck 111, certify that:

1. 1 have reviewed this report on Form 10-K of Constellation Energy Group, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period coveted by this report;

3. Based on my knowledge, the Financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Designed such internal control over Financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) Dis'closed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent Fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registranr's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's Board of Directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 27, 2008

/s/ MAYO A. SHATTUCK III Chairman of the Board, President and Chief Executive Officer

Exhibit 31 (b)

CONSTELLATION ENERGY GROUP, INC.

CERTIFICATION 1, John R. Collins, certify that:

1. 1 have reviewed this report on Form 10-K of Constellation Energy Group, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's Board of Directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and 'report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 27, 2008

/s/ JOHN R. COLLINS Executive Vice President and Chief Financial Officer

Exhibit 31 (c)

BALTIMORE GAS AND ELECTRIC COMPANY CERTIFICATION 1, Kenneth W. DeFontes, Jr., certify that:

1. 1 have reviewed this report on Form 10-K of Baltimore Gas and Electric Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, nor misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's Board of Directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over Financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 27, 2008

/s/ KENNETH W. DEFONTES, JR.

President and Chief Executive Officer

Exhibit 31 (d)

BALTIMORE GAS AND ELECTRIC COMPANY CERTIFICATION 1, John R. Collins, certifyi that:

1. 1 have reviewed this report on Form 10-K of Baltimore Gas and Electric Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the Financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifyiing officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's Board of, Directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 27, 2008

/s/ JOHN R. COLLINS Senior Vice President and Chief Financial Officer

Exhibit 32(a)

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 I, Mayo A. Shattuck III, Chairman of the Board, President and Chief Executive Officer of Constellation Energy Group, Inc., certify pursuant to 18 U.S.C. Section 1350 adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that to my knowledge:

(i) The accompanying Annual Report on Form 10-K for the year ended December 31, 2007 fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934, as amended; and (ii) The information contained in such report fairly presents, in all material respects, the financial condition and results of operations of Constellation Energy Group, Inc.

Is/ MAYO A. SHATTUCK III Mayo A. Shattuck III Chairman of the Board, President and Chief Executive Officer Date: February 27, 2008

Exhibit 32(b)

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 I, John R. Collins, Executive Vice President and Chief Financial Officer of Constellation Energy Group, Inc., certify pursuant to 18 U.S.C. Section 1350 adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that to my knowledge:

(i) The accompanying Annual Report on Form 10-K for the year ended December 31, 2007 fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934, as amended; and (ii) The information contained in such report fairly presents, in all material respects, the financial condition and results of operations of Constellation Energy Group, Inc.

Is/ JOHN R. COLLINS John R. Collins Executive Vice President and Chief Financial Officer Date: February 27, 2008

Exhibit 32(c)

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 I, Kenneth W. DeFontes, Jr., President and Chief Executive Officer of Baltimore Gas and Electric Company, certify pursuant to 18 U.S.C. Section 1350 adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that to my knowledge:

(i) The accompanying Annual Report on Form 10-K for the year ended December 31, 2007 fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934, as amended; and (ii) The information contained in such report fairly presents, in all material respects, the financial condition and results of operations of Baltimore Gas and Electric Company.

Is/ KENNETH W. DEFONTES, JR.

Kenneth W. DeFontes, Jr.

President and Chief Executive Officer Date: February 27, 2008

Exhibit 32(d)

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 I, John R. Collins, Senior Vice President and Chief Financial Officer of Baltimore Gas and Electric Company, certify pursuant to 18 U.S.C. Section 1350 adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that to my knowledge:

(i) The accompanying Annual Report on Form 10-K for the year ended December 31, 2007 fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934, as amended; and (ii) The information contained in such report fairly presents, in all material respects, the financial condition and results of operations of Baltimore Gas and Electric Company.

/s/ JOHN R. COLLINS John R. Collins Senior Vice President and Chief Financial Officer Date: February 27, 2008