ML071500278

R. E. Ginna - 2006 Annual Financial Report,

ML071500278
Person / Time
Site:	Ginna
Issue date:	05/23/2007
From:	Korsnick M Constellation Energy Group
To:	Document Control Desk, NRC/NRR/ADRO
References
1001797
Download: ML071500278 (175)

Text

Maria Korsnick Site Vice President R.E. Ginna Nuclear Power Plant, LLC 1503 Lake Road Ontario, New York 14519-9364 585.771.5200 585.771.3943 Fax maria.korsnick@costellation.com 0

0Constellation Energy Generation Group May 23, 2007 U. S. Nuclear Regulatory Commission Washington, DC 20555 ATTENTION:

SUBJECT:

Document Control Desk R.E. Ginna Nuclear Power Plant Docket No. 50-244 2006 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 2006 Annual Report. This report contains the financial data required by both regulations.

Should you have questions regarding this matter, please contact Mr. Robert Randall at (585) 771-5219, or Robert.Randall @constellation.com.

Very truly yours, Mary G. Korsnick Attachment cc:

S. J. Collins, NRC D. V. Pickett, NRC Resident Inspector, NRC KpQQ4

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ENERGY DOES MATTER Our goal is to be the premier energy company in North America.

We generate, transmit, and deliver energy, help customers manage energy costs and usage, buy and manage fuels for other power generators, and excel at serving customers all along the energy value chain.

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.n1ity involvement Our focus is energy. We provide innovative solutions and extensive industry knowledge to give our customers a competitive advantage.

We execute our business plan with precision to deliver value for our shareholders, and we implement the right strategies to drive our future success. We care about what matters to our customers, our share-holders, our employees, and the communities where we do business.

What matters most to us is what matters most to you.

CONTENTS Letter to Shareholders 2 Competitive Energy Advantages 4 Delivering Value 6 Our Future Success 8 Caring About What Matters Most 10 Constellation Energy at a Glance 12 Board of Directors 14 Executive Team 16 Understanding Our Form 10-K 18 Glossary 24 Form 10-K

PERFORMANCE MATTERS

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'06 ADJUSTED EARNINGS PER SHARE REVENUES (In hilliomn ofdal]La)

Our adjusted earnings per share grew to a record

$3.61, up 25 percent from 2005.

Note: See Financial Hlighlights, including the GAAP reconciliation, on the inside from cover for more details. Also, cerLain prior year amounts have been reclassified to conform to current year's presentation.

Continuing our record performance, total revenues increased to $19.3 billion in 2006. Our growing scale, extensive industry knowledge, and disciplined risk management approach give us a strong competitive edge.

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'07 DIVIDEND GROWTH (Assassal amounts per share)

Our commitment to shareholders has included increasing dividends approximately in line with our earnings growth.

Since 2004, our annual dividend payments have increased by monre than 52 percent.

PRODUCTIVITY GAINS (IN millions ofdol.,)

Since announcing our long-term productivity initiatives in 2003, we've achieved $97 million in pre-tax savings, and we expect to deliver up to $83 million in additional permanent productivity gains over the next two years.

PERFORMANCE MATTERS

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0Q4 Wo 1-YEAR TOTAL RETURN TO SHAREHOLDERS An investment of$100 in Constellation Energy common stock on December 31, 2005, was worth-with dividends reinvested-$122.69 on December 31, 2006. Our 23 percent total return to shareholders was in line with the total return of the S&P 500 Electric Utilities Index and was better than the S&P 500.

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'06 5-YEAR TOTAL RETURN TO SHAREHOLDERS An investment of $100 in Constellation Energy common stock on December3l, 2001, was worth-with dividends reinvested-$299.56 on December 31, 2006. That's significantly better than the S&P 500 Electric Utilities Index and the S&P 500.

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I dependability eecR wise Investments cistornized solutions Mayo A. Shattuck Ill Cbairman, President & CEO DEAR FELLOW SHAREHOLDERS:

2006 was an extraordinary year for our company on many fronts, and we delivered exceptional results. We generated $19.3 billion in revenues and grew adjusted earnings by 25 percent to a record $3.61 per share.

The strong execution of our business strategy translated into superior returns for our investors. Including stock price appreciation and divi-dends, we achieved total shareholder return of nearly 23 percent in 2006, following a 35 percent return in 2005.

These results continue our long track record of success. Our current management team has met or exceeded our earnings targets and the guidance we gave Wall Street for more than five years. And since November 2001-the expansion of our competitive strategy-our shares have appreciated 208 percent, three times greater than the S&P 500 Electric Utilities Index and six times greater than the S&P 500.

Our success also has allowed us to grow dividends approximately in line with our earnings growth. In January 2007, we announced a quarterly dividend increase of 15 percent-from 37.75 cents per share to 43.5 cents per share-equivalent to a new annual dividend of $1.74.

EXECUTING ON ALL FRONTS Our continued success is due in large part to our integrated, yet diversi-fied, business model. Each business excels in its market artid contributes to our overall performance.

Constellation Energy Commodities Group, our competitive energy wholesale business, is a global leader in energy portfolio management, the largest power marketer in the country, and the fifth largest gas marketer.

We continue to grow our power business profitably, and we're making significant gains in natural gas and coal markets in the United States and abroad. In addition, the successful initial public offering (lPO) of Constellation Energy Partners LI.C last November was an important milestone and will help us realize more value from our expanding port-folio of natural gas properties.

On the retail side, both Constellation NewEnergy and Constellation NewEnergy-Gas performed very well. We've steadily grown sales volumes and margins, and our high renewal rates for power and gas provide stabil-ity in our customer base. More importantly, the future growth picture for these businesses is strong.

Constellation Energy Generation Group also had a busy and productive year. We increased generating capacity by 17 percent at our R.E. Ginna Nuclear Power Plant, and we completed a refueling outage at our Nine Mile Point Nuclear Station in record time.

Our generation team also completed the successful sale of six of our gas-fired merchant plants for $1.6 billion. Market conditions were advantageous, and the attractive price we received provided us with a sig-nificant return on our investments in the plants. We've used a portion of the proceeds to pay down debt and strengthen our already strong balance sheet, aid the remainder of the proceeds provides finds for tIs to invest in more strategically aligned opportunities.

RETURNING TO REGULATORY STABILITY IN MARYLAND Volatile power and gas prices, the end of a six-year freeze on residential electric rates, and election-year politics made 2006 a challenging and difficult year for our regulated transnmission and distribution utility, Baltimore Gas asd Electric Company (BGE), and its customers.

My expectation is that 2007 will see a return to a more stable regula-tory climate in Maryland. There is widespread support for Maryland's suc-cessful market structure, and the Maryland Public Service Commission already has initiated proceedings designed to identify and implement improvements in the wholesale energy auction process. The improve-ments should help reduce the likelihood of sudden and severe price spikes for residential customers.

We remain committed to doing everything we can to help customers manage rising power prices. An important focus is introducing new options for our customers to better manage their usage and lower their bills. The options include new demand response and advanced metering programs, which BGE will launch to test groups later this year. We believe these types of energy management and conservation programs will become a way of life for BGE and its customers.

DEFINING A STRONG INDEPENDENT COURSE Last year at this time, it was our expectation that our proposed merger with FPL Group would have closed by now. However, last October, given the considerable regulatory and political uncertainty in Maryland, we reached a mutual and amicable agreement to terminate it.

The reaction from investors was favorable. Reaffirming our independ-ent course and promising future, our stock reached a new all-time high in 2006. This tells tLs three things: investors understand fully why we entered-and why we exited-the proposed merger; they have full confi-dence in our strengths and capabilities as a stand-alone company; and they believe we're returning to a period of greater stability in energy markets.

The proposed merger would have enabled us to meet an important strategic goal and rapidly grow the scale of our company. However, it fell victim to events beyond the control of either company.

I look back on our outstanding performance during this challenging period with great pride. Despite the distractions, we continued to live up to the commitment of meeting and exceeding our financial promises to investors.

THINKING STRATEGICALLY ABOUT THE FUTURE I strongly believe that competitive markets are the future of the energy industry. They're good for customers, for the economy, and for companies

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like ours that value efficiency and being the best at meeting customers' needs. Competitive markets provide incentive for companies to contimn-ously work toward better and more efficient ways to meet our nation's energy needs. That incentive drives our success.

Energy markets that are open to competition are working.

Competition has done what it is supposed to do-it has improved effi-ciency and lowered costs. Power plants are operating more efficiently in competitive markets, and wholesale power price increases are consistently lower than increases in fuel prices-a clear sign there is downward prcs-sure on costs in the marketplace.

It's a trend that I believe will only grow. As a leading advocate and the No. 1 provider of electricity in competitive markets, we'll continue to speak out in Washington, D.C., and in states that have opened their markets to competition or are dealing with deregulation issues.

Other important energy matters-the cost of energy, the global events that control supply and demand, the need for more clean energy, and the growing strain on the existing energy infrastructure-are becom-ing the topic of frank discussions in households and statehouses across North America. More than ever before, people are becoming aware of the importance of energy to everything around them-and are thinking strategically about energy solutions.

Most of us can agree on the elements of our nation's energy future:

greater conservation and energy management programs; a commitment to reducing greenhouse gases and making greater use of renewable energy; and a more constructive partnership between energy suppliers, customers, regulators, and lawmakers.

For the second consecutive year, the Dow Jones Sustainability North America Index has included Constellation Energy on its list of companies that operate in a socially responsible and sustainable way. Customers turn to our energy supply companies for renewable energy options. We're also an industry leader in providing emission-free nuclear power, and we've established effective waste recycling and pollution prevention programs.

As a leader in corporate responsibility, we believe a solution must be devel-oped to slow, then stop, and eventually reverse greenhouse gas emissions.

The pathway to a greener, more cost-effective energy future is com-petition and a vibrant energy marketplace. A retreat to the old way of doing things would be a disastrous setback. As a nation and as an industr)y we need to get this right. We simply cannot afford to move backward.

CONTINUING TO DO WHAT WE DO BEST Our business model has proven sustainable, and our management team has demonstrated the ability to execute successfully in a wide range of market conditions. We believe there is more to come. We expect to deliver compound annual earnings growth of 22 percent to 26 percent from 2005 to 2008.

We'll achieve this growth by continuing to do what we do best.

We'll deploy capital wisely and identify and execute on opportunities that can drive long-term growth. We'll leverage the scale and capabilities of our competitive platform by further integrating our merchant organiza-tion. And we'll continue to identify and empower the best and brightest minds in our industry.

In 2007, a major element of our growth story is investment. We're spending more to earn more. In the years ahead, we'll invest more in BGE, more in our gas portfolio, and considerably more to upgrade our Maryland plants to meet the requirements of the state's healthy air act.

Our generation fleet is among the cleanest in the industry, and we're fully committed to maintaining and broadening the scope of our envi-ronmental efforts. Over the next three years, we're planning to invest approximately $1.1 billion to produce cleaner energy. We'll also continue to invest in the option for new nuclear power through UniStar Nuclear, our joint enterprise with AREVA.

THE BEST IN THE BUSINESS One of our best stories in 2006 was our people. During our United Way pledge drive, our employees responded by doing even more to help the communities we serve. We boosted our pledge total by 20 percent and raised close to $5 million-making us the No. 1 contributor in Central Maryland and a leading contributor in other markets where we do business.

This speaks to the type of employees we have at Constellation Energy. We're committed to delivering value to our shareholders-and we're committed to every community we serve.

I feel very confident about our future. We're the established leader in the competitive energy sector and a respected nuclear fleet operator.

BGE continues to be a top-performing utility: Our emerging businesses in the United States and abroad are performing well. We just completed our fifth consecutive year of record growth. And the forecast for 2007 and beyond is promising.

Constellation Energy has distinguished itself as a remarkable com-pany with a very bright future. Thank you for being part of it.

Mayo A. Shattuck III Chairman, President, and CEO March 26, 2007 3

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ENERGY MATTERS PROVIDING CUSTOMERS WITH COMPETITIVE ENERGY ADVANTAGES Customers seek the competitive advantage that results from effectively managing energy and energy-related risk. Our superior capabilities-broad scale, extensive industry knowledge, exceptional customer service, and disciplined risk management-help customers gain that advantage.

PROVIDING INNOVATIVE ENERGY SOLUTIONS Managing energy costs and usage, and the associated risks, is chal-lenging. Done well, it can provide a company with a significant competitive advantage. Our innovative solutions and superior risk management help customers effectively manage their unique energy needs so they can focus on what matters most to them-running their businesses successfuly).

We serve as an intermediary between suppliers and consumers of energy. We help producers manage the risk associated with selling their output, and we help businesses manage the price risk associ-ated with buying it. Our pricing is competitive, and our specialized energy-management products, services, and resources help customers achieve cost-effective solutions.

We've built North America's leading retail and wholesale com-petitive energy businesses by being the best at what we do. Our broad scale, extensive industry knowledge, superior customer service, and disciplined risk management make us the provider of choice for intensive energy users.

SERVING THE WORLD'S LEADING COMPANIES Our customers include more than two-thirds of the FORTUNE 100, as well as many of the world's most respected brands, including Harley-Davidson, Kimberly-Clark, Lowe's, Raytheon, and others.

Since 2001, we've provided Raytheon with energy and energy-related services at its facilities in Maryland and Massachusetts. Energy is central to its core business-developing some of the most advanced defense technologies in the world. Using those technologies is the DDG 1000 (pictured left), the country's newest naval destroyer.

Raytheon's Integrated Defense Systems business is designing the electronic and combat systems for this revolutionary warship, which is scheduled to be delivered to the U.S. Navy in 2012.

By going beyond excellent customer care, we become a true extension of our customers' energy procurement functions. According to a recent independent study, 94 percent of our commercial and industrial customers said they were happy they chose us and Would choose us again, and 93 percent said they would recommend us to others. That tells Lis we're doing it right.

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FOR OUR SHAREHOLDERS We've achieved a five-year record of success by executing our growth plan and making smart business decisions. Our total return to shareholders has outpaced other comparable investments, and we continue to take the right steps to support our future growth.

EXECUTING OUR PLAN AS PROMISED We're proud of the value we create for our shareholders. In 2006, our adjusted earnings per share were a record $3.61 -a 25 percent increase over 2005. Including stock price appreciation and dividends, our total shareholder return for 2006 was nearly 23 percent.

A $100 investment made in our company on December 31,2001, with dividends reinvested, was worth $299.56 on December 31,2006.

Over the same time, a $100 investment in the S&P 500 was worth

$135.02, and a $100 investment in the S&P 500 Electric Utilities Index was worth $193.06.

We've achieved this success by remaining sharply focused on delivering results and consistently executing our business plan. We've gained market share, increased productivity, made wise investments, and improved return on invested capital.

Our successful track record makes us optimistic about our future-we believe our compound annual earnings growth will range from 22 percent to 26 percent from 2005 to 2008.

MANAGING OUR BUSINESS WITH DISCIPLINE We're taking the right steps to support our future growth. The profit-able sale of our gas-fired generation plants has enabled us to further strengthen our already strong balance sheet. We used a portion of the proceeds to repay approximately $700 million of debt that matured in early 2007. The remaining proceeds give us available capital to redeploy in smart investments in competitive supply, power genera-tion, and transmission and distribution.

We also continue to focus on implementing productivity initiatives that result in permanent savings. Since we began our productivity push in 2003, we've achieved pre-tax cost savings that add $97 million annually to our bottom line. The productivity gains resulted from streamlining our processes and increasing the output of 0ur generat-ing plants. During 2006, we optimized our nuclear workforce and increased our generating capacity by 17 percent at our R.E. Ginna Nuclear Power Plant, laying the groundwork to achieve our 2007 productivity target.

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ENERGY MATTERS DRIVING OUR

]FUTURE uccEss WITH THE RIGHT STRATEGIES Success takes careful planning, precise execution, and a thorough understanding of energy markets. We're implementing the right strategies today to ensure our continued success tomorrow.

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)stre~fi ' gas Pictured left to right: Nine Mile Point Nuclear Station, Pinedale Anticline gas producing property, and Soda Lake Geothermal Power Plant customer relations-renewa. e enei LEVERAGING WHAT WE'VE BUILT Over the last five years, we've built one of the industry's top-performing wholesale and retail energy supply, risk management, and generation businesses. We did it by honing our core capabilities, focusing on strong customer relationships, and improving productivity.

Now we're realigning these successful businesses to further inte-grate our merchant organization, enabling us to better leverage our scale, expertise, and technology. This realignment provides us with opportunities to improve our operating efficiency and drive long-term growth, and we're going after both.

We're also applying our experience and industry knowledge to grow our natural gas business. In 2006, we completed a successful IPO of Constellation Energy Partners LLC, a company focused on the acquisition, development, and exploitation of oil and natural gas properties. The proceeds from the IPO provide us with capital to invest in natural gas production when we see attractive opportunities that fit with our strategy.

Leveraging our scale to invest in high-quality generation assets and managing them to achieve optimal returns are things we've done well and will continue to do.

POWERING THE FUTURE Through UniStar Nuclear-our joint enterprise with AREVA-we're at the forefront of next-generation nuclear power. UniStar provides a business framework for the development and deployment of advanced, standardized nuclear power plants. With the cost benefits and proven safe performance that come from having a standardized design, this approach can help meet our nation's growing demand for electricity with emission-free power.

We're also exploring innovative ways to expand out use of green energy options to meet our customers' growing demands for clean power. More than 60 percent of our generating output is comprised of sources that produce zero emissions, including hydro, geothermal, nuclear, and solar. Over the next few years, we'll be looking at adding wind and other renewable sources to our portfolio.

At BGE, we're implementing demand response and advanced metering technology pilot programs that could eventually provide our 1.2 million electric and 640,000 natural gas customers with information to better manage when and how they use energy. This is an important step in encouraging energy conservation, helping customers deal with rising power costs, and improving our service to customers.

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At the 2006 Constellation Energy Classic, children of our employees sold snowballs to raise more than $1,200 for Special Olympics Maryland.

ENERGY MATTERS WE CAREL-ABOUT WHAT MATTERS MOST We succeed in business by first having a goal and then a strategy and plan to get us there.

We've received recognition as a leader in corporate responsibility by bringing the same focus and discipline to our charitable giving and community support.

ENABLING CHANGE FOR THE BETTER In 2006, we donated nearly $12 million to organizations working to improve the quality of life in our communities. But our goal is to do more than contribute financially. Our strategy is to drive meaningful, long-term change for the better.

We make it a priority to give of ourselves. Our leaders serve on charitable and educational boards and foundations. Our employees volunteer through our company-wide Power of Caring program, and also serve as coaches, mentors, and leaders for more than 300 non-profit organizations. We constantly measure the progress and effec-tiveness of our community programs and support. As a community leader-and as a leader in business-we must constantly innovate and drive for results.

To achieve maximum results, we concentrate on four key seg-ments related to the energy business and the needs of the communi-ties we serve. These include education, the environment, economic development, and energy assistance for those less fortunate.

Each month, through our sponsorship of the b4students Foundation, a group of high school students from the Baltimore City Public School system visits our headquarters as part of a long-term mentor-ing program with our employees. We're very proud of our ongoing sponsorship of this effort because it illustrates the philosophy behind our support of innovative education programs, which also includes the CollegeBound Foundation, Fund for Educational Excellence, Junior Achievement, Maryland Mentoring Partnership, and Teach for America. Our efforts encourage students to graduate from high school and college to prepare for their future.

IMPROVING THE QUALITY OF LIFE FOR ALL Our efforts center on enhancing the quality of life for all. Our sup-port for the environment includes substantial investment in the lat-est environmental equipment at our plants and ongoing support for leading ecological preservation and restoration organizations.

We support economic-development related organizations, and we're the title sponsor for the Constellation Energy Classic. In addi-tion to raising $2.2 million for Maryland-based non-profits, this PGA TOUR Champions Tour golf tournament has generated a sig-nificant economic impact for Maryland.

While our community involvement touches the lives of people from many walks of life, a significant focus is helping disadvantaged youth realize their potential and achieve their dreams. We accomplish this through our support of the Living Classrooms Foundation, Big Brothers Big Sisters, and other well respected organizations.

We know that the rising cost of energy creates a serious strain for many families we serve and have committed $26 million to provide the neediest with financial support and energy conservation pro-grams. The BGE Crisis Assistance Fund makes grants available to the Fuel Fund of Maryland, the Salvation Army, and other non-profit organizations. Our goal is to help meet immediate energy assistance needs and promote self-reliance.

Our company has a 190-year tradition of substantial community support, and it's a responsibility we take very seriously. We're proud of the generosity shown by our nearly 9,700 employees. As a com-pany and as individuals, we're determined to do what's right and to keep our collective focus on what matters most.

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CONSTELLATION ENERGY AT A GLANCE We're North America's largest competitive provider of power to wholesale, commercial, industrial, and governmental customers, one of the top five 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 we deliver electricity and natural gas to customers in Central Maryland through our regulated utility, Baltimore Gas and Electric.

OUR VISION OUR FOUNDATIONAL VALUES OUR PERFORMANCE VALUES To be dte first-choice provider for customers seeking These values guide our actions:

These values measure our results:

energy solutions in the complex and changing Integrity Speed energy marketplace.

Teamwork Accountability Social & Environmental Responsibility Passion for Excellence Customer Focus Creation of Value Corporate Social Responsibility OUR YEAR'S ACCOMPLISHMENTS

• Named one ofAmerica's Most Admired Energy Companies by

• Received the American Red Cross LifeBoard Recruitment Committee FORTUNE magazine of the Year Award for the most successful blood drive program in

• Ranked No. 37 on the BusinessWeek 50 Top Performers list Central Maryland Moved up to No. 125 on the FORTUNE 500 list

• Received a 2006 EPA C2 P2 Environmental Achievement Award for reducing

• Advanced to No. 370 on the FORTUNE Global 500 list greenhouse gas emissions through the beneficial use of coal ash from our

• Ranked as a Platts Top 250 Global Energy Company, earning a Baltimore plants position as the No. 2 independent power producer worldwide Earned a 2006liTee Line USA designation from the National Arbor Day

• Named to the Dow Jones Sustainability North America Index Foundation for BGE's efforts to protect and enhance Americas urban forests for the second consecutive year Received a 2006 People Loving and Nurturing Trees (PLANT) Award from

• Ranked the largest corporate philanthropist in Baltimore by the Maryland Department of Natural Resources for BGE's tree planting and Baltimore Business Journal tree care efforts

• Inducted into the EPA WasteWi$e Program Hall of Fame for

• Named to Training Magazine's Top 125 list for our outstanding Learning &

our waste prevention and recycling efforts Organizational Development program

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Nuclear - 61%

OPERATING A STRATEGIC GENERATION FLEET (Fcludes gas-firod planus sold in 2000)

Our generating facilities are strategically located and use a variety of fuels.

More than 60 percent of our generating output is from sources that produce zero emissions.

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OUR BUSINESSES OUR FOCUS OUR CUSTOMERS CONSTEI[-ION ENERGY Serving as an intermediary managing price and supply risk Energy producers and intensive energy users worldwide COMMODITIES GROUP between producers and consumers of electricity. coal, natural A wholesale marketing, risk management, and portfolio gas, and oil... helping producers manage the risk associated management and trading operation with selling their output and helping consumers manage the price risk associated with buying it... managing the output and fuels for our generation fleet and selling that power CONSTEI IArION NEWENERGY Meeting our customers' energy and risk management needs More than 14,000 commercial, industrial, and public A retail electricity supply business providing energy through innovative products and outstanding service..,

sector organizations, including over two-thirds of the products and services becoming an extension of our customers' energy procure-FORTUNE 100 companies ment functions... helping customers effectively manage energy costs and usage CONSTELI.ATlON NEWENERGY-GAS DIVISION Offering customers untsparalleled service and expertise by More than 6,000 commercial, industrial, municipal, arsd A natural gas supply and transportation-related providing reliable and economical supplies of tatural gas local gas distribution and power generation facilities in services operation competitive markets throughout North America CONSTELLATION ENERGY GENERAIION GROUP Owning and operating-safely, efficiently, and reliably-Wholesale customers in competitive energy markets across A power generation operation a diversified fleet of fossil, nuclear, and renewable energy North America generating fiacilities.,.pursuing new nuclear energy through UniStar Nuclear, our joint enterprise with AREVA BALuiMORE GAS AND ELECTRIC Safely and reliably delivering electricity and natural gas to More than 1.2 million electric and (40,000 natural A regulated utility delivering power and natural gas our customers... becoming a recognized industry leader..,

gas residential, commercial, and industrial customers improving the reliability of our distribution system, reduc-in Baltimore and in all, or part of, 10 counties in ing interruptions, and improving our response to outages Central Maryland FELLON-MCCORD & ASSOCIATES, Offering clients energy consulting and management Serving large commercial, industrial, municipal, and A leading provider of energy consulting and expertise in the physical, financial, regulatory, and legislative institutional energy users, as well as producers, generators, management services aspects of energy markets aggregators, third party marketers, utilities, storage owners, and operators CONSTI-EI ATION ENERGY PROJECIS Providing customized solutions-including central energy Commercial, industrial, and governmental facilities through-

& SERVICES GROUP plants, on-site power generation, mechanical-electrical out North America, including Heinz Field in Pittsburgh A full-service energy company upgrades, and renewable energy products-to increase energy and municipal and commercial facilities in downtown efficiency, reliability, and cost effectiveness Nashville, Tennessee BGE HOME A competitive provider of energy-related products and services Providing customer-centric, energy-focused solutions for heating, air conditioning, plumbing, electrical, and indoor air quality needs, as well as window replacements and the sale of natural gas to the residential market Residential and small commercial customers in Maryland 13

BOARD OF DIRECTORS MAYO A. SHATTUCK III Chairman, President, and CEO Constellation Energy Director since 1999 Age 52 YVES C. DE BALMANN Co-Chairman Bregal Investments LP Director since 2003 Age 60 DOUGLAS L. BECKER Chairman and CEO Laureate Education, Inc.

Director since 1998 Age 41 JAMES T. BRADY Managing Director, Mlid-Atlantic Ballantrae International, Ltd.

Director since 1999 Age 66 EDWARD A. CROOKE Retired Vice Chairman Constellation Energy Director since 1988 Age 68 JAMES R. CURTISS, ESQ.

Partner Winston & Strawn LLP Director since 1994 Age 53 CORPORATE GOVERNANCE We are an industry leader in corporate governance. We conduct our business honestly, with respect for our professional obligations, and with regard for legal and regulatory requirements. The independence of our Board of Directors is important to us-10 of our I I directors are independent according to New York Stock Exchange listing standards. Michael D. Sullivan, one of our independent directors, serves as lead director.

Copies ofthe charters of each of the committees of the Board of Directors, as well as copies of our Corporate Governance Guidelines, Principles of Business Integrity; Corporate Compliance Program, Insider Trading Policy. and Policy and Procedures with Respect to Related Person Transactions are available on our Web site at wwwvconstellation.com.

INTERESTS ALIGNED WITH SHAREHOLDERS We maintain share ownership guidelines to further align the interests of our directors with the interests of our shareholders.

The guidelines require directors to acquire and maintain holdings of Constellation Energy stock equal to at least five times the annual cash retainer.

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BOARD OF DIRECTORS DR. FREEMAN A. HRABOWSKI III President University of Maryland, Baltimore County Director since 1994 Age 56 NANCY LAMPTON Chairman and CEO American Life and Accident Insurance Company of Kentucky and Hardscuffle, Inc.

Director since 1994 Age64 6

ROBERT J. lAWI.ESS Chairman and CEO McCormick & Company, Inc.

Director since 2002 Age 60 LYNN M. MARTIN President The Martin Hall Group LLC Director since 2003 Age 67 MICHAEL D. SULLIVAN Chairman Life Source, Inc. and ADVANCARE HealthCare, LLC Director since 1992 Age 67 Executive Committee Mayo A. Shattuck III, Chairman Edward A. Crooke Robert J. Lawless Audit Committee James']. Brady, Chairman Yves C. de Balmann Edward A. Crooke All committee menbesrs are audit cormmittee financial experts as defined by SF.C rides.

COMMITTEES OF THE BOARD Compensation Committee Robert J. Lawless, Chairman Douglas L. Becker Dr. Freeman A. Hrabowski III Lynn M. Martin Michael D. Sullivan Nominating and Corporate Governance Committee Michael D. Sullivan, Chairman Douglas L. Becker Dr. Freeman A. Hrabowski III Robert J. Lawless Lynn M. Martin Committee on Nuclear Power James R. Curtiss, Chairman Edward A. Crooke Nancy Lampton Lynn M. Martin 15

EXECUTIVE TEAM MAYO A. SHATTUCK Ilt (f/,aitrraat, frident, and 1..'E Mayo, 52, is the Chairman, Preident. and Chief Executive Officer of Constellarien Energy[ Prior to joining Constellation Energy, he was Chairman orf the Board at Deuttsche Banc Alem. Brown. He also served at Clobal [lead of leit-ment Banhing and Global Head of Private Banking at D)eursche Bank, Vice Chairman at Bankers irtrx, and l[esident at Alex. Brown & Sins.

THOMAS F. BRADY Iecutive Vice Preaident itrn. 57. is resptonsible For Constellation Newknetgy and the retail bmuinesses, as well as corptrate strategy, mergers and acquisitions, corptrate communications, branding, and government affairs. -le is also Chairman tof Baltimore Gas and Electric. Tom has served as Chief Accounting Officer at Baltimtrore (as and Electric, at well at in a variety tf executive adtal management poitions.

THOMAS V. BROOKS lceecotrce Vice Ptraidestr Tlrm. 44, heads the merchant organization. He is retponsible forr tur retail and wholesale competitive energy cotmpanics and non-nuclear power generation, as well as for the strategy and execution of merchant acquisitions ana dicestitures and tlte devel-opment of non-onclear assres. Previtredy, 'Iem was Preeident and C(IO ofContelrhlation E-nrgyComrmodities Group. Ptior t joining Constellation Energy. lie worked in the Fixed lncrne and Con,,-

modlitirt Division at Goldman, Sachs & Co.

E. FOILIN SMITH I&'e,rtire Vice Pridctr Chief inrancial Office, and QjhiefAdmitnitraatie O-cer Follin. 47, is responsible for finance, informnaion technology human resources, legal, ardit, risk management, investor relations, ard business perforarrrce improvement. Prior to joining Cofnstellation Energy, Follin was Senior Vice President and Chief Financial Officer ofAertstrong Holdings, Inc. She also has served it various financial erecutive positions ar General Motors Corp.

MICHAELJ. WALLACE F-recttire Vice President Preident and f.'/f. fCooeellaeton Energey Generation Gftrp Mike, 59. is responsible for or nuclear potver generation bhsiness.

Prior to joining Constclaritoi Energy, he was Co-Founder anrd Managing Director of hattiongton Energy Partrnes, 1LC. Mike also was Chicf Nuckar Officer ard served in various ececouive positions at Unicort/ComEd.

IRVING B. YOSKOWIT1 Feecutrive Vice President and General C0aoe1 Irv, 61. is tesponsihie for corporate governance and compliance, mergers and acquisitions. litigation, and bhsiens nirt legal orvincs.

Prior to joining Constellation Energy, li served as Senior Partner of Global 'Tecloilogy Partners, 1,C. Senior Counsel at Crowell &

Moring, L,-C, and Senior Consultant at Chiarlec River Associates, Irv also was F,-soctrive Vice President and General Counsel at United Tcdhirologis Corp. and held a variety of positions as IBM, PROVEN LEADERSHIP Our mission is to be the nation's leading energy manager and competitive supplier, generating and delivering power and natural gas safely and reliably to our customers, while acting in the interests of our communities, employees, shareholders, and the environment.

Our executive team provides the proven leadership, strategic vision, skilled market analysis, and agile decision-making that help us achieve that mission.

INTERESTS ALIGNED WITH SHAREHOLDERS We maintain ownership guidelines to further align the interests of our executives with the interests of our shareholders.

The guidelines require our executives to acquire and maintain holdings of Constellation Energy stock ranging from three times base salary for senior vice presidents to seven times base salary for our CEO.

16

EXECUTIVE TEAM (2)

PAULJ. ALLEN Setnior Vice President, Corporate A_#Lcirs Paul, 55, is responsible for external affairs, government and regulatory relations, and environmental policy. prior to joining Constellarin Eoergy, Paul was Senior Vice l'residenr and Group Head at Ogilvy Public Relations. He also was a senior staff mem-ber at the Natural Resources Defense Council, Prom Secretary for Senator Christopher l)Dold (l)-Coon.), and Foreign News Falitr and Eadior of Morning Edirion at National Pudlic Radio.

JOHN R. COLLINS Senior Vice President and C(eic/isk Offlcer John. 49, is responsible fiar ass.ssing and managing risk. He also senrve on the Board of Managers (if Constellation Energy Partners LIC.

Previously. he was Managing Director (af Finance and 'Aieasutre of Constellation lPower Source Holdings and Consrellation Energy Conmnodities Group. lie also has served itt various leadership pose-rtons at Constellation Fnergy Cosnrtiodities Group and Baltimore Gas and Electric. Prirtm tojoining Baltinmre Gas and Electric, lte hetl various financial management positions at Bell Atlantic Corporation and Perdtcu Farms, Inc.

FELIXJ. DAWSON

.anior Vice Presidenr CAs-la-ceident and (OeGhiia'Ececutive Officer, Canectaeltion Energ Comoaraities Grottp Felix, 39, is responsible for wholeale energy; coartolity

-rrices, and risk management for electricity, coal. natural gas, and related commodiries. He also serven as President anal CEO of Constellarion Energy Partters (IC.

Previously, he was Co-Chief Commercial Officer, Constellation Energy Commoditie Group and served in svriotts leadership Posritons in origination and portfolio management.

lIe also has held a variety of positions at Goldman, Sachs & Co.

KENNETH W. DEFONTFS, JR.

Senior Vice Preridant lreaaiient and ChO. Baltimore G(as and Elctrtc Ken. 56, is responsible for our regulated electric and natural gas distribution utility in Cental Maryland. Peviously, Kent was Vice President, Electric Tratstnission and IDistribttion, and also has served itt various executive and nataagctcnt positions at [altienore Gas and Electric.

BETH S, PERLMAN Senior 14ce President and C'rueflafttrrtetion

/fficer leath, 46. is responsible for inafow*arion technology initiatives that support husiness transfomationt sod enrble growtlh, Prior to joining Constellation Energy, asie was Vice Psesidetnt of Wholesale Trading fcclAhnology and served it, various ather tchttolagy and operations matnagemettl positions at Eaneont.

Shte also held various financial and technoology management positiets at I,ehl an Brothers, b-c..

Kidder, Peabody & Co., andJPMorgan.

GEORGE E. PERSKY Senior 1lce President Ce-President and (7-05si E-vecrao5e (ffcer, iotelhltrion Energy Coanoediries Grotp Ccorge, 37, is responsible for swholesale

energy, commodity services, and risk management for electricity, coal, natural gas, and relstcd cotntodities. Poniously, he

,as Co-Chief Commercial Officer, Consaellation Energy Contrtoditias Group and served in variioma leadership positions in origination and portfolio management, He also has held a vatiety of positions at Coldotan. Sachs & Co.

MARC L. UGOL Setior Vie I/sideat, Haaman Reaeaaeeee Marc, 48. is preponsible for staffing, organization effectivetess, labor relationa, com.pensation, and haecfits. Prior to joining Constellation Energy, lae na Senior Vice Iresident of Human Resoutces at

'lillabs, Inc. He also served in luman resnources managemaent pani-tons at Hlatinurn'li:dclatology, lie.. Systett Software Asociates, Inc.,

and Amoco Corporation.

17

UNDERSTANDING OUR FORNI 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 information 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 I 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.

18

UNDERSTANDING OUR FORM 10-K 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 environmental matters, employees, properties, and executive officers.

HERE'S WHERE YOU LOOK IN PART I HIGHLIGHTS OF WHAT YOU'LL FIND PAGES ITEM SECTION 2

1. Business Overview We have a merchant energy business and a regulated utility.

2-3 Operating Segments Our reportable operating segments are merchant energy, regulated electric, and regulated gas.

We also have certain other nonregulated business activities.

3-9 Merchant Energy Our business Business W'e provide energy products and services to distribution utilities, power generators, and other wholesale customers.., electricity and natural gas supply and services to cosmmercial, industrial, and governmental customers... global coal sourcing and freight activities... natural gas services...

we generate electricity... and we engage in portfolio management and trading activities.

Fuel sources Our electricity generated by fuel type in 2006: nuclear-52 percent, coal-30 percent, natural gas-15 percent, renewable and alternarive-3 percent.

Our competition We encounter competition from companies of various sizes with varying levels 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 five years Revenues by type, distribution volumes to our customers, and the number of our customers.

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

Businesses 15 Consolidated Capital Our total capital requirements for 2006 were $1.1 billion, and we expect them to be Requirements

$1.9 billion in 2007.

15-17 Environmental Matters We are subject to regulations concerning air quality, water quality, and disposal of hazardous substances. Over the next three years, our estimated capital requirements for environmental matters are $1.1 billion.

17 Employees We had approximately 9,645 employees at year-end 2006.

18-22 IA. 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.

NOTE: This special section is intended to be a guide. You ean find more derails aboti all these tens inou Form 10-K, which follows this special section.

19

UNDERSTANDING OUR FORM 10-K PART I: OUR BUSINESSES (continued)

HERE'S WHERE YOU LOOK IN PART I HIGHLIGHTS OF WHAT YOU'LL FIND PAGES ITEM SECTION 22-24

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.

24

4. Submission of At our annual meeting in December 2006, our shareholders re-elected directors Matters to Vote of Douglas L. Becker, Edward A. Crooke, Mayo A. Shattuck III, and Michael D. Sullivan; Security Holders ratified PricewaterhouseCoopers LLP as our independent registered public accounting firm for 2006; and approved a shareholder proposal to declassify our Board of Directors.

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 II: OUR FINANCIAL PERFORMANCE Part II contains managements discussion and analysis of our results of operations and financial condition, and our audited financial statements. It compares our results from 2006 with those from 2005, and our results from 2005 with those from 2004. 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 Statements-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 1I HIGHLIGHTS OF WHAT YOU'LL FIND PAGES ITEM SECTION 27

5. Market for Our dividend information Registrant's Common We declared dividends of $1.51 per share in 2006 and increased our annual dividend to Equity and Related

$1.74 per share in January 2007.

Shareholder Matters Our stock price The price of our common stock-based on New York Stock Exchange Composite Transactions-ranged from $50.55 to $70.20 in 2006.

28-29

6. Selected Summary of our and BGE's operations and financial condition and our financial statistics for Financial Data the last five years.

NOTE-This special section is intended to be a guide. You can find more derail abomt all these tents in otr Form 10-K, which follows this special section.

20

UNDERSTANDING OUR FORM 10-K MANAGEMENT'S DISCUSSION AND ANALYSIS THE CONTEXT. Our management discusses in detail the financial results and condition of our company and the way we manage our business.

HERE'S WHERE YOU LOOK IN PART 11 HIGHLIGHTS OF WHAT YOU'LL FIND PAGES ITEM SECTION 30

7. Management's Introduction We summarize how we have organized our discussion mnd analysis.

Discussion and Analysis and Overview 30-31 Strategy We are pursuing a strategy to provide energy and energy-related sen'ices through our com-petitive supply activities and our regulated Maryland utility.

31-34 Business Environment Energy markets continue to be volatile with significant changes in natural gas and power prices. We continue to be subject to extensive federal and state regulation.

34-37 Critical Accounting These are the accounting policies that require difficult, subjective, or complex judgment and Policies which are most important to the portrayal of our financial condition and results of operations.

37-38 Significant Events 2006 significant events include:

- The termination of our proposed merger with FPL Group

- Volatile commodity prices

- Legislation enacted by the Maryland General Assembly

- The sale of six of our gas-fired generating plants

- The partial pha-se-out of syntlhetic fuel tax credits W

Workforce restructuring at our nuclear facilities

• Acquisition of working interests in gas and oil producing fields

• An initial public offering of common stock in Constellation Energy Partners LLC (CEP)

• Approval of operating license extensions for Nine Mile Point Nuclear Station

• An increase in generating capacity at R.E. Ginna Nuclear Power Plant

• Our dividend increase 39-52 Results of Operations The detailed discussion of our earnings Our overall net income for 2006 was $936.4 million, an increase of $313.3 million from 2005, driven mostly by higher earnings from our merchant energy business, higher income from discontinued operations, gains from the sale of gas-fired generating facilities, and the gain on the initial public offering of ClP.

Our merchant energy income from continuing operations was $580.1 million in 2006, an increase of $220.7 million from 2005.

Our regulated electric net income for 2006 was S 120.2 million, a decrease of $29.2 million from 2005. Our regulated natural gas net income for 2006 was $37.0 million, an increase of $10.3 million from 2005.

53-55 Financial Condition Cash flow Cash provided by our operations was $525.3 million in 2006.

Security ratings All of our securit), ratings are investment-grade.

55-58 Capital Resources We're estimating that we'll need $1.9 billion in capital for 2007 and $1.7 billion in 2008 to fund existing and anticipated projects.

58-63 Market Risk We are exposed to various risks. Our risk mtanagement program uses an effective system of internal controls, and the audit conmaittee of our Board of Directors periodically reviews compliance with our risk paranmeters, limits, and trading guidelines.

NOTM5 This special section is intended to be a guide. You can find more details about all these items in our Form 10-K, which follows this special secion.

21

UNDERSTANDING OUR FORM 10-K OUR FINANCIAL STATEMENTS THE NUMBERS. We provide separate financial statements for Constellation Energy and BGE. This section also includes our management's and auditor's reports on our financial information and the effectiveness of our internal controls.

HERE'S WHERE YOU LOOK IN PART II HIGHLIGHTS OF WHAT YOU'LL FIND PAGES ITEM SECTION 64

8. Financial Report of Management Our management accepts responsibility for the information and representations in our Statements and financial statements and concludes that our internal control over financial reporting was Supplementary Data effective as of December 31, 2006.

64-66 Report of Independent

.PricewaterilouseCoopers LLP states its opinion that our consolidated financial statements Registered Public present fairly, in all material respects, the financial condition of our company and that we Accounting Firm maintained, in all material respects, effective internal control over financial reporting at December 31, 2006.

67 Consolidated Statements Our net income for 2006 was $936.4 million.

of Income 68-69 Consolidated Balance Our total assets were $21.8 billion at December 31, 2006.

Sheets 70 Consolidated Statements Our cash and cash equivalents at December 31, 2006, were $2.3 billion, an increase of of Cash Flows

$1.5 billion from a year earlier.

71 Consolidated Statements We discuss the composition of and changes in our common shareholders' equity.

of Common Shareholders' In 2006, we declared $272.6 million in dividends.

Equity and Comprehensive Income 72-73 Consolidated Statements At December 31, 2006, our total capitalization was $9.1 billion-$4.2 billion in long-term of Capitalzation debt, $94.5 million in minority interests, $190.0 million in preference stock, and $4.6 billion in common shareholders' equity.

74-77 BGE Financial We include financial statements for BGE because it is a separate registrant required to file Statements reports with the SEC.

NOTES TO OUR FINANCIAL STATEMENTS THE DETAILS. We explain the processes, events, actions, projects, issues, and specifics that produce the amounts reflected in our financial statements.

HERE'S WHERE YOU LOOK IN PART II HIGHLIGHTS OF WHAT YOU'LL FIND PAGES ITEM SECTION 78-88 Note 1: Significant Accoutising methods that we use and how dsey're applied throughout our businesses, Accounting Policies along with the new accounting standards issued and adopted.

89-91 Note 2: Other Events Other events added $351.5 millios to our pre-tax earnings, reflecting $295.5 million in income from discontinued operations associated with the sale of our High Desert plant, $73.8 million in income from the gain on the sale of the five other gas-fired plants, and $28.7 million in income from a gain on our initial public offering of CEP...offset by $28.2 million in work-force reduction costs and $18.3 million in merger-related costs.

NOT. Trhis special section is intended to be a guide. You can find more derails about all these items in our Form 10-K, which Follows this special section.

22

UNDERSTANDING OUR FORM 10-K NOTES TO OUR FINANCIAL STATEMENTS (continued)

HERE'S WHERE YOU LOOK IN PART II HIGHLIGHTS OF WHAT YOU'LL FIND PAGES ITEM SECTION 92-93 Note 3: Information by Our revenues, net income, and other financial information broken out by operating segment Operating Segment show the growth of our merchant energy business.

94-96 Note 4: Investments Our investments are mainly financial investments related to our nuclear decommissioning trust funds.

97 Note 5: Intangible Assets At December 31, 2006, our carrying amount of goodwill was $157.6 million, and our total net intangible assets were $304.7 million.

98-99 Note 6: Regulatory At December 31, 2006, our total regulatory assets (net) were $451.5 million, which included Assets (net)

$326.9 million deferred for future collection under the rate stabilization plan provided for in Maryland legislation.99-102 Note 7: Pension, Postre-We provide details-obligations, assets, assumption details, and company contributions-tirement, Other Postem-about our employee benefit plans.

ployment, and Employee Savings Plan Benefits 103 Note 8: Credit Facilities Our short-term borrowings (debt that matures within one year from the date it's issued) may and Short-Termn include bank loans, commercial paper, and bank lines of credit.

Borrowings 103-105 Note 9: Long-Term Debt We provide details about our long-term debt (debt that matures a year or more from the and Preference Stock date ites issued) and about our preference stock.

106-108 Note 10: Taxes Our income tax expense for 2006 was $351.0 million, which reflected a net $75.9 million favorable impact from synthetic fuel tax credits after estimated phase-out.

108 Note 1i: Leases We provide details about the capital and operating leases in which we enter.

108-113 Note 12: Commitments, We provide details about our commitments and financial guarantees, environmental matters, Guarantees, and legal proceedings involving us, and our insurance coverage.

Contingencies 113-114 Note 13: Hedging We explain how we manage commodity price fluctuations and interest rate exposure, and we Activities and Fair Value disclose the fair value of our financial instruments.

of Financial Instruments 115-116 Note 14: Stock-Based We provide stock-based compensation in the form of stock options, restricted stock, Compensation performance-based units, and equity to employees.

117 Note 15: Merger and We agreed to terminate our proposed merger with FPL Group, and we also acquired Acquisitions working interests in gas and oil producing properties.

117-118 Note 16: Related Party Our merchant energy business provides BGE with a portion of the energy it needs, we Transactions-BGE provide BGE with the services of certain corporate functions, and BGE participates in our benefit plans.

118-120 Note 17: Quarterly Finan-We break out our financial results-and those of BGE-by quarter for the last two years.

cial Data (Unaudited)

I NOTF h

This special section is intended to be a gtide. You can find.,ore derails abo all thee items in our Forn I0-K, which Follows this special section.

23

GLOSSARY AGGREGATOR-a company, intermediary, or agent that combines the energy needs of multiple customers and then buys or provides the energy and services needed BRITISH THERMAL UNIT (BTU)-a basic unit used to mseasure natu-ral gas; the amount of natural gas needed to raise the temperature of one pound of water by one degree Fahrenheit COMPETITIVE SUPPLY BUSINESS-the portionof our business that provides energy and related value-added services to wholesale and retail customers in competitive markets D EKATH ERM (DTH)-a standard measurement of natural gas; ten therms or one million BTUs DEREGULATION-in the industry, the process by which regulated mar-kets become competitive markets, giving customers the opportunity to choose their energy supplier DISTRIBUTION-the delivery of energy to locations where customers use it-including homes, businesses, and industrial facilities ESTIMATED PROVED RESERVES-estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data show with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions FEDERAL ENERGY REGULATORY COMMISSION (FERC)-the U.S.

agency that regulates interstate energy activities FULL REQUIREMENTS SERVICE-a product offering that handles all of a customer's energy needs through a combined service that may include generating or buying energy, managing load and power purchase agree-ments, scheduling delivery, managing risk, settling accounts, and other related activities GENERATING CAPACITY-the amount of electricity that can be pro-duced by a specific generating facility GENERATION -the process of transforming other forms of energy-coal, natural gas, uranium, oil, wind, water, or sun-into electricity HEDGING-entering into transactions to manage various types of risk, such as commodity price risk INDEPENDENT SYSTEM OPERATOR-a federally regulated organi-zation that manages regional transmission lines to deliver electricity LOAD-SERVING-the processý,of providing customers with the energy they need MARK-TO-MARKET-the valuation of a security, commodity, or finan-cial instrument to reflect current market values MARYLAND PUBLIC SERVICE COMMISSION-the agency respon-sible for regulating public utilities doing business in Maryland MEGAWATT (MW) -one million watts of electricity, enough electricity to light 10,000 100-watt light bulbs for one hour NUCLEAR REGULATORY COMMISSION (NRC)-thef U.S. agency that regulates commercial nuclesr power planits and the civilian use of nuclear materials ORIGINATION-the initiation of wholesale energy purchases and sales that may include value-added services along with the energy PEA K LOAD-a measure of the maximum amount of electricity delivered at a point in time PORTFOLIO MANAGEMENT AND TRADING-uising 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 in order to earn additional returns REGIONAL TRANSMISSION ORGANIZATION (RTO)-a group of compariies with responsibility for the planning and use of power trans-mission lines in a geographic region REGULATED BUSINESS-the portion of our business whose primary operations and prices are set and controlled by the rules and activities of a state utility commission SECURITIES AND EXCHANGE COMMISSION (SEC)Q-the U.S. agency charged with protecting investors, maintaining fair, orderly and efficient markets, and facilitating capital formation STANDARD OFFER SERVICE-in Maryland, the obligation ofa utility-such as Baltimore Gas and Electric-to supply electricity to residential customers and to serve as the provider of last resort (POLR) for those customers who have not chosen an alternate supplier TOLLING CONTRACT-an agreement where a buyer pays a plant owner a fixed amount per month to have the right to convert fuel provided by the buyer into electric energy TRANSMISSION-the sending of electricity at high voltage, usually on lines running along high towers, from generating plants to substations, where it is then reduced to a lower voltage that is delivered to homes, businesses, and industrial facilities UNIT CONTINGENT POWER PURCHASE AGREEMENT-a contract with a power plant operator where the buyer receives the specified output from the plant unless the plant is not operating VALUE AT RISK-a statistical measure that helps evaluate risk by show-ing how much the value of the mark-to-market energy assets or liabilities may change under various circumstances 24

SHAREHOLDER INFORMATION DIVIDENDS The Board of Directors sets the record and payment dates for quar-terly dividends. In January 2007, we raised our quarterly dividend to 43.5 cents per share-a 15 percent increase over the previous quarterly dividend and equivalent to an annual dividend of $ 1.74 per share. We paid the new dividend on April 2, 2007, to shareholders of record on March 12, 2007. Projected record dates for the next three quarters are June 11, September 10, and December 10. Projected payment dates are July 2, October 1, and January 2.

Detailed information about our dividend policy, as well as our dividend payments and stock price ranges for the last two years, is available on page 27 of our 2006 Form 10-K included within this annual report.

CERTIFICATIONS As required by the Sarbanes-Oxley Act of 2002, we have filed the Chief Executive Officer and Chief Financial Officer certifications in our 2006 Form 10-K. Additionally, our Chief Executive Officer pro-vided an annual certification in December 2006 with respect to our compliance with the New York Stock Exchange corporate governance listing standards.

INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM PricewaterhouseCoopers LLP STOCK TRANSFER AGENT AND REGISTRAR American Stock Transfer & Trust Company Shareholder Services 59 Maiden Lane New York, NY 10038 (800) 258-0499 www.amstock.com SHAREHOLDER ASSISTANCE For general inquiries, or for assistance with lost or stolen stock certifi-cates or dividend checks, name or address changes, stock transfers, or the Shareholder Investment Plan, please contact our Stock Transfer Agent and Registrar.

SHAREHOLDER INVESTMENT PLAN Our Shareholder Investment Plan provides shareholders with an easy, economical way to acquire additional shares. In addition, accounts can be used to sell, deposit, and transfer shares. To participate, or for more information, please contact our Stock Transfer Agent and Registrar.

E-MAIL ALERTS To automatically receive e-mail alerts about our financial informa-tion-including notification of SEC filings, financial reports, presen-tations, and press releases-go to our E-mail Alerts page on the Inves-tor Relations section of our Web site at www.constellation.com and register your preferences. You can also make changes in your notifica-tion options or unsubscribe from the service.

FORM 10-K Our 2006 Form 10-K is included as part of this annual report. Our 2006 Form 10-K and our other SEC filings are available on our Web site at www.constellation.com. We will also provide additional cop-ies upon request. Send requests to Constellation Energy Shareholder Services, 750 East Pratt Street, Baltimore, MD 21202.

STOCK TRADING Constellation Energy common stock trades under the ticker symbol CEG on the New York and Chicago stock exchanges.

FORWARD-LOOKING STATEMENTS We make statements in this annual report that are considered forward-looking within the meaning of the Securities and Exchange Act of 1934. These statements are not guarantees of our future results and are subject to risks, uncertainties, and other important factors-including those in the Forward-Looking Statements and Risk Factors sections of our 2006 Form 10-K included within this annual report-that could cause our actual results to differ.

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Constellation Energy

.750 E. PRATT STREET, BALTIMORE, MD 21202-3106 WWW.CONSTELLATION.COM

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, 2006 Commission IRS Employer file number Exact name of registrant as specified in its charter IdentificationNo 1-12869 CONSTELLATION ENERGY GROUP, INC.

52-1964611 1-1910 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 Title of each class which registered Constellation Energy Group, Inc. Common Stock-Without Par Value New York Stock Exchange, Inc.

I Chicago Stock Exchange, Inc.

6.20% Trust Preferred Securities ($25 liquidation amount per preferred secutity) issued by BGE Capital Trust 11, NeYokSckEhagI.

fully and unconditionally guaranteed, based on several obligations, by Baltimore Gas and Electric Company I

e okSokEcagIc SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:

Not Applicable Indicate by check mark if Constellation Energy Group, Inc. is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes lE No 0l.

Indicate by check mark if Baltimore Gas and Electric Company is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes lHI No 0.

Indicate by check mark if Constellation Energy Group, Inc. is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes 0 No [El1.

Indicate by check mark if Baltimore Gas and Electric Company is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes 0 No [xl.

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months, and (2) have been subject to such filing requirements for the past 90 days. Yes El No 0.

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants' knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10O-K or any amendment to this Form 10O-K. MXI Indicate by check mark whether Constellation Energy Group, Inc. is a large accelerated filer, an accelerated filer, or a non-accelerated filer.

See definition of "accelerated filer" and "large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer [0 Accelerated filer 0 Non-accelerated filer 0 Indicate by check mark whether Baltimore Gas and Electric Company is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer" and "large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer 0 Accelerated filer 0 Non-accelerated filer 0 Indicate by check mark whether Constellation Energy Group, Inc. is a shell company (as defined in Rule 12b-2 of the Exchange Act) Yes 0 No Ox 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 0 No Mx Aggregate market value of Constellation Energy Group, Inc. Common Stock, without par value, held by non-affiliates as of June 30, 2006 was approximately $9,699,558,195 based upon New York Stock Exchange composite transaction closing price.

CONSTELLATION ENERGY GROUP, INC. COMMON STOCK, WITHOUT PAR VALUE 180,679,592 SHARES OUTSTANDING ON JANUARY 31, 2007.

DOCUMENTS INCORPORATED BY REFERENCE Part of Form 10-K Document Incorporated by Reference III Certain sections of the Proxy Statement for the 2007 Annual Meeting of Shareholders for Constellation Energy Group, Inc.

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

TABLE OF CONTENTS Page Forward Looking Statements 1..

PART I Item 1I Business.......................................................................

2 Overview..................................................................

2 Merchant Energy Business.....................................................

3 Baltimore Gas and Electric Company............................................

10 Other Nonregulated Businesses.................................................

15 Consolidated Capital Requirements.............................................

15 Environmental Matters.......................................................

15 Employees.................................................................

17 Item 1A -

Risk Factors....................................................................

18 Item 2 Properties.....................................................................

22 Item 3

-Legal Proceedings...............................................................

24 Item 4 Submission of Matters to Vote of Security Holders.....................................

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

25 PART 11 Item 5 Market for Registrant's Common Equity and Related Shareholder Matters...................

27 Item 6 Selected Financial Data...........................................................

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

30 Item 7A -

Quantitative and Qualitative Disclosures About Market Risk.............................

63 Item 8 Financial Statements and Supplementary Data.........................................

64 Item 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure....

121 Item 9A -

Controls and Procedures.........................................................

121 Item 9B Other Information..............................................................

121 PART III Item 10 Directors and Executive Officers of the Registrant......................................

122 Item 11I -

Executive Compensation.........................................................

122 Item 12 Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters......................................

I...............

122 Item 13 Certain Relationships and Related Transactions............................

I...........123 Item 14 Principal Accountant Fees and Services..............................................

123 PART IV Item 15 Exhibits and Financial Statement Schedules..........................................

123 Signatures...............................................................................

129

Forward Looking Statements We make statements in this report that are considered forward looking statements within the meaning of the Securities Exchange Act of 1934. Sometimes these statements will contain words such as "believes,"

"1anticipates," "expects," "in tends," "Plans," and other similar words. We also disclose non-historical information that represents management's expectations, which are based on numerous assumptions. These statements and projections are not guarantees of our future performance and are subject to risks, uncertainties, and other important factors that could cause our actual performance or achievements to be materially different from those we project. These risks, uncertainties, and factors include, but are not limited to:

• the timing and extent of changes in commodity prices and volatilities for energy and energy related products including coal, natural gas, oil, electricity, nuclear fuel, freight, and emission allowances,

• the liquidity and competitiveness of wholesale markets for energy commodities,

• the effect of weather and general economic and business conditions on energy supply, demand, and prices,

• the ability to attract and retain customers in our competitive supply activities and to adequately forecast their energy usage,

• the timing and extent of deregulation of, and competition in, the energy markets, and the rules and regulations adopted on a transitional basis in those markets,

• uncertainties associated with estimating natural gas reserves, developing properties, and extracting natural gas,

• regulatory or legislative developments that affect deregulation, transmission or distribution rates and revenues, demand for energy, or increases in costs, including costs related to nuclear power plants, safety, or environmental compliance,

• the inability of Baltimore Gas and Electric Company (BGE) to recover all its costs associated with providing customers service,

• the conditions of the capital markets, interest rates, availability of credit, liquidity, and general economic conditions, as well as Constellation Energy Group's (Constellation Energy) and BGE's ability to maintain their current credit

ratings,

• the effectiveness of Constellation Energy's and BGE's risk management policies and procedures and the ability and willingness of our counterparries to satisfy their financial and performance commitments,

• operational factors affecting commercial operations of our generating facilities (including nuclear facilities) and BGE's transmission and distribution facilities, including catastrophic weather-related damages, unscheduled outages or repairs, unanticipated changes in fuel costs or availability, unavailability of coal or gas transportation or electric transmission services, workforce issues, terrorism, liabilities associated with catastrophic events, and other events beyond our control,

• the actual outcome of uncertainties associated with assumptions and estimates using judgment when applying critical accounting policies and preparing financial statements, including factors that are estimated in determining the fair value of energy contracts, such as the ability to obtain market prices and, in the absence of verifiable market prices, the appropriateness of models and model inputs (including, but not limited to, estimated contractual load obligations, unit availability, forward commodity prices, interest rates, correlation and volatility factors),

• changes in accounting principles or practices,

• losses on the sale or write down of assets due to impairment events or changes in management intent with regard to either holding or selling certain assets,

• the ability to successfuilly identify and complete acquisitions and sales of businesses and assets, and

• cost and other effects of legal and administrative proceedings that may not be covered by insurance, including environmental liabilities.

Given these uncertainties, you should nor place undue reliance on these forward looking statements.

Please see the other sections of this report and our other periodic reports filed with the Securities and Exchange Commission (SEC) for more information on these factors. These forward looking statements represent our estimates and assumptions only as of the date of this report.

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

1

PART I Item 1. Business Overview Constellation Energy is an energy company that includes a merchant energy business and BGE, a regulated electric and gas public utility in central Maryland.

Constellation Energy was incorporated in Maryland on September 25, 1995. On April 30, 1999, Constellation Energy became the holding company for BGE and its subsidiaries. References in this report to "we" and "our" are to Constellation Energy and its subsidiaries, collectively. References in this report to the "regulated business(es)" are to BGE.

Our merchant energy business is a competitive provider of energy solutions for a variety of customers. It has electric generation assets located in various regions of the United States and provides energy solutions to meet customers' needs. Our merchant energy business focuses on serving the energy and capacity requirements (load-serving) of, and providing other energy products and risk management services, for various customers.

Our merchant energy business includes:

+ a generation operation that owns, operates, and maintains fossil, nuclear, and hydroelectric generating facilities and holds interests in qualifying facilities, fuel processing facilities and power projects in the United States,

+ a wholesale marketing, risk management, and trading operation that primarily provides energy products and services to distribution utilities, power generators, and other wholesale customers,

+ an electric and natural gas retail operation that provides energy products and services to commercial, industrial, and governmental customers, and

+ a generation operations and maintenance services operation.

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

Our other nonregulated businesses:

• design, construct, and operate heating, cooling, and cogeneration facilities, and provide various energy-related services, including energy consulting, for commercial, industrial, and governmental customers throughout North America, and

• provide home improvements, service heating, air conditioning, plumbing, electrical, and indoor air quality systems, and provide natural gas to residential customers in central Maryland.

On October 24, 2006, Constellation Energy and FPL Group, Inc. (FPL Group) agreed to terminate the Agreement and Plan of Merger the parties entered into on December 18, 2005. For additional information related to the merger termination, see Note 15 to Consolidated Financial Statements. For a discussion of other recent events that have impacted us, our strategy, and the seasonality of our business, please refer to Item 7.

Management's Discussion andAnalysis section.

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

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

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

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

2006 2005 2004 2006 2005 2004 Unaffiliated Revenues Merchant Regulated Regulated Other Energy Electric Gas Nonregulated 83%

11%

5%

1%

81 12 6

1 76 16 6

2 Net Income Merchant Regulated Regulated Other Energy Electric Gas Nonregulated 77%

16%

5%

2%

67 28 5

72 26 5

(3) 2

2006 2005 2004 Total Assets Merchant Reulated Regulated Other Energy aectric Gas Nonregulated 75%

17%

6%

2%

77 16 6

1 71 20 7

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

(1)

Excludes income from discontinued operations in 2006, 2005 and 2004 and cumulative effects of changes in accounting principles in 2005 as discussed in more detail in Item 8. Financial Statements and Supplementary Data.

Merchant Energy Business Introduction Our merchant energy business integrates electric generation assets with the marketing and risk management of energy and energy-related commodities, allowing us to manage energy price risk over geographic regions and time.

Constellation Energy Commodities Group, our wholesale marketing, risk management, and trading operation, dispatches the energy from our generating facilities and from some facilities with which we have power purchase agreements, manages the risks associated with selling the output and purchasing non-nuclear fuels, and enters into transactions to meet customers' energy and risk management requirements. This operation also trades energy and energy-related commodities and deploys risk capital in the management of our portfolio in order to earn additional returns. Constellation NewEnergy, our electric and gas retail operation, provides electricity, natural gas, transportation, and other energy services to commercial, industrial, and governmental customers.

Constellation Generation Group, our merchant generation operation, oversees the ownership, operations, maintenance, and performance of our fossil, nuclear and renewable generation and fuel processing facilities. Our generation capacity supports our wholesale and retail operations by providing a source of reliable power supply. Constellation Generation Group also owns and operates a generation operations and maintenance services organization.

Our merchant energy business:

• provided approximately 34,650 megawatts (MW) of peak load in the aggregate to distribution utilities, municipalities, commercial, industrial, and governmental customers during 2006,

• provided approximately 355,000 million British Thermal Units (mmBTUs) of natural gas to commercial, industrial, and governmental customers during 2006,

+ delivered 26.0 million tons of coal to international and domestic third-party customers and to our own fleet during 2006, and

• managed approximately 8,680 MW of generation capacity as of December 31, 2006.

We analyze the results of our merchant energy business as follows:

• Mid-Atlantic Region--our fossil, nuclear, and hydroelectric generating facilities and load-serving activities in the PJM Interconnection (PJM) region. This also includes active portfolio management of generating assets and other physical and financial contractual arrangements, as well as other PJM competitive supply activities. In addition, due to the expiration of its power purchase agreement, beginning in June 2006 until its sale in December 2006, the results of our University Park generating facility are included with the Mid-Atlantic Region.

University Park was previously included in Plants with Power Purchase Agreements.

• Plants with Power Purchase Agreements-our generating facilities outside the Mid-Atlantic Region with long-term power purchase agreements. As discussed in Note 2 to Consolidated Financial Statements, the sale of the High Desert facility resulted in a reclassification of its results to discontinued operations.

• Wholesale Competitive Supply-our marketing, risk management, and trading operation that provides energy products and services primarily to distribution utilities, power generators, and other wholesale customers. We also provide global energy and related services and upstream and downstream natural gas services.

• Retail Competitive Supply--our operation that provides electric and natural gas energy products and services to commercial, industrial, and governmental customers.

• Other-our investments in qualifying facilities and domestic power projects and our generation operations and maintenance services.

In December 2006, we completed the sale of the following gas-fired plants owned by our merchant energy business:

Facility High Desert...

Rio Nogales...

Holland......

University Park Big Sandy....

Wolf Hills....

Capacity (MW)

Unit Type Location 830 Combined Cycle California 800 Combined Cycle Texas 665 Combined Cycle Illinois 300 Peaking Illinois 300 Peaking West Virginia 250 Peaking Virginia 3

We discuss the sale of these gas-fired generating facilities in Note 2 to Consolidated Financial Statements.

We present details about our generating properties in Item 2. Properties.

Mid-Atlantic Region We own 6,305 MW of fossil, nuclear, and hydroelectric generation capacity in the Mid-Atlantic Region. The output of these plants is managed by our wholesale marketing, risk management, and trading operation and is hedged through a combination of power sales to wholesale and retail market participants. Our merchant energy business meets the load-serving requirements of various contracts using the output from the Mid-Atlantic Region and from purchases in the wholesale market.

BGE transferred all of these facilities to our merchant energy generation subsidiaries on July 1, 2000 as a result of the implementation of electric customer choice and competition among suppliers in Maryland, except for the Handsome Lake facility that commenced operations in mid-2001. The assets transferred from BGE are subject to the lien of BGE's mortgage.

Our merchant energy business supplies BGE with a portion of its market-based standard offer service obligation. For 2006, the peak load supplied to BGE was approximately 3,490 MW.

Plants with Power Purchase Agreements We own 2,134 MW of nuclear generation capacity with power purchase agreements for a significant portion of their output. Our facilities with power purchase agreements are the Nine Mile Point Nuclear Station (Nine Mile Point) and the R.E. Ginna Nuclear Plant (Ginna).

We own 100% of Nine Mile Point Unit 1 (620 MW) and 82% of Unit 2 (933 MW). The remaining interest in Nine Mile Point Unit 2 is owned by the Long Island Power Authority. Unit 1 entered service in 1969 and Unit 2 in 1988. Nine Mile Point is located within the New York Independent System Operator (NYISO) region.

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

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

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

In October 2006, we received Nuclear Regulatory Commission (NRC) approval for license extension for both units at our Nine Mile Point nuclear facility. With the renewed licenses, we can continue to operate Unit 1 until 2029 and Unit 2 until 2046.

We own 100% of the Ginna nuclear facility.

Ginna consists of a 581 MW reactor that entered service in 1970 and is licensed to operate until 2029. We sell up to 90% of the plant's output and capacity to the former owners for 10 years at an average price of $44.00 per MWH under a long term unit contingent power purchase agreement. The remaining output is managed by our wholesale marketing, risk management, and trading operation and sold into the wholesale market.

During the fourth quarter of 2006, we completed a planned outage at our Ginna nuclear facility, which included increasing the capacity of the plant from 498 MW to the current 581 MW. Based on the new capacity, beginning in 2007, we will sell approximately 80% of Ginna's output to the former owners.

Competitive Supply We are a leading supplier of energy products and services to wholesale customers and retail commercial, industrial, and governmental customers. In 2006, our wholesale marketing, risk management, and trading operation provided approximately 17,950 peak MWs of wholesale full requirements load-serving products.

During 2006, our retail competitive supply activities served approximately 16,700 MW of peak load and approximately 355,000 mmBTUs of natural gas.

Wholesale and Retail Load-Serving Actiities Our wholesale marketing, risk management, and trading operation structures transactions that serve the full energy and capacity requirements of various customers outside the PJM region such as distribution utilities, municipalities, cooperatives, and retail aggregators that do not own sufficient generating capacity or in-house supply functions to meet their own load requirements.

4

Our retail competitive supply operation structures transactions to supply full energy and capacity requirements and provide natural gas, transportation, and other energy products and services to retail, commercial, industrial, and governmental customers.

Contracts with these customers generally extend from one to ten years, but some can be longer. To meet our customers' load-serving requirements, our merchant energy business obtains energy from various sources, including:

• bilateral power and natural gas purchase agreements with third parties,

• unit contingent purchases from generation companies,

• our generation assets,

• regional power pools,

• tolling contracts with generation companies, which provide us the right, but not the obligation, to purchase power at a price linked to the variable cost of production, including fuel, with terms that generally extend from several months to several years, but can be longer, and

+ exchange traded electricity and natural gas contracts.

Portfolio Management and Trading We continue to identify and pursue opportunities which can generate additional returns through portfolio management and trading activities within our business.

These opportunities have increased due to the significant growth in scale of our competitive supply operations. In managing our portfolio, we may terminate, restructure, or acquire contracts. Such transactions are within the normal course of managing our portfolio and may materially impact the timing of our recognition of revenues, fuel and purchased energy expenses, and cash flows.

Our wholesale marketing, risk management, and trading operation actively uses energy and energy-related commodities in order to manage our portfolio of energy purchases and sales to customers through structured transactions. We use both derivative and nonderivative contracts in managing our portfolio of energy sales and purchase contracts. Generally, we expect to use both derivative and nonderivative contracts to hedge a majority of our portfolio over a three-year period in order to reduce volatility in our results. Although a substantial portion of our portfolio is hedged, we are able to identify opportunities to deploy risk capital to increase the value of our accrual positions, which we characterize as portfolio management.

We trade energy and energy-related commodities and deploy risk capital in the management of our portfolio in order to earn additional returns. These activities are managed through daily value at risk and stop loss limits and liquidity guidelines, and could have a material impact on our financial results. We discuss the impact of our trading activities and value at risk in more detail in Item 7. Management's Discussion and Analysis.

These activities involve the use of a variety of instruments, including:

• forward contracts (which commit us to purchase or sell energy commodities in the future),

• swap agreements (which require payments to or from counterparties based upon the difference between two prices for a predetermined contractual (notional) quantity),

• option contracts (which convey the right to buy or sell a commodity, financial instrument, or index at a predetermined price), and

• futures contracts (which are exchange traded standardized commitments to purchase or sell a commodity or financial instrument, or make a cash settlement, at a specified price and future date).

Active portfolio management allows our wholesale marketing, risk management, and trading operation to:

• manage and hedge its fixed-price energy purchase and sale commitments,

• provide fixed-price energy commitments to customers and suppliers,

• reduce exposure to the volatility of market Prices, and

• hedge fuel requirements at our non-nuclear generation facilities.

Coal and International Services Our wholesale marketing, risk management, and trading operation participates in global coal sourcing activities by providing coal and coal-related logistical services, for the variable or fixed supply needs of global customers. In 2006, we delivered 26.0 million tons of c~oal to global customers and to our own fleet. Additionally, we entered into power, natural gas, freight, and emissions transactions outside of the United States. We also include in our coal services the results from our synthetic fuel processing facility in South Carolina.

We will continue to evaluate new international opportunities, including expanding our coal sourcing, freight, and power, natural gas and emissions activities outside of the United States.

Natural Gas Services Our wholesale marketing, risk management, and trading operation includes upstream (exploration and production) and downstream (transportation and storage) natural gas operations. Our upstream activities include the acquisition, development, and exploitation of natural gas properties. Our downstream activities include providing natural gas to various customers, including large utilities, industrial customers, power generators, wholesale marketers, and retail aggregators.

5

In 2006 and 2005, we acquired working interests in gas producing fields. We discuss these acquisitions in more detail in Note 15 to Consolidated Financial Statements.

In November 2006, we completed the initial public offering of Constellation Energy Partners LLC (CEP), a limited liability company that we formed. CEP is principally engaged in the acquisition, development, and exploitation of natural gas properties. CEP's existing property is located in the Robinson's Bend Field in the Black Warrior Basin of Alabama. We continue to own 54% of CEP and as a result, we continue to consolidate CEP. We discuss the impact of this initial public offering on our financial results in more detail in Note 2 to Consolidated Financial Statements.

Other We hold up to a 50% voting interest in 24 operating energy projects that consist of electric generation (primarily relying on alternative fuel sources), fuel processing, or fuel handling facilities. These generating projects are considered qualifying facilities under the Public Utility Regulatory Policies Act of 1978. Each electric generating plant sells its output to a local utility under long-term contracts.

We also provide operation and maintenance services, including testing and start-up, to owners of electric generating facilities.

UniStar Nuclear In 2005, we formed UniStar Nuclear, LLC (UniStar), a joint enterprise with AREVA NP, Inc., to develop the business model for a standardized fleet of nuclear power plants based on an advanced design called the U.S.

Evolutionary Power Reactor (U.S. EPR). UniStar provides the framework through which we can work with AREVA NP, Inc. to obtain design certification and all necessary approvals from the NRC to license, construct, own, and operate U.S. EPR plants.

UniStar also offers the business framework that could enable the development of future joint ventures with Constellation Energy, other energy companies, and interested parties. Those future joint ventures, in turn, would license, construct, own, and operate nuclear power plants as part of a standardized fleet. However, prior to identifying specific projects or committing to ordering new nuclear power plants, our financial commitment will be limited to the formation of the business platform and business development activities, including licensing and permit activities and securing access to long-lead materials such as heavy forgings needed for reactor pressure vessels and steam generators or turbine and generator parts.

Fuel Sources Our power plants use diverse fuel sources. Our fuel mix based on capacity owned at December 31, 2006 and our generation based on actual output by fuel type in 2006 were as follows:

Fuel Capacity Owned Generation*

Nuclear..........

45%

52%

Coal............

32 30 Natural Gas......

7 15 O il.............

8 Renewable and Alternative ')...

5 3

Dual *..........

3 Includes outputfrom gas-firedplants until sale in December 2006 (1)

Includes solar, geothermal, hydro, waste coal and biomass.

(2)

Switches between natural gas and oil.

We discuss our risks associated with fuel in more detail in Item 7. Managements Discussion and Analysis-Market Risk.

Nuclear The output at our nuclear facilities over the past five years (including periods prior to our acquisition of Ginna in June 2004) is presented in the following table:

Calvert Cliffs Nine Mile Point Ginna Capacity Capacity Capacity MWH Factor MWVH*

Factor MWH Factor (MWH in millions) 2006 13.8 90%

12.8 93%

4.1 93%

2005 14.7 97 12.7 93 4.0 93 2004 14.5 96 12.1 89 4.3 100 2003 13.7 93 12.2 90 3.9 90 2002 12.1 82 11.7 87 3.8 89

• represents our proportionate ownership interest The supply of fuel for nuclear generating stations includes the:

• purchase of uranium (concentrates and uranium hexafluoride),

• conversion of uranium concentrates to uranium hexafluoride,

• enrichment of uranium hexafluoride, and

• fabrication of nuclear fuel assemblies.

Uranium and We have commitments for sufficient Conversion quantities of uranium (concentrates and uranium hexafluoride) to meet 100% of our total requirements through 2010. Additionally, we have commitments covering approximately 95% of our requirements in 2011.

6

Enrichment We have commitments that provide 100% of our uranium enrichment requirements through 2010 and 75%

of these requirements in 2011 and 2012. We have commitments that provide 50% of our uranium enrichment requirements from 2013 through 2020.

Fuel Assembly We have commitments for the Fabrication fabrication of fuel assemblies for reloads required through 2013 for Nine Mile Point and Calvert Cliffs Nuclear Power Plant, Inc. (Calvert Cliffs), and through 2017 for Ginna.

The nuclear fuel markets are competitive, and although prices for uranium and conversion are increasing, we do not anticipate any significant problems in meeting our future requirements.

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

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

The DOE has stated that it may not meet that obligation until 2017 at the earliest. This delay has required that we undertake additional actions to provide on-site fuel storage at Calvert Cliffs, Ginna, and Nine Mile Point, including the installation of on-site dry fuel storage capacity at Calvert Cliffs, as described in more detail below. In 2004, complaints were filed against the federal government in the United States Court of Federal Claims seeking to recover damages caused by the DOE's failure to meet its contractual obligation to begin disposing of spent nuclear fuel by January 31, 1998.

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

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

Storafe ofSpent Nuclear Fuel-On-Site Facilities Calvert Cliffs has a license from the NRC to operate an on-site independent spent fuel storage installation that expires in 2012. We have storage capacity at Calvert Cliffs that will accommodate spent fuel from operations through 2011. In addition, we can expand our temporary storage capacity at Calvert Cliffs to meet future requirements until approximately 2025. Nine Mile Point and Ginna are beginning initial planning studies for the potential development of independent spent fuel storage capacity. Nine Mile Point's Unit 1 has sufficient storage capacity within the plant until 2011.

Nine Mile Point's Unit 2 has sufficient storage capacity within the plant until 2012. Ginna has sufficient storage capacity within the plant until 2010.

Cost for Decommissioning Uranium Enrichment Facilities The Energy Policy Act of 1992 requires domestic nuclear utilities to contribute to a fund for decommissioning and decontaminating uranium enrichment facilities that had been operated by DOE.

These contributions are generally payable over a 15-year period with escalation for inflation and are based upon the amount of uranium enriched by DOE for each utility through 1992. The 1992 Act provides that these costs are recoverable through utility service rates. BGE is solely responsible for these costs as they relate to Calvert Cliffs and made the last payment in 2006. The sellers of the Nine Mile Point plant and the Long Island Power Authority are responsible for the costs relating to the Nine Mile Point plant. The seller of Ginna is responsible for the costs related to that facility.

Cost for Decommissionin' We are obligated to decommission our nuclear plants at the time these plants cease operation. Every two years, the NRC requires us to demonstrate reasonable assurance that funds will be available to decommission the sites. When BGE transferred all of its nuclear generating assets to our merchant energy business, it also transferred the trust fund established to pay for decommissioning Calvert Cliffs. At December 31, 2006, the Calvert Cliffs trust fund assets were $420.6 million.

Under the Maryland Public Service Commission's (Maryland PSC) order regarding the deregulation of electric generation, BGE ratepayers must pay a total of

$520 million, in 1993 dollars adjusted for inflation, to decommission Calvert Cliffs through fixed annual collections. In 2006, BGE received approval from the Maryland PSC to continue annual customer collections of approximately $18.7 million through December 31, 2016. BGE will be required to submit a filing to determine the level of customer contributions after December 31, 2016.

7

BGE is collecting this amount on behalf of Calvert Cliffs. Any costs to decommission Calvert Cliffs in excess of this $520 million must be paid by Calvert Cliffs. If BGE ratepayers have paid more than this amount at the time of decommissioning, Calvert Cliffs must refund the excess. If the cost to decommission Calvert Cliffs is less than the $520 million BGE's ratepayers are obligated to pay, Calvert Cliffs may keep the difference.

As discussed in Baltimore Gas and Electric Company--Provider ofLast Resort section, Senate Bill 1, which was enacted in June 2006, requires BGE to provide credits to residential electric customers equal to the amount collected for decommissioning annually for 10 years beginning January 1, 2007. Under the provisions of Senate Bill I we are required to apply the collection of the nuclear decommissioning trust funds over the ten year period beginning January 1, 2007 toward the fulfillment of the decommissioning obligations of BGE ratepayers.

The sellers of Nine Mile Point transferred a

$441.7 million decommissioning trust fund to us at the time of sale. In return, we assumed all liability for the costs to decommission Unit 1 and 82% of the costs to decommission Unit 2. We believe that this amount is adequate to cover our responsibility for decommissioning Nine Mile Point to a greenfield status (restoration of the site so that it substantially matches the natural state of the surrounding properties and the site's intended use). At December 31, 2006, the Nine Mile Point trust fund assets were $572.8 million.

The seller of Ginna transferred $200.8 million in decommissioning funds to us. In return, we assumed all liability for the costs to decommission the unit. We believe that this amount will be sufficient to cover our responsibility for decommissioning Ginna to a greenfield status. At December 31, 2006, the Ginna trust fund assets were $246.7 million.

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

Approximate Annual Coal Requirement Special Coal (tons)

Restrictions Brandon Shores 3,500,000 Sulfur content less Units 1 and 2 than 1.20 lbs per (combined) mmBTU C. P. Crane 850,000 Low ash melting Units 1 and 2 temperature Coal deliveries to these facilities are made by rail and barge. Over the past few years, we expanded our coal sources including restructuring our rail contracts, increasing the range of coals we can consume, adding synthetic fuel as an alternate source, and finding potential other coal supply sources including shipments from various international sources. While we primarily use coal produced from mines located in central and northern Appalachia, we are capable of switching to imported coals to manage our coal supply. The timely delivery of coal together with the maintenance of appropriate levels of inventory is necessary to allow for continued, reliable generation from these facilities.

All of the Conemaugh and Keystone plants' annual coal requirements are purchased by the plant operators from regional suppliers on the open market. The sulfur restrictions on coal are approximately 2.3% for the Keystone plant and approximately 5.3% for the Conemaugh plant.

The annual coal requirements for the ACE, Jasmin, and Poso plants, which are located in California, are supplied under contracts with mining operators. The Jasmin and Poso plants are restricted to coal with sulfur content less than 4.0% and ACE is restricted to less than 2.0%.

All of our coal requirements reflect historical levels.

The actual fuel quantities required can vary substantially from historical levels depending upon the relationship between energy prices and fuel costs, weather conditions, and operating requirements.

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

Oil Under normal burn practices, our requirements for residual fuel oil (No. 6) amount to approximately 1.5 million to 2.0 million barrels of low-sulfur oil per year. Deliveries of residual fuel oil are made from the suppliers' Baltimore Harbor and Philadelphia marine terminals for distribution to the various generating plant locations. Also, based on normal burn practices, we require approximately 8.0 million to 11.0 million gallons of distillates (No. 2 oil and kerosene) annually, but these requirements can vary substantially from year (combined)

H. A. Wagner Units 2 and 3 (combined) 1,100,000 Sulfur content no more than 1%

8

to year depending upon the relationship between energy prices and fuel costs, weather conditions, and operating requirements. Distillates are purchased from the suppliers' Baltimore truck terminals for distribution to the various generating plant locations. We have contracts with various suppliers to purchase oil at spot prices, and for future delivery, to meet our requirements.

Competition Market developments over the past several years have changed the nature of competition in the merchant energy business. Certain companies within the merchant energy sector have curtailed their activities or withdrawn completely from the business. However, new competitors (e.g., financial investors, banks and investment banks) have entered the market. We encounter competition from companies of various sizes, having varying levels of experience, financial and human resources, and differing strategies.

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

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

States are considering different types of regulatory initiatives concerning competition in the power industry, which makes a competitive assessment difficult. Increased competition that resulted from some of these initiatives in several states contributed in some instances to a reduction in electricity prices and put pressure on electric utilities to lower their costs, including the cost of purchased electricity. While many states continue to support retail competition and industry restructuring, other states that were considering deregulation have slowed their plans or postponed consideration of deregulation. In addition, other states are reconsidering deregulation.

We believe there is adequate growth potential in the current deregulated market and that further market changes could provide additional opportunities for our merchant energy business. In addition, our wholesale marketing, risk management, and trading operation participates in global coal sourcing activities by providing coal for the variable or fixed supply needs of North American and international power generators. In addition, our wholesale marketing, risk management, and trading operation includes upstream (exploitation and production) and downstream (transportation and storage) natural gas operations.

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

Merchant Energy Operating Statistics 2006 2005 2004 2003 2002 Revenues (In millions)

Mid-Atlantic Region

$ 2,813.5

$ 2,283.9

$ 1,925.6

$1,696.2

$1,415.1 Plants with Power Purchase Agreements 650.5 665.9 555.3 463.3 433.2 Competitive Supply-Retail 8,014.7 6,942.3 4,280.0 2,567.7 312.7 Competitive Supply-Wholesale 5,612.7 4,672.3 3,353.8 2,703.9 540.7 Other 74.8 58.0 73.6 45.1 56.4 Total Revenues

$17,166.2

$14,622.4

$10,188.3

$7,476.2

$2,758.1 Generation (In millions)--MWH*

59.1 60.2 55.3 51.6 44.7

• Includes output from gas-firedplants until sale in December 2006.

Operating statistics do not reflect the elimination of intercompany transactions.

Certain prior-year amounts have been reclassified to conform with the current year ' presentation. The reclassifications primarily relate to operations that have been reflected as discontinued in the current year.

9

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

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

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

Electric Business Electric Regulatory Matters and Competition Deregulation Effective July 1, 2000, electric customer choice and competition among electric suppliers was implemented in Maryland. As a result of the deregulation of electric generation, all customers can choose their electric energy supplier. While BGE does not sell electric commodity to all customers in its service territory, BGE continues to deliver electricity to all customers and provides meter reading, billing, emergency response, and regular maintenance.

Standard Offier Service BGE provided fixed-price standard offer service to commercial and industrial customers through either June 30, 2002 or June 30, 2004, depending on customer type, and for residential customers through June 30, 2006.

Upon the expiration of fixed-price standard offer service, customers that continue to receive their electric supply from BGE are charged market-based standard offer service rates (Provider of Last Resort rates). We discuss Provider of Last Resort (POLR) rates in more detail below.

Provider of Last Resort BGE is obligated to provide market-based standard offer service to all of its electric customers for varying periods. The POLR rates charged recover BGE's wholesale power supply costs and include an administrative fee. The administrative fee includes a shareholder return component and an incremental cost component. As a result of Senate Bill 1, beginning January 1, 2007, the shareholder return component of the administrative charge for residential POLR service was suspended. We discuss Senate Bill 1 in detail in the Residential Customers section.

Bidding to supply BGE's market-based standard offer service will occur from time to time through a competitive bidding process approved by the Maryland PSC. Successful bidders, which may include subsidiaries of Constellation Energy, will execute contracts with BGE for varying terms.

Commercial and Industrial Customers BGE is obligated to provide market-based standard offer service to commercial and industrial customers for varying periods beyond June 30, 2004, depending on customer load.

In August 2006, the Maryland PSC issued an order indefinitely extending the obligation of Maryland utilities to provide POLR 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 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.

Residential Customers As a result of the November 1999 Maryland PSC order regarding the deregulation of electric generation in Maryland, BGE's residential electric base rates were frozen until July 2006. Subsequent orders of the Maryland PSC specified that BGE would procure the power to serve residential customers beginning July 2006 via auctions to be conducted in late 2005 and early 2006. The procured power costs of these auctions would have resulted in an average electric residential customer bill increase of 72%. In June 2006, Senate Bill 1 was enacted, which, among other things:

+ imposes rate stabilization measures that (i) cap rate increases by BGE for residential POLR service at 15% from July 1, 2006 to May 31, 2007, (ii) give residential POLR customers the option from June 1, 2007 until December 31, 2007 of paying a full market rate or choosing a short term rate stabilization plan in order to provide a smooth transition to market rates without adversely affecting the creditworthiness of BGE, and (iii) provide for full market rates for residential POLR service starting January 1, 2008;

• allows BGE to recover the costs deferred from July 1, 2006 to May 31, 2007 from its customers over a period not to exceed 10 years, on terms and conditions to be determined by the Maryland PSC, including through the issuance of rate stabilization bonds that securitize the deferred costs; 10

• directs the Maryland PSC to investigate measures to mitigate the impact of residential rate increases on BGE customers, including by investigating the prior determination of and allowances for stranded costs that occurred when BGE transferred assets to its affiliates in 2000 and by requiring the Maryland PSC to provide funds to residential customers of BGE for mitigation of BGE's rate increases, including any adjustment in favor of BGE's customers to allowances for such stranded costs; and

1. requires BGE to reduce residential electric rates by approximately $39 million per year for 10 years, beginning January 1, 2007, through suspension of the collection of the residential return component of the administrative charge for POLR service and a credit equal to the amount collected from BGE ratepayers for the nuclear decommissioning trust for Calvert Cliffs. We provide further details in the Cost for Decommissioning section.

In August 2006, the Maryland PSC began its investigation into the general regulatory structure, agreements, orders, and other prior actions of the Maryland PSC under the Electric Customer Choice and Competition Act of 1999, including the determination of and allowances for stranded costs.

We cannot predict the outcome of the investigation, but it could have a material adverse effect on our, or BGE's, financial results.

In December 2006, the Maryland PSC issued an order that allows BGE to securitize its costs relating to the residential rate deferral through the issuance of bonds in an aggregate principal amount of approximately $630 million, subject to adjustment.

Also in December 2006, in connection with implementing the $39 million in annual residential electric rate reductions discussed above, BGE and Calvert Cliffs notified the Maryland PSC that they had entered into a standstill agreement with the Attorney General of the State of Maryland with respect to potential challenges to the provisions of Senate Bill 1 relating to the reductions.

In January 2007, BGE filed a proposed plan with the Maryland PSC that would allow residential electric customers to defer the transition to full market rates from June 1, 2007 to December 31, 2007. Under the proposed plan, electric rates for residential customers who elect this extended deferral would increase on June 1, 2007 by one-half of the total increase remaining to reach full market rates on January 1, 2008. We estimate that electric rates for residential electric customers under this plan will be approximately 20-25% higher on June 1, 2007 compared to current residential electric rates. This estimate may differ from the actual increase on June 1, 2007 based on BGE's actual procured power cost, which will be determined in April 2007 via auctions.

Customers who choose to defer would repay the deferred amounts over a two-year period starting January 1, 2008, at which time these customers would transition to full market rates. The proposed plan remains subject to Maryland PSC approval.

Because Senate Bill 1 requires additional decisions and proceedings by the Maryland PSC and other governmental authorities to implement and interpret many of its provisions, we cannot predict the ultimate impact of the legislation on us, BGE, or the energy market in Maryland. The new legislation and its implementation through applicable regulatory proceedings could have a material adverse effect on our, or BGE's, financial results. In addition, one or more parties may challenge in court one or more provisions of Senate Bill 1. The outcome of any challenges and the uncertainty that could result cannot be predicted.

We discuss other aspects of Senate Bill 1 in Item 7. Management's Discussion andAnalysis-Business Environment-Senate Bill I section. We discuss the market risk of our regulated electric business in more detail in Item 7. Management's Discussion and Analysis-Market Risk section.

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

We refer to these programs as active load management programs. These programs include:

• two options for commercial and industrial customers to voluntarily reduce their electric

loads,

• air conditioning control for residential and commercial customers, and

+ residential water heater control.

These programs generally take effect on summer days when demand and/or wholesale prices are relatively high and had the capability during the 2006 summer to reduce load up to approximately 233 MW.

Transmission and Distribution Facilities BGE maintains approximately 250 substations and 1,300 circuit miles of transmission lines throughout central Maryland. BGE also maintains approximately 23,900 circuit miles of distribution lines. The transmission facilities are connected to those of neighboring utility systems as part of PJM. Under the PJM Tariff and various agreements, BGE and other market participants can use regional transmission facilities for energy, capacity, and ancillary services transactions including emergency assistance.

We discuss various FERC initiatives relating to wholesale electric markets in more detail in Item 7.

Management's Discussion and Analysis-Federal Regulation section.

11

Electric Operating Statistics 2006 2005 2004 2003 2002 Revenues (In millions)

Residential

$1,092.1

$1,066.6

$1,015.8

$ 959.0

$ 946.6 Commercial Excluding Delivery Service Only 733.4 722.1 708.9 694.2 776.0 Delivery Service Only 149.4 107.5 78.6 66.1 33.5 Industrial Excluding Delivery Service Only 46.8 52.8 92.3 137.0 158.7 Delivery Service Only 26.2 28.0 21.3 18.2 10.9 System Sales and Deliveries 2,047.9 1,977.0 1,916.9 1,874.5 1,925.7 Other (A) 68.0 59.5 50.8 47.1 40.3 Total

$2,115.9

$2,036.5

$1,967.7

$1,921.6

$1,966.0 Distribution Volumes (In thousands)-MWH Residential 12,886 13,762 13,313 12,754 12,652 Commercial Excluding Delivery Service Only 6,325 7,847 9,286 9,937 11,840 Delivery Service Only 9,392 7,967 5,767 4,982 2,762 Industrial Excluding Delivery Service Only 467 614 1,429 2,556 3,478 Delivery Service Only 2,988 3,122 2,562 1,780 997 Total 32,058 33,312 32,357 32,009 31,729 Customers (In thousands)

Residential 1,093.3 1,084.1 1,072.1 1,061.7 1,052.3 Commercial 115.5 114.7 113.6 112.1 110.8 Industrial 5.2 5.0 4.8 4.9 4.9 Total 1,214.0 1,203.8 1,190.5 1,178.7 1,168.0 (A) Primarily includes network integration transmission service revenues, late payment charges, miscellaneous service fees, and tower leasing revenues.

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

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

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

In December 2005, the Maryland PSC issued an order granting BGE a $35.6 million annual increase in its'gas base rates. In December 2006, the Baltimore City Circuit Court upheld the rate order. However, certain parties have filed an appeal with the Court of Special Appeals. We cannot provide assurance that the Maryland PSC's order will not be reversed in whole or in part or that certain issues will not be remanded to the Maryland PSC for reconsideration.

For customers that buy their gas from BGE, there is a market-based rates incentive mechanism. Under this market-based rates incentive mechanism, our actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between our actual cost and the market index is shared equally between shareholders and customers. BGE must secure fixed-price contracts for at least 10%, but not more than 20%, of forecasted system supply requirements for the November through March period.

These fixed-price contracts are not subject to sharing under the market-based rates incentive mechanism.

BGE purchases the natural gas it resells to customers directly from many producers and marketers.

BGE has transportation and storage agreements that expire from 2007 to 2028.

BGE's current pipeline firm transportation entitlements to serve BGE's firm loads are 313,053 dekatherms (DTH) per day.

BGE's current maximum storage entitlements are 235,080 DTH per day. To supplement its gas supply at times of heavy winter demands and to be available in temporary emergencies affecting gas supply, BGE has:

• a liquefied natural gas facility for the liquefaction and storage of natural gas with a total storage capacity of 1,092,977 DTH and a daily capacity of 311,500 DTH, and

• a propane air facility with a mined cavern with a total storage capacity equivalent to 564,200 DTH and a daily capacity of 85,000 DTH.

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

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

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

13

Gas Operating Statistics 2006 2005 2004 2003 2002 Revenues (In millions)

Residential Excluding Delivery Service Only 490.2 558.5 478.0 444.5 342.1 Delivery Service Only 20.6 23.2 14.2 13.6 16.5 Commercial Excluding Delivery Service Only 148.9 174.4 135.4 128.6 89.4 Delivery Service Only 35.9 31.9 28.0 24.6 29.2 Industrial Excluding Delivery Service Only 7.5 10.5 9.4 11.5 9.3 Delivery Service Only 19.3 12.4 7.8 11.4 13.9 System Sales and Deliveries 722.4 810.9 672.8 634.2 500.4 Off-System Sales 168.6 154.7 77.2 84.8 74.8 Other 8.5 7.2 7.0 7.0 6.1 Total 899.5 972.8 757.0 726.0 581.3 Distribution Volumes (In thousands)-DTH Residential Excluding Delivery Service Only 33,019 39,107 39,080 40,894 35,364 Delivery Service Only 3,948 5,423 6,053 6,640 6,404 Commercial Excluding Delivery Service Only 11,683 14,133 13,248 13,895 11,583 Delivery Service Only 25,695 28,993 34,120 29,138 28,429 Industrial Excluding Delivery Service Only 604 921 865 1,143 1,207 Delivery Service Only 20,325 19,357 14,310 18,399 23,689 System Sales and Deliveries 95,274 107,934 107,676 110,109 106,676 Off-System Sales 19,738 17,209 9,914 12,859 18,551 Total 115,012 125,143 117,590 122,968 125,227 Customers (In thousands)

Residential 597.1 590.9 582.0 575.2 567.3 Commercial 42.3 42.0 41.6 41.1 40.7 Industrial 1.2 1.2 1.2 1.2 1.3 Total 640.6 634.1 624.8 617.5 609.3 Operating statistics 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.

14

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

Other Nonregulated Businesses Energy Projects and Services We offer energy projects and services designed primarily to provide energy solutions to large commercial and industrial and governmental customers. These energy products and services include:

• designing, constructing, and operating heating, cooling, and cogeneration facilities,

• energy savings projects and performance contracting,

• energy consulting and procurement services,

• services to enhance the reliability of individual electric supply systems, and

• customized financing alternatives.

Home Products and Gas Retail Marketing We offer services to customers in Maryland including:

• home improvements,

• the service of heating, air conditioning, plumbing, electrical, and indoor air quality systems, and 4 the sale of natural gas to residential customers.

Consolidated Capital Requirements Our total capital requirements for 2006 were

$1,149 million. Of this amount, $789 million was used in our nonregulated businesses and $360 million was used in our regulated business. We estimate our total capital requirements will be $1,915 million in 2007.

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

Environmental Matters The development (involving site selection, environmental assessments, and permitting),

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

We continuously monitor federal, state, and local environmental initiatives to determine potential impacts on our financial results. As new laws or regulations are promulgated, we assess their applicability and implement the necessary modifications to our facilities or their operation to maintain ongoing compliance. Our capital expenditures were approximately $100 million during the five-year period 2002-2006 to comply with existing environmental standards and regulations. Our estimated environmental capital requirements for the next three years are approximately $335 million in 2007, $495 million in 2008, and $305 million in 2009.

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

NationalAmbient Air Quality Standards (NAAQS)

The NAAQS are federal air quality standards authorized under the Clean Air Act that establish maximum ambient air concentrations for the following specific pollutants: ozone (smog), carbon monoxide, lead, particulates, sulfur dioxides (SO 2), and nitrogen dioxides (NO).

In order for states to achieve compliance with the NAAQS, the Environmental Protection Agency (EPA) adopted the Clean Air Interstate Rule (CAIR) in March 2005 to further reduce ozone and fine particulate pollution by addressing the interstate transport of SO 2 and nitrogen oxide (NO.) emissions from fossil fuel-fired generating facilities located primarily in the Eastern United States.

In May 2005, the EPA adopted a stricter NAAQS for ozone and rescinded a requirement to impose fees on emissions sources in certain areas, including certain of our generating facilities, for failure to achieve the previous ozone standard. States will be required to submit plans to the EPA to meet the new standard by 2007, at which time the standard will take effect. We are unable to determine the impact that complying with the stricter NAAQS for ozone will have on our financial results until the states in which our generating facilities are located adopt plans to meet the new standard.

In December 2006, the United States Court of Appeals for the District of Columbia Circuit ruled that the requirement to impose fees on emissions sources based on the previous ozone standard remained applicable retroactive to November 2005 and remanded the issue to the EPA for reconsideration. At this time, we cannot predict what action the EPA will take in response to the Court's decision and whether the fees will be retroactively assessed. The exact method of computing these fees has not been established and will depend in part on state implementation regulations that have not been finalized. Consequently, we are unable to estimate the ultimate financial impact of the fees in light of the uncertainty surrounding the methodology that 15

will be used in calculating the fees. However, any fees that are ultimately assessed could have a material adverse affect on our financial results.

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

Hazardous Air Emissions In March 2005, the EPA finalized the Clean Air Mercury Rule (CAMR) to reduce the emissions of mercury from coal-fired facilities through a market-based cap and trade program. CAMR will affect all coal or waste coal fired boilers at our generating facilities.

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

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

In March 2006, the U.S. Court of Appeals for the District of Columbia annulled the equipment replacement rule adopted by the EPA in August 2003, which established a threshold for determining when major new source review requirements are triggered. We believe the Court decision, which was anticipated, should have minimal effect on us as it maintains the existing rules for equipment replacement. However, we anticipate that the EPA will continue to examine the existing equipment replacement rules and may again propose new rules. In addition, the U.S. Supreme Court has agreed to hear a case, not involving us, relating to the new source review requirements. We cannot predict the timing or outcome of any future EPA regulatory action or the outcome of the U.S. Supreme Court proceeding, or their possible effect on our financial results.

State Maryland has adopted the Healthy Air Act (l-AA) and the Clean Power Rule (CPR), which establish annual SO,, NO., and mercury emission caps for specific coal-fired units in Maryland, including units located at three of our facilities. The requirements of the HAA and the CPR for SO,, NO. and mercury emissions are more stringent and apply sooner than those under CAIR and CAMR.

In addition, Pennsylvania has adopted regulations requiring coal-fired generating facilities located in Pennsylvania to reduce mercury emissions sooner and to a greater extent than required under CAMR.

Several other states in the northeastern U.S.

continue to consider more stringent and earlier SO,,

NO., and mercury emissions reductions than those required under CAIR or CAMR.

Cap~ital Expenditure Estimates We expect to incur additional environmental capital spending as a result of complying with the air quality laws and regulations discussed above. Based on the information currently available to us about CAIR, CAMR, HAA, and CPR, we will install additional air emission control equipment at our coal-fired generating facilities in Maryland and at our co-owned coal-fired facilities in Pennsylvania to meet air qualiry standards.

We include in our estimated environmental capital requirements capital spending for these projects, which we expect will be approximately $320 million in 2007,

$470 million in 2008, $290 million in 2009 and

$40 million from 2010-2011.

Our estimates are subject to significant uncertainties including the timing of any additional federal and/or state regulations or legislation, the implementation timetables for such regulation or legislation, and the specific amount of emissions reductions that will be required at our facilities. As a result, we cannot predict our capital spending or the scope or timing of these projects with certainty, and the actual expenditures, scope and timing could differ significantly from our estimates. In addition, CAMR is subject to legal challenges filed by the states and industry and environmental groups. We cannot predict the timing or outcome of these challenges, or their possible effect on our financial results.

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

16

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

The HAA requires that Maryland become a full participant in the Northeast Regional Greenhouse Gas Initiative (RGGI) by June 2007. Under RGGI, it is expected that affected plants would participate in an auction to obtain sufficient CO, allowances to support the level of emissions that result from plant operations.

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

We continue to evaluate the potential impact of the I-AA and California CO, emissions requirements and RGGI participation on our financial results; however, our compliance costs could be material.

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

Water Intake Regulations In July 2004, the EPA published final rules under the Clean Water Act that require cooling water intake structures to reflect the best technology available for minimizing adverse environmental impacts. We currently have six facilities affected by the regulation.

The rule allows for a number of compliance options that will be assessed through 2007, following which we will determine whether any action is required and what our most viable options are if any action is required. Until we determine our most viable option under the final rules, we cannot estimate our compliance costs.

However, the costs associated with the final rules could be material.

In January 2007, the United States Court of Appeals for the Sccond Circuit ruled that the EPA's rule did not properly implement the Clean Water Act requirements in a number of areas and remanded the rule to the EPA for reconsideration. At this time, we cannot predict the timing or outcome of any EPA regulatory action taken in response to the court's decision. However, any such action could impact our compliance approach, which could have a material effect on our financial results.

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

Our coal-fired generating facilities produce approximately two and a half million tons of combustion by-products ("ash") each year. The EPA has announced its intention to develop national standards, currently scheduled to be proposed in May 2007, to regulate this material as a non-hazardous waste, and is developing regulations governing the placement of ash in landfills, surface impoundments, and sand/gravel surface mines.

The EPA is also developing regulations for ash placement in coal mines, which are expected to be proposed in October 2007. Federal regulation has the potential to result in additional requirements.

Depending on the scope of any final requirements, our compliance costs could be material.

As a result of these regulatory pr6posals, the remaining ash placement capacity at our current mine reclamation site and our current ash generation projections, we are exploring our options for the placement of ash, including construction of an ash placement facility. Over the next five years, we estimate that our capital expenditures for this project will be approximately $75 million. Our estimates are subject to significant uncertainties including the timing of any regulatory change, its implementation timetable, and the scope of the Final requirements. As a result, we cannot predict our capital spending or the scope and timing of this project with certainty, and the actual expenditures, scope and timing could differ significantly from our estimates.

Employees Constellation Energy and its subsidiaries had approximately 9,645 employees at December 31, 2006.

At the Nine Mile Point facility, approximately 515 employees are represented by the International Brotherhood of Electrical Workers, Local 97. The labor contract with this union expires in June 2011. We believe that our relationship with this union is satisfactory, but there can be no assurances that this will continue to be the case.

17

Item IA. Risk Factors You should consider carefully the following risks, along with the other information contained in this Form 10-K.

The risks and uncertainties described below are not the only ones that may affect us. Additional risks and uncertainties also may adversely affect our business and operations including those discussed in Item 7. Management's Discussion and Analysis. If any of the following events actually occur, our business and financial results could be materially adversely affected.

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

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

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

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

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

Exposure to fuel cost volatility. Currently, our power generation facilities purchase a portion of their fuel through short-term contracts or on the spot market.

Fuel prices can be volatile, and the price that can be obtained for power produced from such fuel may not change at the same rate as fuel costs. As a result, fuel price increases may adversely affect our financial results.

Exposure to counterparty performance. Our merchant energy business enters into trades and hedging transactions with numerous third parties (commonly referred to as "counterparties"). In such arrangements, we are exposed to the credit risks of our counterparties and the risk that one or more counterparties may fail to perform their obligations to make payments or deliver fuel or power. These risks are enhanced during periods of commodity price fluctuations, such as is currently being experienced in the United States. Defaults by suppliers and other counterparties may adversely affect our financial results.

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

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

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

We are subject to extensive federal, state, and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, wildlife protection, the management of natural resources, and the protection of human health and safety that could, among other things, require additional pollution control equipment, limit the use of certain fuels, restrict the 18

output of certain facilities, or otherwise increase costs.

Significant capital expenditures, operating and other costs are associated with compliance with environmental requirements, and these expenditures and costs could become even more significant in the future as a result of regulatory changes.

For example, the State of Maryland has enacted the Healthy Air Act and the Clean Power Rule, which will require, among other things, more rapid emission reductions by Maryland power generation facilities (including those owned and operated by us) than is required by current federal laws and regulations.

We are subject to liability under environmental laws for the costs of remediating environmental contamination. Remediation activities include the cleanup of current facilities and former properties, including manufactured gas plant operations and offsite waste disposal facilities. The remediation costs could be significantly higher than the liabilities recorded by us.

Also, our subsidiaries are currently involved in proceedings relating to sites where hazardous substances have been released and may be subject to additional proceedings in the future.

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

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

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

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

Nuclear Operating Risks.

The ownership and operation of nuclear generating facilities involve routine operating risks, including:

• mechanical or structural problems;

• inadequacy or lapses in maintenance protocols;

• impairment of reactor operation and safety systems due to human or mechanical error;

• costs of storage, handling and disposal of nuclear materials, including the availability or unavailability of a permanent repository for spent nuclear fuel;

• regulatory actions, including shut down of units because of public safety concerns, whether at our plants or other nuclear operators;

• limitations on the amounts and types of insurance coverage commercially available;

• uncertainties regarding both technological and financial aspects of decommissioning nuclear generating facilities; and

• environmental risks, including risks associated with changes in environmental legal requirements.

Nuclear Accident Risks.

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

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

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

Consequently, our financial performance depends on the continued performance by customers and suppliers of their obligations under these long-term agreements.

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

We are an active participant in energy markets through our competitive energy businesses. The liquidity of regional energy markets is an important factor in our ability to manage risks in these operations. Over the past several years, several merchant energy businesses have ended or significantly reduced their activities as a result of several factors including government investigations, changes in market design and deteriorating credit quality. As a result, several regional energy markets experienced a significant decline in liquidity. While there have been recent improvements in liquidity, future reductions in liquidity may restrict our ability to manage our risks, and could impact our financial results.

19

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

To lower our financial exposure related to commodity price fluctuations, we routinely enter into contracts to hedge a portion of our purchase and sale commitments, weather positions, fuel requirements, inventories of natural gas, coal and other commodities, and competitive supply. As part of this strategy, we routinely utilize fixed-price forward physical purchase and sales contracts, futures, financial swaps, and option contracts traded in the over-the-counter markets or on exchanges.

However, we may not cover the entire exposure of our assets or positions to market price volatility and the coverage will vary over time. Fluctuating commodity prices may negatively impact our financial results to the extent we have unhedged positions.

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

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

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

We use derivative instruments, such as swaps, options, futures and forwards, to manage our commodity and financial market risks and to engage in trading activities.

We could recognize financial losses as a result of volatility in the market values of these contracts or if a counterparty fails to perform.

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

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

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

Due to recent events in the energy markets, energy companies have been under increased scrutiny by state legislatures, regulatoty bodies, capital markets and credit rating agencies. This increased scrutiny could lead to substantial changes in laws and regulations affecting us, including modifications to the auction processes in competitive markets and new accounting standards that could change the way we are required to record revenues, expenses, assets and liabilities. The Matyland energy legislation enacted in June 2006 is one example of how these laws can change. We cannot predict the future development of regulation in these markets or the ultimate effect that this changing reguldatoty environment will have on our business.

If competitive restructuring of the electric and natural gas markets is reversed, discontinued, restricted or delayed, or if the recently enacted Matyland energy legislation is implemented or interpreted in a manner adverse to us, our business prospects and financial results could be negatively impacted.

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

We have business operations throughout the United States and internationally. As a result, we depend on transportation and transmission facilities owned and operated by utilities and other energy companies to deliver the electricity, coal, and natural gas we sell to the wholesale and retail markets, as well as the natural gas and coal we purchase to supply some of our generating facilities. If transportation or transmission is disrupted, or transportation or transmission capacity is inadequate, our ability to sell and deliver products may be hindered. Such disruptions could also hinder our ability to provide electricity or natural gas to our retail electric and gas customers and may materially adversely affect our financial results.

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

Our merchant energy business has contractual obligations to certain customers to supply full requirements service to such customers to satisfy all or a portion of their energy requirements. The uncertainty regarding the amount of load that our merchant energy business must be prepared to supply to customers may 20

increase our operating costs. A significant under-or over-estimation of load requirements could result in our merchant energy business not having enough or having too much power to cover its load obligation, in which case it would be required to buy or sell power from or to third parties at prevailing market prices. Those prices may not be favorable and thus could increase our operating costs.

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

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

Generally, demand for electricity peaks in winter and summer and demand for gas peaks in the winter.

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

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

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

We rely on access to capital markets as a source of liquidity for capital requirements not satisfied by operating cash flows. If any of our credit ratings were to be downgraded, especially below investment grade, our ability to raise capital on favorable terms, including the commercial paper markets, could be hindered, and our borrowing costs would increase. Additionally, the business prospects of our wholesale and retail competitive supply businesses, which in many cases rely on the creditworthiness of Constellation Energy, would be negatively impacted. Some of the factors that affect credit ratings are cash flows, liquidity, and the amount of debt as a component of total capitalization.

In addition, the ability of BGE to recover its costs of providing service and timing of BGE's recovery could have a material adverse effect on the credit ratings of BGE and us.

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

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

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

Energy legislation enacted in Maryland in June 2006 mandates rate stabilization that requires BGE to defer the recovery of a portion of its purchased power costs and to phase in the recovery of these costs over a period of years. In addition, the legislation mandates that the Maryland PSC conduct a comprehensive review of Maryland's deregulated electricity market. Because this energy legislation is still in the process of being implemented and interpreted, we do not know the final impact such legislation will have on our, or BGE's, business.

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

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

Our qualified pension obligations have exceeded the fair value of our plan assets since 2001. At December 31, 2006, our qualified pension obligations were approximately $405 million greater than the fair value 21

of our plan assets. The performance of the capital markets will affect the value of the assets that are held in trust to satisfy our future obligations under our qualified pension plans. A decline in the market value of those assets may increase our funding requirements for these obligations, which may adversely affect our liquidity and financial results.

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

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

We cannot predict the impact that any future terrorist attacks may have on the energy industry in general and on our business in particular. In addition, any retaliatory military strikes or sustained military campaign may affect our operations in unpredictable ways, such as changes in insurance markets and disruptions of fuel supplies and markets, particularly oil.

The possibility alone that infrastructure facilities, such as electric generation, electric and gas transmission and distribution facilities, would be direct targets of, or indirect casualties of, an act of terror may affect our operations.

Such activity may have an adverse effect on the United States economy in general. A lower level of economic activity might result in a decline in energy consumption, which may adversely affect our financial results or restrict our future growth. Instability in the financial markets as a result of terrorism or war may affect our stock price and our ability to raise capital.

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

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

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

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

Item 2. Properties Constellation Energy's corporate offices occupy approximately 106,000 square feet of leased office space in Baltimore, Maryland. The corporate offices for most of our merchant energy business occupy approximately 268,000 square feet of leased office space in another building in Baltimore, Maryland. We describe our electric generation properties on the next page. We also have leases for other offices and services located in the Baltimore metropolitan region, and for various real property and facilities relating to our generation projects.

BGE owns its principal headquarters building located in downtown Baltimore. In addition, BGE owns propane air and liquefied natural gas facilities as discussed in Item 1. Business-Gas Business section.

BGE also has rights-of-way to maintain 26-inch natural gas mains across certain Baltimore City-owned property (principally parks) which expired in 2004.

BGE is in the process of renewing the rights-of-way with Baltimore City for an additional 25 years. The expiration of the rights-of-way does not affect BGE's ability to use the rights-of-way during the renewal process.

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

• 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.

All of BGE's property is subject to the lien of BGE's mortgage securing its mortgage bonds. The generation facilities transferred to our subsidiaries by BGE on July 1, 2000, along with the stock we own in certain of our subsidiaries, are subject to the lien of BGE's mortgage.

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

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

22

The following table describes our generating facilities:

Plant Location Capacity (M")')

Capacity Owned Owned (MW)

Primary Fuel (at December 31, 2006)

Mid-Atlantic Region Calvert Cliffs Brandon Shores H. A. Wagner C. P. Crane Keystone Conemaugh Perryman Riverside Handsome Lake Notch Cliff Westport Philadelphia Road Safe Harbor Total Mid-Atlantic Region Calvert Co., MD Anne Arundel Co., MD Anne Arundel Co., MD Baltimore Co., MD Armstrong and Indiana Cos., PA Indiana Co., PA Harford Co., MD Baltimore Co., MD Rockland Twp, PA Baltimore Co., MD Baltimore City, MD Baltimore City, MD Safe Harbor, PA 1,735 1,286 963 399 1,706 1,714 355 200 250 120 116 64 417 9,325 620 1,138 581 2,339 100.0 100.0 100.0 100.0 21.0 10.6 100.0 100.0 100.0 100.0 100.0 100.0 66.7 100.0 82.0 100.0 1,735 1,286 963 399 358 (A) 181 (A) 355 200 250 120 116 64 278 6,305 Nuclear Coal Coal/Oil/Gas Oil/Coal Coal Coal Oil/Gas Oil/Gas Gas Gas Gas Oil Hydro Plants with Power Purchase Aereements Nine Mile Point Unit 1 Scriba, NY Nine Mile Point Unit 2 Scriba, NY R.E. Ginna Ontario, NY Total Plants with Power Purchase Agreements 620 933 581 2,134 Nuclear Nuclear Nuclear Other Panther Creek Nesquehoning, PA 80 50.0 40 Waste Coal Colver Colver Township, PA 104 25.0 26 Waste Coal Sunnyside Sunnyside, UT 52 50.0 26 Waste Coal ACE Trona, CA 102 31.1 32 Coal Jasmin Kern Co., CA 34 50.0 17 Coal POSO Kern Co., CA 34 50.0 17 Coal Mammoth Lakes G-1 Mammoth Lakes, CA 6

50.0 3

Geothermal Mammoth Lakes G-2 Mammoth Lakes, CA 12 50.0 6

Geothermal Mammoth Lakes G-3 Mammoth Lakes, CA 12 50.0 6

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 22 45.0 10 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 643 238 Total Generating Facilities 12,307 8,677 (A) Reflects our proportionate interest in and entitlement to capacity from Keystone and Conemaugh, which include 2 MW of die'sel capacity for Keystone and 1 MW of diesel capacity for Conemaugh.

23

The following table describes our processing facilities:

Plant A/C Fuels Gary PCI Low Country PC Synfuel VA I PC Synfuel WV I PC Synfuel WV II PC Synfuel WV III Location Hazelton, PA Gary, IN Cross, SC Norton, VA Chelyan, WV Mount Storm, WV Chester, VA Owned 50.0 24.5 99.0 16.7 16.7 16.7 16.7 Primary Fuel Waste Coal Processing Coal Processing Synfuel Processing Synfuel Processing Synfuel Processing Synfuel Processing Synfuel Processing Item 3. Legal Proceedings We discuss our legal proceedings in Note 12 to Consolidated Financial Statements.

Item 4. Submission of Matters to Vote of Security Holders On December 8, 2006, we held our annual meeting of shareholders. At that meeting, the following matters were voted upon:

1.

Class I Directors nominated by Constellation Energy were elected to serve for a term to expire in 2009 and until their successors are duly elected and qualified as follows:

Douglas L. Becker Edward A. Crooke Mayo A. Shattuck III Michael D. Sullivan COMMON SHARES CAST:

For Withheld 119,241,432 14,048,574 122,520,333 10,769,673 128,640,389 4,649,617 119,327,025 13,962,981 All other directors whose term of office continued after the date of this meeting are:

James T. Brady James R. Curtiss Yves C. de Balmann Freeman A. Hrabowski, III Nancy Lampton Robert J. Lawless Lynn M. Martin

2.

The ratification of PricewaterhouseCoopers LLP as independent registered public accounting firm for 2006 was approved. With respect to holders of common stock, the number of affirmative votes cast was 130,005,402, the number of votes cast against was 1,846,861, and the number of abstentions was 1,437,743.

3.

The shareholder proposal requesting Constellation Energy to declassify the Board of Directors was approved.

With respect to holders of common stock, the number of affirmative votes cast was 76,259,034, the number of votes cast against was 7,688,559, the number of abstentions was 26,748,840, and the number of broker non-votes was 22,593,573.

24

Executive Officers of the Registrant Name Age Present Office Mayo A. Shattuck III 52 Chairman of the Board of Constellation Energy (since July 2002), President and Chief Executive Officer of Constellation Energy (since November 2001); and Chairman of the Board of BGE (since July 2002)

E. Follin Smith 47 Executive Vice President (since January 2004), Chief Financial Officer (since June 2001) and Chief Administrative Officer (since January 2004) of Constellation Energy; and Senior Vice President and Chief Financial Officer of Baltimore Gas and Electric Company (since January 2002)

Thomas V. Brooks 44 Chairman of Constellation Energy Commodities Group, Inc. (since August 2005); and Vice Chairman (since August 2005) and Executive Vice President (since January 2004) of Constellation Energy Other Offices or Positions Held During Past Five Years None.

Senior Vice President-Constellation Energy.

President and Chief Executive Officer-Constellation Energy Commodities Group, Inc.

Michael J. Wallace Thomas F. Brady Irving B. Yoskowitz Felix J. Dawson 59 President (since January 2002) and Chief Executive Officer (since May 2005) of Constellation Generation Group, LLC; and Executive Vice President of Constellation Energy (since January 2004) 57 Executive Vice President, Corporate Strategy and Retail Competitive Supply of Constellation Energy (since January 2004) 61 Executive Vice President and General Counsel of Constellation Energy (since June 2005) 39 Senior Vice President of Constellation Energy (since October 2006); and Co-President and Co-Chief Executive Officer of Constellation Energy Commodities Group, Inc.

(since August 2005); President and Chief Executive Officer of Constellation Energy Partners LLC (since May 2006)

None.

Senior Vice President, Corporate Strategy and Development-Constellation Energy; and Vice President, Corporate Strategy and Development-Constellation Energy.

Senior Counsel-Crowell & Moring (law firm); and Senior Partner-Global Technology Partners, LLC (investment banking and consulting firm).

Co-Chief Commercial Officer-Constellation Energy Commodities Group, Inc.; and Managing Director-Constellation Energy Commodities Group, Inc.

25

Name George E. Persky Kenneth W.

DeFontes, Jr.

Paul J. Allen John R. Collins Beth S. Perlman Age Present Office 37 Senior Vice President of Constellation Energy (since October 2006); and Co-President and Co-Chief Executive Officer of Constellation Energy Commodities Group, Inc.

(since August 2005) 56 President and Chief Executive Officer of Baltimore Gas and Electric Company and Senior Vice President of Constellation Energy (since October 2004) 55 Senior Vice President, Corporate Affairs of Constellation Energy (since January 2004) 49 Senior Vice President (since January 2004) and Chief Risk Officer of Constellation Energy (since December 2001); and member of Board of Managers of Constellation Energy Partners LLC (since September 2006) 46 Senior Vice President (since January 2004) and Chief Information Officer of Constellation Energy (since April 2002) 48 Senior Vice President, Human Resources of Constellation Energy (since January 2004)

Vice President, Corporate Affairs-Constellation Energy.

Vice President-Constellation Energy.

Vice President-Constellation Energy; and Vice President, Technology-Enron Corporation.

Vice President, Human Resources-Constellation Energy; and Senior Vice President, Human Resources and Administration-Tellabs, Inc.

Other Offices or Positions Held During Past Five Years Co-Chief Commercial Officer-Constellation Energy Commodities Group, Inc.; and Managing Director-Constellation Energy Commodities Group, Inc.

Vice President, Electric Transmission and Distribution-BGE.

Marc L. Ugol 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 II Item 5. Market for Registrant's Common Equity and Related Shareholder Matters Stock Trading Constellation Energy's common stock is traded under the ticker symbol CEG. It is listed on the New York and Chicago stock exchanges.

As of January 31, 2007, there were 41,680 common shareholders of record.

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

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

In January 2007, we announced an increase in our quarterly dividend from $0.3775 to $0.435 per share payable April 2, 2007 to holders of record on March 12, 2007. This is equivalent to an annual rate of $1.74 per share.

Quarterly dividends were declared on our common stock during 2006 and 2005 in the amounts set forth below.

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

+ BGE elects to defer interest payments on the 6.20% Deferrable Interest Subordinated Debentures due 2043, and any deferred interest remains unpaid; or

• any dividends (and any redemption payments) due on BGE's preference stock have not been paid.

Common Stock Dividends and Price Ranges First Q uarter............................

Second Q uarter.........................

Third Q uarter..........................

Fourth Q uarter..........................

T otal..................................

2006 Dividend Price Declared High Low

$0.3775

$60.55

$54.01 0.3775 55.68 50.55 0.3775 60.79 53.70 0.3775 70.20 59.00 1.51 2005 Dividend Price Declared High Low

$0.335

$53.55

$43.01 0.335 57.91 50.36 0.335 62.09 56.50 0.335 62.60 50.40

$1.340 Unregistered Sales of Equity Securities and Use of Proceeds The following table presents shares surrendered by employees to exercise stock options and to satisfy tax withholding obligations on vested restricted stock and stock option exercises.

Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs Period October 1 - October 31, 2006 November 1 - November 30, 2006 Total Number of Shares Purchased 565 Average Price Paid for Shares

$60.43 Maximum Number of Shares that May Yet Be Purchased Under the Plans and Programs December 1 - December 31, 2006 2,483 68.61 Total 3,048

$67.09 27

Item 6. Selected Financial Data Constellation Energy Group, Inc. and Subsidiaries 2006 2005 2004 2003 2002" (In millions, except per share amounts)

Summary of Operations Total Revenues

$19,284.9

$16,968.3

$12,127.2

$ 9,342.8

$ 4,771.6 Total Expenses 18,025.2 16,023.8 11,209.1 8,395.5 3,711.5 Gain on Sale of Gas-Fired Plants 73.8 Income From Operations 1,333.5 944.5 918.1 947.3 1,060.1 Gain on Initial Public Offering of CEP LLC 28.7 Other Income 66.1 65.5 25.5 20.6 33.8 Fixed Charges 328.7 310.2 326.8 336.3 277.3 Income Before Income Taxes 1,099.6 699.8 616.8 631.6 816.6 Income Taxes 351.0 163.9 118.4 222.2 301.2 Income from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles 748.6 535.9 498.4 409.4 515.4 Income from Discontinued Operations, Net of Income Taxes 187.8 94.4 41.3 66.3 10.2 Cumulative Effects of Changes in Accounting Principles, Net of Income Taxes (7.2)

(198.4)

Net Income 936.4 623.1 539.7 277.3 525.6 Earnings Per Common Share from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles Assuming Dilution 4.12 2.98 2.88 2.45 3.14 Income from Discontinued Operations 1.04 0.53 0.24 0.40 0.06 Cumulative Effects of Changes in Accounting Principles (0.04)

(1.19)

Earnings Per Common Share Assuming Dilution 5.16 3.47 3.12 1.66 3.20 Dividends Declared Per Common Share 1.51 1.34 1.14 1.04 0.96 Summary of Financial Condition Total Assets

$21,801.6

$21,473.9

$17,347.1

$15,593.0

$14,943.3 Current Portion of Long-Term Debt 878.8 491.3 480.4 343.2 426.2 Capitalization Long-Term Debt

$ -4,222.3

$ 4,369.3

$ 4,813.2

$ 5,039.2

$ 4,613.9 Minority Interests 94.5 22.4 90.9 113.4 105.3 Preference Stock Not Subject to Mandatory Redemption 190.0 190.0 190.0 190.0 190.0 Common Shareholders' Equity 4,609.3 4,915.5 4,726.9 4,140.5 3,862.3 Total Capitalization

$ 9,116.1

$ 9,497.2

$ 9,821.0

$ 9,483.1

$ 8,771.5 Financial Statistics at Year End Ratio of Earnings to Fixed Charges Book Value Per Share of Common Stock 4.05 3.04 25.54 27.57 2.71 2.69 3.31 26.81 24.68 23.44 Certain prior-year amounts have been reclassified to conform with the current year's presentation.

(1)

Total revenues for the year ended December 31, 2002 include $255.5 million ofgains recognized on the sale of our outstanding shares of Orion Power Holdings, Inc.

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

28

Baltimore Gas and Electric Company and Subsidiaries 2006 2005 2004 (In millions) 2003 2002 Summary of Operations Total Revenues Total Expenses Income From Operations Other Income (Expense)

Fixed Charges Income Before Income Taxes Income Taxes Net Income Preference Stock Dividends

$3,015.4 2,646.3 369.1 6.0 102.6 272.5 102.2 170.3 13.2

$3,009.3 2,612.8 396.5 5.9 93.5 308.9 119.9 189.0 13.2

$2,724.7 2,353.3 371.4 (6.4) 96.2 268.8 102.5 166.3 13.2

$2,647.6 2,262.6 385.0 (5.4) 111.2 268.4 105.2 163.2 13.2

$2,547.3 2,181.0 366.3 10.7 140.6 236.4 93.3 143.1 13.2 Earnings Applicable to Common Stock 157.1 175.8 153.1 150.0 129.9 Summary of Financial Condition Total Assets

$5,140.7

$4,742.1

$4,662.9

$4,706.6

$4,779.9 Current Portion of Long-Term Debt 258.3

$ 469.6 165.9

$ 330.6

$ 420.7 Capitalization Long-Term Debt

$1,480.5

$1,015.1

$1,359.5

$1,343.7

$1,499.1 Minority Interest 16.7 18.3 18.7 18.9 19.4 Preference Stock Not Subject to Mandatory Redemption 190.0 190.0 190.0 190.0 190.0 Common Shareholder's Equity 1,651.5 1,622.5 1,566.0 1,487.7 1,461.7 Total Capitalization

$3,338.7

$2,845.9

$3,134.2

$3,040.3

$3,170.2 Financial Statistics at Year End Ratio of Earnings to Fixed Charges Ratio of Earnings to Fixed Charges and Preferred and Preference Stock Dividends 3.60 2.99 4.22 3.45 3.75 3.08 3.36 2.82 2.66 2.31 29

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations Introduction and Overview Constellation Energy Group, Inc. (Constellation Energy) is an energy company that conducts its business through various subsidiaries including a merchant energy business and Baltimore Gas and Electric Company (BGE). We describe our operating segments in Note 3.

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

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

• factors which affect our businesses,

• our earnings and costs in the periods presented,

• changes in earnings and costs between periods,

• sources of earnings,

• impact of these factors on our overall financial condition,

• expected future expenditures for capital projects, and

• expected sources of cash for future capital expenditures.

As you read this discussion and analysis, refer to our Consolidated Statements of income, which present the results of our operations for 2006, 2005, and 2004. We analyze and explain the differences between periods in the specific line items of our Consolidated Statements of Income.

We have organized our discussion and analysis as follows:

• First, we discuss our strategy.

• We then describe the business environment in which we operate including how regulation, weather, and other factors affect our business.

• Next, we discuss our critical accounting policies. These are the accounting policies that are most important to both the portrayal of our financial condition and results of operations and require management's most difficult, subjective or complex judgment.

• We highlight significant events that are important to understanding our results of operations and financial condition.

• We then review our results of operations beginning with an overview of our total company results, followed by a more detailed review of those results by operating segment.

• We review our financial condition addressing our sources and uses of cash, security ratings, capital resources, capital requirements, commitments, and off-balance sheet arrangements.

• We conclude with a discussion of our exposure to various market risks.

Strategy We are pursuing a strategy of providing energy and energy related services through our competitive supply activities and BGE, our regulated utility located in Matyland. Our merchant energy business focuses on short-term and long-term purchases and sales of energy, capacity, and related products to various customers, including distribution utilities, municipalities, cooperatives, and industrial, commercial, and governmental customers.

We obtain this energy through both owned and contracted supply resources. Our generation fleet is strategically located in deregulated markets and includes various fuel types, such as nuclear, coal, gas, oil, and renewable sources. In addition to owning generating facilities, we contract for power from other merchant providers, typically through power purchase agreements. We intend to remain diversified between regulated transmission and distribution and competitive supply. We will use both our owned generation and our contracted generation to support our competitive supply operations.

We are a leading national competitive supplier of energy. In our wholesale and commercial and industrial retail marketing activities we are leveraging our recognized expertise in providing full requirements energy and energy-related services to enter markets, capture market share, and organically grow these businesses. Through the application of technology, intellectual capital, process improvement, and increased scale, we are seeking to reduce the cost of delivering full requirements energy and energy related services and managing risk.

We are also responding proactively to customer needs by expanding the variety of products we offer. Our wholesale competitive supply activities include a growing operation that markets physical energy products and risk management and logistics services to generators, distributors, producers of coal, natural gas and fuel oil, and other consumers.

We trade energy and energy-related commodities and deploy risk capital in the management of our portfolio in order to earn additional returns. These activities are managed through daily value at risk and stop loss limits and liquidity guidelines.

Within our retail competitive supply activities, we are marketing a broader array of products and expanding our markets. Over time, we may consider integrating the sale of electricity and natural gas to provide one energy procurement solution for our customers.

Collectively, the integration of owned and contracted electric generation assets with origination, fuel procurement, and risk management expertise, allows our merchant energy business to earn incremental margin and more effectively manage energy and commodity price risk over geographic regions and over time.

Our focus is on providing solutions to customers' energy needs, and our wholesale marketing, risk management, and trading operation adds value to our owned and contracted generation assets by providing national market access, market infrastructure, real-time market intelligence, risk management and arbitrage opportunities, and transmission and transportation expertise.

Generation capacity supports our wholesale marketing, risk management, and trading operation by providing a source of reliable power supply.

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To achieve our strategic objectives, we expect to continue to pursue opportunities that expand our access to customers and to support our wholesale marketing, risk management, and trading operation with generation assets that have diversified geographic, fuel, and dispatch characteristics. We also expect to grow through buying and selling a greater number of physical energy products and services to large energy customers. We expect to achieve operating efficiencies within our competitive supply operation and our generation fleet by selling more products through our existing sales force, benefiting from efficiencies of scale, adding to the capacity of existing plants, and making our business processes more efficient.

We expect BGE and our other retail energy service businesses to grow through focused and disciplined expansion primarily from new customers. At BGE, we are also focused on enhancing reliability and customer satisfaction.

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

We are constantly reevaluating our strategies and might consider:

• acquiring or developing additional generating facilities and gas properties to support our merchant energy

business,

• mergers or acquisitions of utility or non-utility businesses or assets, and

• sale of assets or one or more businesses.

Business Environment With the evolving regulatory environment surrounding customer choice, increasing competition, and the growth of our merchant energy business, various factors affect our financial results. We discuss some of these factors in more detail in the Item 1.

Business--Competition section. We also discuss these various factors in the Forward Looking Statements and Item MA. Risk Factors sections.

Over the last several years, the energy markets have been highly volatile with significant changes in natural gas, power, oil, coal, and emission allowance prices. The volatility of the energy markets impacts our credit portfolio, and we continue to actively manage our credit portfolio to attempt to reduce the impact of a potential counterparty default. We discuss our customer (counterparty) credit and other risks in more detail in the Market Risk section.

In addition, the volatility of the energy markets impacts our liquidity and collateral requirements. We discuss our liquidity in the Financial Condition section.

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

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

In addition, other states are reconsidering deregulation.

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

We discuss merchant competition in more detail in Item 1.

Business-Competition section.

The impacts of electric deregulation on BGE in Maryland are discussed in Item 1. Business-Electric Regulatory Matters and Competition section.

Regulation-Senate Bill I In June 2006, Senate Bill 1 was enacted, which, among other things:

• directs the Maryland PSC to conduct a comprehensive review of Maryland's deregulated electricity market, including the implications of requiring or allowing utilities to construct, acquire, or lease power generating facilities and alternative approaches to power procurement;

1. expands the authority of the Maryland PSC to review acquisitions, dispositions, and financings by public service companies operating in Maryland; and

• directs Maryland's taxing authority to consider whether property tax valuation methodologies applied to power plants located in Maryland should be revised in light of the values of those properties in a restructured electric industry.

Because Senate Bill 1 requires additional decisions and proceedings by the Maryland PSC and other governmental authorities to implement and interpret many of its provisions, we cannot predict the ultimate impact of the legislation on us, BGE, or the energy market in Maryland. The new legislation and its implementation through applicable regulatory proceedings could have a material adverse effect on our, or BGE's, financial results.

In addition, one or more parties may challenge in court one or more provisions of Senate Bill 1. The outcome of any challenges and the uncertainty that could result cannot be predicted.

We discuss the provisions of Senate Bill 1 relating to residential electric customer rates in Item 1. Business-Electric Regulatory Matters and Competition section.

Regulation by the Maryland PSC In addition to electric restructuring, which is discussed in Item 1.

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

31

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

Higher electric base rates apply during the summer when the demand for electricity is higher. Gas base rates are not affected by seasonal changes.

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

In December 2005, the Maryland PSC issued an order granting BGE a $35.6 million annual increase in its gas base rates. In December 2006, the Baltimore City Circuit Court upheld the rate order. However, certain parties have filed an appeal with the Court of Special Appeals. We cannot provide assurance that the Maryland PSC's order will not be reversed in whole or part or that certain issues will not be remanded to the Maryland PSC for reconsideration.

Electric Commodity and Transmission Charges BGE electric commodity and transmission charges (standard offer service), including the enactment of Senate Bill 1 in Maryland, are discussed in Item 1. Business-Electric Regulatory Matters and Competition section.

Gas Commodity Charge BGE charges its gas customers separately for the natural gas they purchase. The price BGE charges for the natural gas is based on a market-based rates incentive mechanism approved by the Maryland PSC. We discuss market-based rates in more detail in the Regulated Gas Business-Gas Cost Adjustments section and in Note 6.

Federal Regulation FERC The FERC has jurisdiction over various aspects of our business, including electric transmission and wholesale natural gas and electricity sales. We believe that FERC's continued commitment to fair and efficient wholesale energy markets should continue to result in improvements to competitive markets across various regions.

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

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

Ongoing initiatives at FERC have included a review of its methodology for the granting of market-based rate authority to sellers of electricity. FERC has announced interim tests that will be used to determine the extent to which companies may have market power in certain regions. Where market power is found to exist, FERC may require companies to implement measures to mitigate the market power in order to maintain market-based rate authority. In addition, FERC is reviewing other aspects of its granting of market-based rate authority, including horizontal and vertical market power, affiliate abuse, and barriers to entry. We cannot determine the eventual outcome of FERC's efforts in this regard and their impact on our financial results at this time.

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

In addition, FERC provided transmission customers that are charged the SECA rates with an opportunity to demonstrate that such charges should be shifted to their wholesale power suppliers. We are a recipient of SECA payments, payer of SECA charges, and supplier to whom such charges may be shifted.

Administrative hearings regarding the SECA charges concluded in May 2006, and an initial decision from the FERC administrative law judge (ALJ) was issued in August 2006. The decision of the ALJ generally found in favor of reducing the overall SECA liability. The decision, if upheld, is expected to significantly reduce the overall SECA liability at issue in this proceeding. However, the ALJ also allowed SECA charges to be shifted to upstream suppliers, subject to certain adjustments.

Therefore, certain charges could be shifted to our wholesale marketing, risk management, and trading operation. This decision will be reviewed by FERC. We are unable to predict the timing or final outcome of FERC's SECA rate proceeding.

However, as the amounts collected under the SECA rates are subject to refund and the ultimate outcome of the proceeding establishing SECA rates is uncertain, the result of this proceeding may have a material effect on our financial results.

In April 2006, FERC issued an initial order approving PJM's proposal to restructure its capacity market. Such a restructuring would change how we are paid for generating plant capacity available to PJM. However, FERC found that certain elements of the proposal needed further development before FERC could issue a final order and encouraged the parties to the proceeding, including Constellation Energy, to continue to seek a negotiated resolution of the remaining issues. Subsequently, 32

settlement discussions were conducted among the parties that resulted in a settlement being approved by FERC in December 2006, subject to requests for rehearing and potential further judicial review. Currently, we cannot predict with certainty the capacity prices that will result from the restructuring, given that rules must still be developed, or the possible effect such prices will have on our, or BGE's, financial results.

In February 2007, FERC adopted Order No. 890, which reforms the open-access transmission regulatory framework. We are in the process of evaluating this rule and its possible effect on our, or BGE's, financial results.

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

Federal Energy Legislation The Energy Policy Act of 2005 (EPACT 2005) was enacted in August 2005. The legislation encourages investments in energy production and delivery infrastructure, including further development of competitive wholesale energy markets, and promotes the use of a diverse mix of fuels and renewable technologies to generate electricity, including federal support and tax incentives for clean coal, nuclear, and renewable power generation. Effective February 2006, the legislation repealed the Public Utility Holding Company Act of 1935 (PUHCA 1935).

In addition, EPACT 2005 significantly increased FERC's enforcement authority. There have been a number of FERC rulemaking proceedings that relate to the implementation of EPACT 2005 including proceedings relating to FERC's new responsibilities following the repeal of PUHCA 1935, its revised merger authority, its new authority over electric grid reliability, and its new authority with respect to addressing electric and gas market manipulation. FERC has moved expeditiously to implement its new authority under EPACT 2005 and has completed many of its rulemaking proceedings under EPACT 2005. Additional rulemaking remains to be completed, which could have a material impact on our, or BGE's, financial results.

There are also rulemakings required from other federal agencies, the outcome of which could affect our financial results, but we cannot at this time predict such outcome or the actual effect on our financial results.

Weather Merchant Energy Business Weather conditions in the different regions of North America influence the financial results of our merchant energy business.

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

BGE Weather affects the demand for electricity and gas for our regulated businesses. Very hot summers and very cold winters increase demand. Mild weather reduces demand. Weather affects residential sales more than commercial and industrial sales, which are mostly affected by business needs for electricity and gas. The Maryland PSC approved a revenue decoupling mechanism which allows BGE to record a monthly adjustment to our regulated gas business revenues to eliminate the effect of abnormal weather patterns. We discuss this further in the Regulated Gas Business-Revenue Decoupling section.

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

• seasonal, daily, and hourly changes in demand,

• number of market participants,

• extreme peak demands,

• available supply resources,

• transportation and transmission availability and reliability within and between regions,

• location of our generating facilities relative to the location of our load-serving obligations,

• implementation of new market rules governing operations of regional power pools,

+ procedures used to maintain the integrity of the physical electricity system during extreme conditions,

• changes in the nature and extent of federal and state regulations, and 4 international supply and demand.

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

• weather conditions,

• market liquidity,

• capability and reliability of the physical electricity and gas systems,

• local transportation systems, and

• the nature and extent of electricity deregulation.

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

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

Usage per customer refers to all other items impacting customer sales that cannot be measured separately. These factors include the strength of the economy in our service territory.

When the economy is healthy and expanding, customers tend to consume more electricity and gas. Conversely, during an economic downturn, our customers tend to consume less electricity and gas.

33

Environmental Matters and Legal Proceedings We discuss details of our environmental matters in Note 12 and Item 1. Business-Environmental Matters section. We discuss details of our legal proceedings in Note 12. Some of this information is about costs that may be material to our financial results.

Accounting Standards Adopted and Issued We discuss recently adopted and issued accounting standards in Note 1.

Critical Accounting Policies Our discussion and analysis of financial condition and results of operations is based on our consolidated financial statements that were prepared in accordance with accounting principles generally accepted in the United States of America. Management makes estimates and assumptions when preparing financial statements.

These estimates and assumptions affect various matters, including:

• our reported amounts of revenues and expenses in our Consolidated Statements of Income,

• our reported amounts of assets and liabilities in our Consolidated Balance Sheets, and

• our disclosure of contingent assets and liabilities.

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

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

Accounting for Derivatives Our merchant energy business originates and acquires contracts for energy, other energy-related commodities, and related derivatives. We record merchant energy business revenues using two methods of accounting: accrual accounting and mark-to-market accounting. The accounting requirements for derivatives are governed by Statement of Financial Accounting Standard (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, and applying those requirements involves the exercise of judgment in evaluating these provisions, as well as related implementation guidance and applying those requirements to complex contracts in a variety of commodities and markets.

Many fundamental customer contracts in our business, such as those associated with our load-serving activities, must be accounted for on an accrual basis. We may economically hedge these contracts with derivatives and elect cash-flow hedge accounting or apply the normal purchase and normal sale exception in order to match more closely the timing of the recognition of earnings from these transactions. We make these elections because we believe that accrual accounting provides the most transparent presentation to our shareholders of these business activities. If our commercial transactions or related hedges meet the definition of a derivative, we must comply with the provisions of SFAS No. 133 in order to use cash-flow hedge accounting or the normal purchase and normal sale exception.

Qualifying for either of these accounting treatments requires ongoing compliance with specific, detailed documentation and other requirements that may be unrelated to the economics of the transactions or how the associated risks are managed. While we believe we have appropriate controls in place to comply with these requirements, the failure to meet all of those requirements, even inadvertently, may result in disqualifying the use of these accounting treatments for those transactions for any affected period until all such requirements are satisfied.

0 The exercise of management's judgment in using cash-flow hedge accounting or electing the normal purchase and sale exception versus mark-to-market accounting, including compliance with all of the associated qualification and documentation requirements, materially impacts our financial results with respect to timing of the recognition of earnings.

In addition, interpretations of SFAS No. 133 could continue to evolve. If there is a future change in interpretation or a failure to meet the qualification and documentation requirements, contracts that currently are excluded from the provisions of SFAS No. 133 under the normal purchase and normal sale exception or for which changes in fair value are recorded in other comprehensive income under cash-flow hedge accounting could be deemed to no longer qualify for those accounting treatments.

If that were to occur, normal purchase and normal sale contracts could be required to be recorded on the balance sheet at fair value with changes in value recorded in the income statement, and changes in value of derivatives previously designated as cash-flow hedges could be required to be recorded in the income statement rather than in other comprehensive income.

We record revenues and fuel and purchased energy expenses from the sale or purchase of energy, energy-related products, and energy services under the accrual method of accounting in the period when we deliver or receive energy commodities, products, and services, or settle contracts. We use accrual accounting for our merchant energy and other nonregulated business transactions, including the generation or purchase and sale of electricity, gas, and coal as part of our physical delivery activities and for power, gas, and coal sales contracts that are not subject to mark-to-market accounting.

Contracts that are eligible for accrual accounting include non-derivative transactions and derivatives that qualify for and are designated as normal purchases and normal sales of commodities that will be physically delivered.

The use of accrual accounting requires us to analyze contracts to determine whether they are non-derivatives or, if they are derivatives, whether they meet the requirements for designation as normal purchases and normal sales. For those derivative contracts that do not meet these criteria, we may also analyze whether they qualify for hedge accounting, including performing an evaluation of historical market price information to determine whether such contracts are expected to be highly effective in offsetting changes in cash flows from the risk being hedged. We record the fair value of derivatives for which we have 34

elected hedge accounting in "Risk management assets and liabilities."

We use the mark-to-market method of accounting for derivative contracts for which we do not elect to use accrual accounting or hedge accounting. These mark-to-market activities include derivative contracts for energy and other energy-related commodities. Under the mark-to-market method of accounting, we record the fair value of these derivatives as mark-to-market energy assets and liabilities at the time of contract execution. We record the changes in mark-to-market energy assets and liabilities in our Consolidated Statements of Income.

Mark-to-market energy assets and liabilities consist of a combination of energy and energy-related derivative contracts.

While some of these contracts represent commodities or instruments for which prices are available from external sources, other commodities and certain contracts are not actively traded and are valued using modeling techniques to determine expected future market prices, contract quantities, or both. The market prices and quantities used to determine fair value reflect management's best estimate considering various factors.

However, future market prices and actual quantities will vary from those used in recording mark-to-market energy assets and liabilities, and it is possible that such variations could be material.

We record valuation adjustments to reflect uncertainties associated with certain estimates inherent in the determination of the fair value of mark-to-market energy assets and liabilities. The effect of these uncertainties is not incorporated in market price information or other market-based estimates used to determine fair value of our mark-to-market energy contracts. To the extent possible, we utilize market-based data together with quantitative methods for both measuring the uncertainties for which we record valuation adjustments and determining the level of such adjustments and changes in those levels.

We describe below the main types of valuation adjustments we record and the process for establishing each. Generally, increases in valuation adjustments reduce our earnings, and decreases in valuation adjustments increase our earnings.

However, all or a portion of the effect on earnings of changes in valuation adjustments may be offset by changes in the value of the underlying positions.

• Close-out adjustment-represents the estimated cost to close out or sell to a third-party open mark-to-market positions. This valuation adjustment has the effect of valuing "long" positions (the purchase of a commodity) at the bid price and "short" positions (the sale of a commodity) at the offer price. We compute this adjustment using a market-based estimate of the bid/offer spread for each commodity and option price and the absolute quantity of our net open positions for each year. The level of total close-out valuation adjustments increases as we have larger unhedged positions, bid-offer spreads increase, or market information is not available, and it decreases as we reduce our unhedged positions, bid-offer spreads decrease, or market information becomes available. To the extent that we are not able to obtain observable market information for similar contracts, the close-out adjustment is equivalent to the initial contract margin, thereby resulting in no gain or loss at inception. In the absence of observable market information, there is a presumption that the transaction price is equal to the market value of the contract, and therefore we do not recognize a gain or loss at inception. We recognize such gains or losses in earnings as we realize cash flows under the contract or when observable market data becomes available.

• Credit-spread adjustment-for risk management purposes, we compute the value of our mark-to-market energy assets and liabilities using a risk-free discount rate.

In order to compute fair value for financial reporting purposes, we adjust the value of our mark-to-market energy assets to reflect the credit-worthiness of each counterparty based upon either published credit ratings, or equivalent internal credit ratings and associated default probability percentages. We compute this adjustment by applying a default probability percentage to our outstanding credit exposure, net of collateral, for each counterparty. The level of this adjustment increases as our credit exposure to counterparties increases, the maturity terms of 'ur transactions increase, or the credit ratings of our counterparties deteriorate, and it decreases when our credit exposure to counterparties decreases, the maturity terms of our transactions decrease, or the credit ratings of our counterparties improve.

Market prices for energy and energy-related commodities vary based upon a number of factors, and changes in market prices affect both the recorded fair value of our mark-to-market energy contracts and the level of future revenues and costs associated with accrual-basis activities. Changes in the value of our mark-to-market energy contracts will affect our earnings in the period of the change, while changes in forward market prices related to accrual-basis revenues and costs will affect our earnings in future periods to the extent those prices are realized. We cannot predict whether, or to what extent, the factors affecting market prices may change, but those changes could be material and could affect us either favorably or unfavorably. We discuss our market risk in more detail in the Market Risk section.

The impact of derivative contracts on our revenues and costs is material and is affected by many factors, including:

+ our ability to continue to designate and qualify derivative contracts for normal purchase and normal sale accounting or hedge accounting under the requirements of SFAS No. 133, as amended and as interpreted in supplemental guidance,

• potential volatility in earnings from ineffectiveness associated with derivatives subject to hedge accounting,

• potential volatility in earnings from derivative contracts that serve as economic hedges but do not meet the accounting requirements to qualify for normal purchase and normal sale accounting or hedge accounting,

• our ability to enter into new mark-to-market derivative origination transactions, and

• sufficient liquidity and transparency in the energy markets to permit us to record gains at inception of new derivative contracts because fair value is evidenced by quoted market prices, current market transactions, or other observable market information.

35

As discussed in Note 1, the Financial Accounting Standards Board (FASB) issued SFAS No. 157, Fair Value Measurements, which is effective January 1, 2008 and will affect our accounting for derivatives. SFAS No. 157 defines fair value, establishes a framework for measuring fair value, and expands disclosures for fair value measurements.

Evaluation of Assets for Impairment and Other Than Temporary Decline in Value Long-Lived Assets We are required to evaluate certain assets that have long lives (for example, generating property and equipment and real estate) to determine if they are impaired when certain conditions exist.

SFAS No. 144, Accounting for the Impairment or Disposal ofLong-LivedAssets, provides the accounting requirements for impairments of long-lived assets. We are required to test our long-lived assets for recoverability whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. Examples of such events or changes are:

• a significant decrease in the market price of a long-lived

asset,

• a significant adverse change in the manner an asset is being used or its physical condition,

• an adverse action by a regulator or legislature or an adverse change in the business climate,

• an accumulation of costs significantly in excess of the amount originally expected for the construction or acquisition of an asset,

• a current-period loss combined with a history of losses or the projection of future losses, or

• a change in our intent about an asset from an intent to hold to a greater than 50% likelihood that an asset will be sold or disposed of before the end of its previously estimated useful life.

For long-lived assets that are expected to be held and used, SFAS No. 144 provides that an impairment loss shall only be recognized if the carrying amount of an asset is not recoverable and exceeds its fair value. The carrying amount of an asset is not recoverable under SFAS No. 144 if the carrying amount exceeds the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset. Therefore, when we believe an impairment condition may have occurred, we are required to estimate the undiscounted future cash flows associated with a long-lived asset or group of long-lived assets at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. This necessarily requires us to estimate uncertain future cash flows.

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

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

For long-lived assets that can be classified as assets held for sale under SFAS No. 144, an impairment loss is recognized to the extent their carrying amount exceeds their fair value less costs to sell.

If we determine that the undiscounted cash flows from an asset to be held and used are less than the carrying amount of the asset, or if we have classified an asset as held for sale, we must estimate fair value to determine the amount of any impairment loss. The estimation of fair value under SFAS No. 144, whether in conjunction with an asset to be held and used or with an asset held for sale, also involves judgment. We consider quoted market prices in active markets to the extent they are available. In the absence of such information, we may consider prices of similar assets, consult with brokers, or employ other valuation techniques. Often, we will discount the estimated future cash flows associated with the asset using a single interest rate that is commensurate with the risk involved with such an investment or employ an expected present value method that probability-weights a range of possible outcomes. The use of these methods involves the same inherent uncertainty of future cash flows as discussed above with respect to undiscounted cash flows. Actual future market prices and project costs could vary from those used in our estimates, and the impact of such variations could be material.

We are also required to evaluate our equity-method and cost-method investments (for example, in partnerships that own power projects) to determine whether or not they are impaired.

Accounting Principles Board (APB) Opinion No. 18, The Equity Method ofAccounting for Investments in Common Stock, provides the accounting requirements for these investments. The standard for determining whether an impairment must be recorded under APB No. 18 is whether the investment has experienced a loss in value that is considered an "other than a temporary" decline in value.

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

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

36

Debt and Equity Securities Our investments in debt and equity securities, primarily our nuclear decommissioning trust fund assets, are subject to impairment evaluations under FASB Staff Position SFAS 115-1 and SFAS 124-1 (FSP 115-1 and 124-1), The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments. FSP 115-1 and 124-1 requires us to determine whether a decline in fair value of an investment below the amortized cost basis is other than temporary. If we determine that the decline in fair value is judged to be other than temporary, the cost basis of the investment must be written down to fair value as a new cost basis.

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

Asset Retirement Obligations We incur legal obligations associated with the retirement of certain long-lived assets. SFAS No. 143, Accounting for Asset Retirement Obligations, provides the accounting for legal obligations associated with the retirement of long-lived assets.

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

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

Our nuclear decommissioning costs represent our largest asset retirement obligation. This obligation primarily results from the requirement to decommission and decontaminate our nuclear generating facilities in connection with their future retirement. We utilize site-specific decommissioning cost estimates to determine our nuclear asset retirement obligations.

However, given the magnitude of the amounts involved, complicated and ever-changing technical and regulatory requirements, and the very long time horizons involved, the actual obligation could vary from the assumptions used in our estimates, and the impact of such variations could be material.

Significant Events Termination of Merger Agreement with FPL Group, Inc.

On October 24, 2006, Constellation Energy and FPL Group, Inc. (FPL Group) agreed to terminate the Agreement and Plan of Merger the parties had entered into on December 18, 2005. We discuss the merger termination agreement in more detail in Note 15.

Commodity Prices During 2006, we continued to experience significant changes in commodity prices. This volatile commodity price environment continues to impact our results of operations and financial conditions. This volatility contributed to the following changes in our financial statements:

• total mark-to-market assets decreased $510.3 million and total mark-to-market liabilities decreased

$796.9 million since December 31, 2005,

• total risk management assets decreased

$1,282.9 million and total risk management liabilities increased $528.3 million since December 31, 2005,

• net cash collateral requirements increased $630.6 million since December 31, 2005,

• accumulated other comprehensive loss increased

$1,088.1 million since December 31, 2005,

• total revenues increased $2,316.6 million during 2006 compared to 2005, and

• total fuel and purchased energy expenses increased

$1,691.1 million during 2006 compared to 2005.

We discuss the impact of commodity prices on our financial condition and results of operations in more detail in the following sections:

• Merchant Energy Results,

• Financial Condition,

• Contractual Payment Obligations and Committed Amounts, and

• Market Risk.

Residential Electric Rates We discuss Senate Bill 1 enacted by the Maryland General Assembly in more detail in the Item 1. Business-Electric Regulatory Matters and Competition and Regulation sections.

Gas-Fired Plants In December 2006, we completed the sale of several gas-fired plants for $1.6 billion in cash, and recognized a pre-tax gain on the sale of $259.0 million, or $163.8 million after-tax. We discuss the sale in more detail in Note 2.

37

Synthetic Fuel Facilities Our merchant energy business has investments in facilities that manufacture solid synthetic fuel produced from coal as defined under the Internal Revenue Code (IRC) for which we can claim tax credits on our Federal income tax return through 2007. The IRC provides for a phase-out of synthetic fuel tax credits if average annual wellhead oil prices increase above certain levels. For 2006, we estimate the tax credit reduction would begin if the reference price exceeds approximately $55 per barrel and would be fully phased-out if the reference price exceeds approximately $68 per barrel. We discuss how we determine the amount of phase-out in more detail in Note 10.

Based on monthly EIA published wellhead oil prices for the ten months ended October 31, 2006 and November and December NYMEX prices for light, sweet, crude oil (adjusted for the 2006 difference between EIA and NYMEX prices), we estimate a 38% tax credit phase-out in 2006. We recorded the effect of this phase-out estimate as a reduction in tax credits of

$44.3 million during 2006.

For 2007, we estimate the tax credit reduction would begin if the reference price exceeds approximately $56 per barrel and would be fully phased-out if the reference price exceeds approximately $70 per barrel. Based on forward market prices and volatilities as of February 22, 2007, we estimate a 21% tax credit phase-out in 2007. However, the ultimate amount of tax credits phased-out for 2007 is subject to change based on the actual reference price and production levels for the entire year. In addition, our ability to claim synthetic fuel tax credits and the potential phase-out of these credits could be materially impacted by any future legislative changes to the Internal Revenue Code.

We actively monitor and manage our exposure to synthetic fuel tax credit phase-out as part of our ongoing hedging activities. In addition, we continue to monitor various options related to our South Carolina facility, including the suspension or cessation of synthetic fuel production depending on our expectation of the level of tax credit phase-out.

We will continue to monitor the level of synthetic fuel tax credit phase-out based on forward market prices and volatilities and perform impairment analyses as warranted. A significant increase in synthetic fuel tax credit phase-out could result in an impairment. At December 31, 2006, the book value of our investment in synthetic fuel facilities is approximately $14 million, substantially all of which is related to our South Carolina facility.

Workforce Reduction Costs During the quarter ended March 31, 2006, we incurred costs associated with a planned workforce restructuring at our R. E. Ginna Nuclear Power Plant (Ginna). In July 2006, we announced a planned workforce restructuring at our Nine Mile Point Nuclear Station (Nine Mile Point). We also initiated a restructuring of the workforce at our Calvert Cliffs nuclear facility during the third quarter of 2006.

In addition, during 2006, we recorded a settlement charge in our Consolidated Statements of Income for one of our qualified plans under SFAS No. 88, Employers'Accountingfor Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits.

We discuss these restructurings and the settlement charge in more detail in Note 2.

Acquisitions During 2006, we acquired working interests in gas and oil producing fields. We discuss this acquisition in more detail in the Note 15.

Initial Public Offering of Constellation Energy Partners LLC In November 2006, Constellation Energy Partners LLC (CEP),

a limited lidbility company formed by Constellation Energy, completed its initial public offering of common units. CEP is principally engaged in the acquisition, development, and exploitation of natural gas properties. CEP's existing property is located in the Robinson's Bend Field in the Black Warrior Basin of Alabama.

We discuss the impact of this initial public offering on our financial results in more detail in Note 2.

Nine Mile Point License Extension In October 2006, we received Nuclear Regulatory Commission approval for license extension for both units at our Nine Mile Point nuclear facility. With the renewed licenses, we can continue to operate Unit 1 until 2029 and Unit 2 until 2046.

Ginna Uprate During the fourth quarter of 2006, we completed a planned outage at our Ginna nuclear facility, which included an uprate of the plant from 498 megawatts to 581 megawatts. We expect that the increase in capacity of the facility will result in higher revenues in future years due to higher generation.

Dividend Increase In January 2007, we announced an increase in our quarterly dividend to $0.435 per share on our common stock. This is equivalent to an annual rate of $1.74 per share. Previously, our quarterly dividend on our common stock was $0.3775 per share, equivalent to an annual rate of $1.51 per share.

38

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

Overview Results Merchant energy Regulated electric Regulated gas Other nonregulated 2006 2005 2004 (In millions, afler-tax)

$580.1

$359.4

$358.0 120.2 149.4 131.1 37.0 26.7 22.2 11.3 0.4 (12.9)

Income from continuing operations and before cumulative effects of changes in accounting principles 748.6 535.9 498.4 Income from discontinued operations 187.8 94.4 41.3 Cumulative effects of changes in accounting principles (7.2)

Net Income

$936.4

$623.1

$539.7 Other Items Included in Operations:

Gain on sale of gas-fired plants

$ 47.1 Non-qualifting hedges 39.2 (24.9) 0.2 Workforce reduction costs (17.0)

(2.6)

(5.9)

Merger-related costs (5.7)

(15.6)

Recognition of 2003 synthetic fuel tax credits 35.9 Total Other Items

$ 63.6

$ (43.1)

$ 30.2 Certain prior-year amounts have been reclassified to conform with the current year's presentation.

2006 Our total net income for 2006 increased $313.3 million, or

$1.69 per share, compared to 2005 mostly because of the following:

• We had higher earnings of approximately $144 million after-tax at our merchant energy business due to higher gross margin from the Mid-Atlantic Region. We discuss this increase in gross margin in more detail in the Mid-Atlantic Region section.

• We had higher earnings from discontinued operations of $93.4 million after-tax mostly due to the gain on sale of our High Desert facility. In addition, we had higher earnings of $47.1 million resulting from the recognition of a gain on sale of five other gas-fired generating facilities. We discuss the sale of these plants in more detail in Note 2.

• We had higher wholesale competitive supply gross margin of approximately $105 million after-tax. This increase was partially offset by approximately

$68 million after-tax of higher operating expenses mostly because of higher labor and benefit costs due to the growth of our wholesale competitive supply operation. We discuss our mark-to-market and wholesale accrual results in more detail in the Competitive Supply section.

• We had higher earnings of $67.7 million after-tax at our retail competitive supply operation primarily due to an increase in gross margin, partially offset by higher operating expenses to support the growth of this operation. We discuss our retail gross margin in more detail in the Competitive Supply-Retail section.

• We had higher earnings of approximately $18 million after-tax due to the gain on the CEP initial public offering. This gain was partially offset by cash-flow hedge losses of approximately $10 million after-tax reclassified from "Accumulated other comprehensive income" to revenues as a result of the initial public offering. We discuss the CEP transaction in more detail in Note 2.

• We had higher earnings of $10.3 million after-tax from our regulated gas business primarily due to the favorable impact of the increase in gas base rates that was approved in December 2005.

These increases were partially offset by the following:

• We had lower earnings of $30.1 million after-tax at our synthetic fuel facilities mostly due to the expected phase-out of tax credits as a result of the high price of oil. We discuss the phase-out of tax credits in more detail in the Significant Events section.

• We had lower earnings of $29.2 million after-tax from our regulated electric business primarily due to higher operations and maintenance expenses and lower revenues less electricity purchased for resale expenses.

• We had lower earnings of $14.4 million after-tax due to workforce reduction costs associated with workforce restructurings at our nuclear generating facilities. We discuss these costs in more detail in the Note 2.

• We had lower earnings of approximately $11 million after-tax due to higher fixed charges and lower other income. We discuss these items in more detail in the Consolidated Nonoperating Income and Expenses section.

2005 Our total net income for 2005 increased $83.4 million, or

$0.35 per share, compared to 2004 mostly because of the following:

• We had higher earnings of approximately $58 million at our wholesale marketing, risk management, and trading operation. This increase is primarily due to the realization of higher gross margin, which included the termination or restructuring of several energy contracts and higher mark-to-market results in earnings. We discuss these terminations, restructurings, and mark-to-market results in more detail in the Competitive Supply section. This increase in earnings was partially offset by higher load-serving costs resulting from extreme weather and volatile commodity prices and higher operating expenses.

• We recorded higher income from discontinued operations of $53.1 million after-tax. This increase is primarily due to a loss of $49.1 million after tax in 2004 related to the sale of our Hawaiian geothermal facility which had a negative impact in that period. We discuss discontinued operations in more detail in Note 2.

39

• We had higher earnings of approximately $34 million after-tax primarily due to higher interest and investment income due to a higher cash balance, and higher decommissioning trust asset earnings, and lower interest expense resulting from the maturity of

$300.0 million in long-term debt in 2005 and the favorable impact of floating-rate swaps.

• We had higher earnings of $29.1 million after-tax at our Nine Mile Point and Ginna facilities primarily due to productivity improvements and cost saving initiatives partially offset by inflationary cost increases and costs associated with the planned refueling outage at Ginna.

• We had higher earnings of $22.8 million after-tax at our regulated businesses primarily due to favorable weather during 2005 compared to 2004.

• We had higher earnings of approximately $17 million after-tax due to the absence of coal delivery issues that were experienced in 2004 that had a negative impact in that period.

• We had higher earnings from our other nonregulated businesses of $13.3 million after-tax, including higher gains from the continued liquidation of our non-core investments and the results of Cogenex, which was acquired in April 2005. We discuss the acquisition of Cogenex in more detail in Note 15.

• We had higher earnings at our South Carolina synthetic fuel facility of $7.6 million after-tax due to a higher level of production in 2005 compared to 2004.

These increases were partially offset by the following:

• Our merchant energy business recognized

$35.9 million of 2003 synthetic fuel tax credits in 2004 which had a positive impact in that period.

• We had lower earnings at our retail competitive supply operation of $25.1 million after-tax primarily due to higher costs to serve our load obligations in Texas and the absence of bankruptcy settlements that had a favorable impact in 2004.

• We had lower earnings of $25.1 million after-tax related to losses associated with certain economic hedges that do not qualify for cash-flow hedge accounting treatment. We discuss these economic hedges in more detail in the Mark-to-Market section.

• We had lower earnings of $15.6 million after-tax due to external costs associated with the execution of our merger agreement with FPL Group.

• We had lower earnings of $20.0 million after-tax due to lower competitive transition charge (CTC) revenues at our merchant energy business.

• We had lower earnings of $8.5 million after-tax related to the impact of expensing stock options during the fourth quarter of 2005.

• We had lower earnings of $7.2 million after-tax due to the cumulative effect of adopting FIN 47 and SFAS No. 123 Revised (SFAS No. 123R), Share-Based Payment. We discuss the adoption of these standards in detail in Note 1.

Earnings per share was impacted by additional dilution, including the issuance of 6.0 million shares of common stock on July 1, 2004.

Merchant Energy Business

Background

Our merchant energy business is a competitive provider of energy solutions for various customers. We discuss the impact of deregulation on our merchant energy business in Item 1.

Business-Competition section.

Our merchant energy business focuses on delivery of physical, customer-oriented products to producers and consumers, manages the risk and optimizes the value of our owned generation assets, and uses our portfolio management and trading capabilities both to manage risk and to deploy risk capital to generate additional returns. We continue to identify and pursue opportunities which can generate additional returns through portfolio management and trading activities within our business. These opportunities have increased due to the significant growth in scale of our competitive supply operations.

We record merchant energy revenues and expenses in our financial results in different periods depending upon which portion of our business they affect. We discuss our revenue recognition policies in the CriticalAccounting Policies section and in Note 1. We summarize our revenue and expense recognition policies as follows:

+ We record revenues as they are earned and fuel and purchased energy expenses as they are incurred for contracts and activities subject to accrual accounting, including certain load-serving activities.

• Prior to the settlement of the forecasted transaction being hedged, we record changes in the fair value of contracts designated as cash-flow hedges in other comprehensive income to the extent that the hedges are effective. We record the effective portion of the changes in fair value of hedges in earnings in the period the settlement of the hedged transaction occurs. We record the ineffective portion of the changes in fair value of hedges, if any, in earnings in the period in which the change occurs.

• We record changes in the fair value of contracts that are subject to mark-to-market accounting in revenues or fuel and purchased energy expenses in the period in which the change occurs.

Mark-to-market accounting requires us to make estimates and assumptions using judgment in determining the fair value of certain contracts and in recording revenues from those contracts. We discuss the effects of mark-to-market accounting on our results in the Competitive Supply-Mark-to-Market section. We discuss mark-to-market accounting and the accounting policies for the merchant energy business further in the Critical Accounting Policies section and in Note 1.

Our wholesale marketing, risk management, and trading operation actively transacts in energy and energy-related commodities in order to manage our portfolio of energy purchases and sales to customers through structured transactions. As part of these activities we trade energy and energy-related commodities and deploy risk capital in the management of our portfolio in order to earn additional returns. These activities are managed through daily value at risk and stop loss limits and liquidity guidelines, and may have a 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.

40

Results 2006 2005 2004 (In millions)

Revenues

$ 17,166.2 $ 14,622.4

$10,188.3 Fuel and purchased energy expenses (14,256.3)

(12,301.8)

(8,118.1)

Operating expenses (1,549.4)

(1,346.1)

(1,149.9)

Workforce reduction costs (28.2)

(4.4)

(9.7)

Merger-related transaction costs (13.1)

(11.2)

Depreciation, depletion, and amortization (258.7)

(250.4)

(221.9)

Accretion of asset retirement obligations (67.6)

(62.0)

(53.1)

Taxes other than income taxes (120.0)

(106.7)

(83.3)

Gain on sale of gas-fired plants 73.8 Income from Operations 946.7 539.8 $

552.3 Income from continuing operations and before cumulative effects of changes in accounting principles (after-tax) 580.1 359.4 358.0 Income from discontinued operations (after-tax) 186.9 73.8 31.9 Cumulative effects of changes in accounting principles (after-tax)

(7.4)

Net Income 767.0 425.8 389.9 Other Items Included in Operations (after-tax)

Gain on sale of gas-fired plants 47.1 Non-qualifying hedges 39.2 (24.9) 0.2 Merger-related costs (4.3)

(10.4)

Workforce reduction costs (17.0)

(2.6)

(5.9)

Recognition of 2003 synthetic fuel tax credits 35.9 Total Other Items 65.0 (37.9) $

30.2 Certain prior-year amounts have been reclassified to conform with the current year's presentation. Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. Note 3 provides a reconciliation of operating results by segment to our Consolidated Financial Statements.

Revenues and Fuel and Purchased En ergy Expenses Our merchant energy business manages the revenues we realize from the sale of energy to our customers and our costs of procuring fuel and energy. As previously discussed, our merchant energy business uses either accrual or mark-to-market accounting to record our revenues and expenses. Mark-to-market results reflect the net impact of amounts recorded in either revenues or fuel and purchased energy expenses to recognize changes in fair value of derivative contracts subject to mark-to-market accounting during the reporting period.

The difference between revenues and fuel and purchased energy expenses, including all direct expenses, is the gross margin of our merchant energy business, and this measure is a useful tool for assessing the profitability of our merchant energy business. Accordingly, we believe it is appropriate to discuss the operating results of our merchant energy business by analyzing the changes in gross margin between periods. In managing our portfolio, we may terminate, restructure, or acquire contracts.

Such transactions are within the normal course of managing our portfolio and may materially impact the timing of our recognition of revenues, fuel and purchased energy expenses, and cash flows.

We analyze our merchant energy gross margin in the following categories because of the risk profile of each category, differences in the revenue sources, and the nature of fuel and purchased energy expenses. With the exception of a portion of our competitive supply activities that we are required to account for using the mark-to-market method of accounting, all of these activities are accounted for on an accrual basis.

• Mid-Atlantic Region--our fossil, nuclear, and hydroelectric generating facilities and load-serving activities in the PJM Interconnection (PJM) region.

This also includes active portfolio management of the generating assets and other physical and financial contractual arrangements, as well as other PJM competitive supply activities. In addition, due to the expiration of its power purchase agreement, beginning in June 2006 until its sale in December 2006, the results of our University Park generating facility are included with the Mid-Atlantic Region. University Park was previously included in Plants with Power Purchase Agreements.

+ Plants with Power Purchase Agreements-our generating facilities outside the Mid-Atlantic Region with long-term power purchase agreements. As discussed in Note 2, the sale of the High Desert facility resulted in a reclassification of its results of operations to discontinued operations.

• Wholesale Competitive Supply-our marketing, risk management, and trading operation that provides energy products and services primarily to distribution utilities, power generators, and other wholesale customers. We also provide global energy and related services and upstream and downstream natural gas services.

• Retail Competitive Supply--our operation that provides electric and gas energy products and services to commercial, industrial, and governmental customers.

• Other-our investments in qualifying facilities and domestic power projects and our generation operations and maintenance services.

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

Facility High Desert Rio Nogales Holland University Park Big Sandy Wolf Hills Capacity (MV) 830 800 665 300 300 250 Unit Type Combined Cycle Combined Cycle Combined Cycle Peaking Peaking Peaking Location California Texas Illinois Illinois West Virginia Virginia We discuss the sale of these gas-fired generating facilities in Note 2.

41

We provide a summary of our revenues, fuel and purchased energy expenses, and gross margin as follows:

2006 2005 2004 (Dollar amounts in millions)

Revenues:

Mid-Atlantic Region 2,813.5

$ 2,283.9

$ 1,925.6 Plants with Power Purchase Agreements 650.5 665.9 555.3 Competitive Supply Retail 8,014.7 6,942.3 4,280.0 Wholesale 5,612.7 4,672.3 3,353.8 Other 74.8 58.0 73.6 Total

$ 17,166.2

$ 14,622.4

$10,188.3 Fuel and purchased energy expenses:

Mid-Atlantic Region

$ (1,727.6)

$ (1,436.5)

(946.9)

Plants with Power Purchase Agreements (67.9)

(72.5)

(46.4)

Competitive Supply Retail (7,570.2)

(6,668.2)

(4,011.4)

Wholesale (4,890.6)

(4,124.6)

(3,113.4)

Other Total

$ (14,256.3)

$ (12,301.8)

$ (8,118.1)

%/of

%of

%of Total Total Total Gross maegin:

Mid-Atlantic Region

$ 1,085.9 37% $ 847.4 36% $ 978.7 47%

Plants with Power Purchase Agreements 582.6 20 593.4 25 508.9 25 Competitive Supply Retail 444.5 15 274.1 12 268.6 13 Wholesale 722.1 25 547.7 24 240.4 12 Other 74.8 3

58.0 3

73.6 3

Total

$ 2,909.9 100% $ 2,320.6 100% $ 2,070.2 100%

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

Mid-Atlantic Re ion 2006 2005 2004 (In millions)

Revenues

$ 2,813.5

$ 2,283.9

$1,925.6 Fuel and purchased energy expenses (1,727.6)

(1,436.5)

(946.9)

Gross margin

$ 1,085.9 847.4

$ 978.7 The increase of $238.5 million in gross margin in 2006 compared to 2005 is primarily due to approximately $340 million in higher gross margin mostly from favorable portfolio management, including higher margins on existing contracts and new contracts that began in 2006.

Our wholesale marketing, risk management, and trading operation was awarded contracts in 2006 to supply a substantial portion of BGE's standard offer service obligation to residential customers beginning July 1, 2006 through May 31, 2007. The increase in gross margin included higher revenues from BGE of approximately $256 million mostly from these new contracts during 2006 compared to 2005. This increase in gross margin was partially offset by the negative impact of higher expenses from serving the original BGE standard offer service obligation during the first six months of 2006 as variable costs, including emissions and coal, continued to increase. We discuss the expiration of the BGE residential rate freeze in more detail in the Item l--Business-Electric Deregulation and Competition section. Our wholesale marketing, risk management, and trading operation served fixed-price standard offer service obligations to BGE residential customers during the period from July 1, 2000 until July 1, 2006.

These increases in gross margin were partially offset by:

• lower CTC revenues of approximately $64 million due to customers that completed their obligation and the continued decline in the CTC rate, and

+ lower generation at Calvert Cliffs, which resulted in lower gross margin of approximately $37 million, mostly because of a longer planned 2006 refueling outage that included replacement of the reactor vessel head.

The decrease in Mid-Atlantic Region gross margin in 2005 compared to 2004 is primarily due to rising commodity prices and hotter than normal weather during the third quarter of 2005, which resulted in higher load-serving costs. In addition, CTC revenues were $33.1 million lower during 2005 compared to 2004. These decreases in gross margin were partially offset by the absence of coal delivery issues that we experienced in 2004 that had a negative impact in that period.

Plantf with Power Purcrhae Aoreemente 2006 2005 2004 (In millions)

Revenues 650.5 665.9 555.3 Fuel and purchased energy expenses (67.9)

(72.5)

(46.4)

Gross margin 582.6 593.4 508.9 Gross margin from our Plants with Power Purchase Agreements decreased slightly in 2006 compared to the same periods of 2005. This was mostly due to approximately $14 million in lower gross margin from the University Park facility.

As discussed in the Revenues and Fuel and Purchased Energy Expenses section, the University Park power purchase agreement expired in May 2006. As a result, beginning in June 2006 until its sale in December 2006, the results of University Park are included in the Mid-Atlantic Region.

The increase in gross margin from our Plants with Power Purchase Agreements in 2005 compared to 2004 was primarily due to:

• higher gross margin of $71.5 million from Ginna, which was acquired in June 2004. This increase in gross margin at Ginna includes an increase in revenues of $76.9 million, and

• higher gross margin of $39.0 million at our Nine Mile Point facility that benefited from higher generation primarily due to fewer refueling outage days, the absence of an unplanned outage that occurred in January 2004, and higher prices on the portion of our output sold into the wholesale market.

These increases in gross margin were partially offset by

$26.0 million primarily related to changes in commodity prices that had a negative impact on realized hedging activities related to the portion of these facilities sold into the wholesale market.

42

Competitive Supply We analyze our retail accrual, wholesale accrual, and mark-to-market competitive supply activities below.

Retail 2006 2005 2004 (In millions)

Accrual revenues

$ 8,000.6

$ 6,944.2

$ 4,281.0 Fuel and purchased energy expenses (7,577.0)

(6,688.4)

(4,011.4)

Retail accrual activities 423.6 255.8 269.6 Mark-to-market activities 20.9 18.3 (1.0)

Gross margin 444.5 274.1 268.6 The increase in accrual gross margin of $167.8 million from our retail activities during 2006 compared to 2005 is primarily due to:

+ approximately $158 million in higher margins primarily due to higher electric rates and lower costs related to our fixed-price load-serving obligations as a result of milder weather in 2006 compared to the prior year, and

• approximately $13 million in higher gross margin due to higher volumes, including 3.6 million more megawatt hours of electricity and 55 billion cubic feet more of natural gas served to retail customers during the year ended December 31, 2006 compared to 2005.

The decrease in gross margin from our retail competitive supply accrual activities in 2005 compared to 2004 is primarily due to:

+ a combination of higher market prices for electricity, price volatility, and increased customer usage primarily in Texas resulting mostly from extreme summer weather, which increased our cost to serve our fixed-price load-serving obligations,

• the expiration of higher margin contracts, and

• the absence of favorable bankruptcy settlements, which had a positive impact in 2004.

These decreases were partially offset by serving approximately 20 million more megawatt hours in 2005 compared to 2004 mostly due to the growth of this operation.

Wholesale 2006 2005 2004 (In millions)

Accrual revenues

$ 5,232.7

$ 4,281.8

$ 3,253.7 Fuel and purchased energy expenses (4,890.6)

(4,124.6)

(3,113.4)

Wholesale accrual activities 342.1 157.2 140.3 Mark-to-market activities 380.0 390.5 100.1 Gross margin 722.1 547.7 240.4 Our wholesale marketing, risk management, and trading operation had $184.9 million of higher gross margin from accrual activities during 2006 compared to 2005 due to:

• an increase of approximately $145 million primarily due to new contracts entered into during 2006 and higher realized gross margin on existing contracts, and

• an increase of approximately $85 million primarily related to the growth in our coal and natural gas activities.

These increases in gross margin were partially offset by the following:

• a decrease of $24.8 million as a result of the initial public offering of CEP and the sale of our gas-fired plants. As a result of these transactions, forecasted transactions associated with cash-flow hedges were determined to be probable of not occurring, and the associated amounts previously recorded in "Accumulated other comprehensive loss" were reclassified into earnings, and

• a decrease of approximately $20 million from contract restructurings related to unit contingent power purchase agreements during the year ended December 2006 compared to 2005. The termination and sale of these contracts has allowed us to eliminate our exposure to performance risk under these contracts.

Our wholesale marketing, risk management, and trading operation's accrual gross margin was $16.9 million higher in 2005 compared to 2004 primarily due to newly originated and realized business in power, gas, and coal in 2005, including several contract terminations and restructurings. During 2005, we terminated or restructured several in-the-money contracts in exchange for upfront cash payments and a reduction or cancellation of future performance obligations. The termination or restructuring of two contracts allowed us to lower our exposure to performance risk under these contracts, and resulted in the realization of $77.0 million of pre-tax earnings in 2005 that would have been recognized over the life of these contracts. These increases were partially offset by lower gross margins of approximately $60 million mostly due to the absence of several favorable items, including settlements, power prices, and contracts that had a positive impact ir 2004.

Mark-to-Market Mark-to-market results include net gains and losses from origination, trading, and risk management activities for which we use the mark-to-market method of accounting. We discuss these activities and the mark-to-market method of accounting in more detail in the CriticalAccounting Policies section and in Note 1.

As a result of the nature of our operations and the use of mark-to-market accounting for certain activities, mark-to-market earnings will fluctuate. We cannot predict these fluctuations, but the impact on our earnings could be material.

We discuss our market risk in more detail in the Market Risk section. The primary factors that cause fluctuations in our mark-to-market results are:

+ the number, size, and profitability of new transactions including terminations or restructuring of existing contracts,

• the number and size of our open derivative positions, and

+ changes in the level and volatility of forward commodity prices and interest rates.

43

Mark-to-market results were as follows:

2006 2005 2004 (In millions)

Unrealized mark-to-market results Origination gains 13.5

$ 61.6

$ 19.7 Risk management and trading--

mark-to-market Unrealized changes in fair value 387.4 347.2 79.4 Changes in valuation techniques Reclassification of settled contracts to realized (372.1)

(257.7)

(85.4)

Total risk management and trading-mark-to-market 15.3 89.5 (6.0)

Total unrealized mark-to-market*

28.8 151.1 13.7 Realized mark-to-market 372.1 257.7 85.4 Total mark-to-market results

$ 400.9

$ 408.8

$ 99.1

• Total unrealized mark-to-market is the sum of origination transactions and total risk management and trading-mark-to-market.

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

Origination gains represent the initial fair value recognized on these structured transactions. The recognition of origination gains is dependent on the existence of observable market data that validates the initial fair value of the contract.

Origination gains arose primarily from:

• 3 transactions completed in 2006, of which no transaction contributed in excess of $10 million pre-

tax,

• 6 transactions completed in 2005, one of which contributed approximately $35 million pre-tax, and

• 7 transactions completed in 2004, of which no transaction contributed in excess of $10 million pre-tax.

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

Risk management and trading-mark-to-market represents both realized and unrealized gains and losses from changes in the value of our portfolio, including the recognition of gains associated with decreases in the close-out adjustment when we are able to obtain sufficient market price information.

In addition, we use derivative contracts subject to mark-to-market accounting to manage our exposure to changes in market prices primarily as a result of our gas transportation and storage activities, while in general the underlying physical transactions related to our gas activities are accounted for on an accrual basis. We discuss the changes in mark-to-market results below. We show the relationship between our mark-to-market results and the change in our net mark-to-market energy asset on the next page.

Total mark-to-market results decreased $7.9 million in 2006 compared to 2005 because of a decrease in origination gains of $48.1 million, mostly offset by an increase in unrealized changes in fair value of $40.2 million. Unrealized changes in fair value increased primarily due to higher pre-tax gains of approximately $105 million related to the positive impact of certain economic hedges primarily related to gas transportation and storage contracts that do not qualify for or are not designated as cash-flow hedges. These mark-to-market results will be offset as we realize the related accrual load-serving positions in cash.

This increase in unrealized changes in fair value was partially offset by:

• a lower level of gains from risk management and trading-mark-to-market activities of approximately

$45 million, and

• the absence of a $19.5 million favorable impact related to changes in the close-out adjustment in 2006 compared to 2005. The close-out adjustments are determined by the change in open positions, new transactions where we did not have observable market price information, and existing transactions where we have now observed sufficient market price information and/or we realized cash flows since the transactions' inception. We discuss the close-out adjustment in more detail in the Critical Accounting Policies section.

Total mark-to-market results increased $309.7 million in 2005 compared to 2004 due to:

• approximately $260 million primarily related to a higher level of risk management and trading activities.

Increases in our gas and coal activities, higher commodity price volatility, and greater market liquidity resulted in more opportunities to deploy risk capital and to earn additional returns in 2005 compared to 2004. These items resulted in an increased number of transactions that were entered into and realized during 2005 and a higher level of open positions that resulted in increased gains in 2005 compared to 2004. During 2005, slightly more than half of the mark-to-market results were derived from power, approximately one-third from gas, and the remainder from other transactions.

• $41.9 million related to a higher level of origination gains as discussed above, and

• $49.9 million related to the decrease in the close-out adjustment during 2005 compared to the prior year for transactions that we have now observed sufficient market price information and/or we realized cash flows since the transactions' inception.

These increases in mark-to-market results were partially offset by the impact of $41.5 million of higher mark-to-market losses on certain economic hedges that did not qualify for cash-flow hedge accounting treatment. Changing forward prices result in shifting value between accrual contracts and the associated mark-to-market positions of certain contracts in New England that contain fuel adjustment clauses and gas transportation contract hedges, producing a timing difference in the recognition of earnings on these transactions. These 44

mark-to-market hedges are economically effective; however, they do not qualify for cash-flow hedge accounting under SFAS No. 133. As a result, we recorded $41.2 million of pre-tax losses in 2005 and $0.3 million of pre-tax gains in 2004. These mark-to-market gains and losses will be offset as we realize the related accrual load-serving positions in cash.

Mark-to-Market Energy Assets and Liabilities Our mark-to-market energy assets and liabilities are comprised of derivative contracts. While some of our mark-to-market contracts represent commodities or instruments for which prices are available from external sources, other commodities and certain contracts are not actively traded and are valued using other pricing sources and modeling techniques to determine expected future market prices, contract quantities, or both. We discuss our modeling techniques later in this section.

Mark-to-market energy assets and liabilities consisted of the following:

At December 31, 2006 2005 (In millions)

Current Assets

$1,294.8

$1,339.2 Noncurrent Assets 623.4 1,089.3 Total Assets 1,918.2 2,428.5 Current Liabilities 1,071.7 1,348.7 Noncurrent Liabilities 392.4 912.3 Total Liabilities 1,464.1 2,261.0 Net mark-to-market energy asset

$ 454.1 167.5 The following are the primary sources of the change in net mark-to-market energy asset during 2006 and 2005:

Changes in the net mark-to-market energy asset 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.

• Unrealized changes in fair value represent unrealized changes in commodity prices, the volatility of options on commodities, the time value of options, and other valuation adjustments.

• Changes in valuation techniques represent improvements in estimation techniques, including modeling and other statistical enhancements used to value our portfolio to reflect more accurately the economic value of our contracts.

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

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

• Changes in value of exchange-listed futures and options are adjustments to remove unrealized revenue from exchange-traded contracts that are included in risk management revenues. The fair value of these contracts is recorded in "Accounts receivable" rather than "Mark-to-market energy assets" in our Consolidated Balance Sheets because these amounts are settled through our margin account with a third-party broker.

+ Net changes in premiums on options reflects the accounting for premiums on options purchased as an increase in the net mark-to-market energy asset and premiums on options sold as a decrease in the net mark-to-market energy asset.

• Contracts acquired represents the initial fair value of acquired derivative contracts recorded in "Mark-to-market energy assets."

2006 2005 (In millions)

$167.5 Fair value beginning of year Changes in fair value recorded in earnings Origination gains Unrealized changes in fair value Changes in valuation techniques Reclassification of settled contracts to realized Total changes in fair value recorded in earnings Changes in value of exchange-listed futures and options Net change in premiums on options Contracts acquired Other changes in fair value Fair value at end of year 52.4 13.5 387.4 (372.1)

$ 61.6 347.2 (257.7) 28.8 277.8 (29.8) 9.8

$454.1 151.1 (119.9) 79.7 17.4 (13.2)

$ 167.5 45

The settlement terms of our net mark-to-market energy asset and sources of fair value as of December 31, 2006 are as follows:

Settlement Term 2007 2008 2009 2010 2011 2012 Thereafter Fair Value (In millions)

Prices provided by external sources (1)

$192.7

$205.5

$ 6.1

$ 27.0

$ 5.4

$ 8.7

$3.4

$448.8 Prices based on models 30.4 (0.9)

(1.0)

(13.6)

(6.9)

(5.3) 2.6 5.3 Total net mark-to-market energy asset

$223.1

$204.6

$ 5.1

$ 13.4

$(1.5)

$ 3.4

$6.0

$454.1 (1)

Includes contracts actively quoted and contracts valued from other external sources.

We manage our mark-to-market risk on a portfolio basis based upon the delivery period of our contracts and the individual components of the risks within each contract.

Accordingly, we record and manage the energy purchase and sale obligations under our contracts in separate components based upon the commodity (e.g., electricity or gas), the product (e.g., electricity for delivery during peak or off-peak hours), the delivery location (e.g., by region), the risk profile (e.g., forward or option), and the delivery period (e.g., by month and year).

Consistent with our risk management practices, we have presented the information in the table above based upon the ability to obtain reliable prices for components of the risks in our contracts from external sources rather than on a contract-by-contract basis. Thus, the portion of long-term contracts that is valued using external price sources is presented under the caption "prices provided by external sources." This is consistent with how we manage our risk, and we believe it provides the best indication of the basis for the valuation of our portfolio.

Since we manage our risk on a portfolio basis rather than contract-by-contract, it is not practicable to determine separately the portion of long-term contracts that is included in each valuation category. We describe the commodities, products, and delivery periods included in each valuation category in detail below.

The amounts for which fair value is determined using prices provided by external sources represent the portion of forward, swap, and option contracts for which price quotations are available through brokers or over-the-counter transactions.

The term for which such price information is available varies by commodity, region, and product. The fair values included in this category are the following portions of our contracts:

• forward purchases and sales of electricity during peak and off-peak hours for delivery terms primarily through 2010, but up to 2012, depending upon the region,

• options for the purchase and sale of electricity during peak hours for delivery terms through 2008, depending upon the region,

• forward purchases and sales of electric capacity for delivery terms primarily through 2007, but up to 2008, depending on the region,

• forward purchases and sales of natural gas, coal, and oil for delivery terms through 2011, and

• options for the purchase and sale of natural gas, coal, and oil for delivery terms through 2008.

The remainder of the net mark-to-market energy asset is valued using models. The portion of contracts for which such techniques are used includes standard products for which external prices are not available and customized products that are valued using modeling techniques to determine expected future market prices, contract quantities, or both.

Modeling techniques include estimating the present value of cash flows based upon underlying contractual terms and incorporate, where appropriate, option pricing models and statistical and simulation procedures. Inputs to the models include:

+ observable market prices,

• estimated market prices in the absence of quoted market prices,

• the risk-free market discount rate,

• volatility factors,

• estimated correlation of energy commodity prices, and

• expected generation profiles of specific regions.

Additionally, we incorporate counterparty-specific credit quality and factors for market price and volatility uncertainty and other risks in our valuation. The inputs and factors used to determine fair value reflect management's best estimates.

The electricity, fuel, and other energy contracts we hold have varying terms to maturity, ranging from contracts for delivery the next hour to contracts with terms often years or more. Because an active, liquid electricity futures market comparable to that for other commodities has not developed, the majority of contracts used in the wholesale marketing, risk management, and trading operation are direct contracts between market participants and are not exchange-traded or financially settling contracts that can be readily liquidated in their entirety through an exchange or other market mechanism.

Consequently, we and other market participants generally realize the value of these contracts as cash flows become due or payable under the terms of the contracts rather than through selling or liquidating the contracts themselves.

Consistent with our risk management practices, the amounts shown in the table above as being valued using prices from external sources include the portion of long-term contracts for which we can obtain reliable prices from external sources. The remaining portions of these long-term contracts are shown in the table as being valued using models. In order to realize the entire value of a long-term contract in a single transaction, we would need to sell or assign the entire contract.

If we were to sell or assign any of our long-term contracts in their entirety, we may realize an amount different from the value reflected in the table. However, based upon the nature of the wholesale marketing, risk management, and trading operation, we generally expect to realize the value of these contracts, as well as any contracts we may enter into in the future to manage our risk, over time as the contracts and related hedges settle in accordance with their terms. In general, we do not expect to realize the value of these contracts and related hedges by selling or assigning the contracts themselves in total.

46

The fair values in the table represent expected future cash flows based on the level of forward prices and volatility factors as of December 31, 2006 and could change significantly as a 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.

Management uses its best estimates to determine the fair value of commodity and derivative contracts it holds and sells.

These estimates consider various factors including closing exchange and over-the-counter price quotations, time value, volatility factors, and credit exposure. However, future market prices and actual quantities will vary from those used in recording mark-to-market energy assets and liabilities, and it is possible that such variations could be material.

Risk Management Assets and Liabilities We record derivatives that qualify' for designation as hedges under SFAS No. 133 in "Risk management assets and liabilities" in our Consolidated Balance Sheets. Our risk management assets and liabilities consisted of the following:

At December 31, 2006 2005 (In millions)

Current Assets 261.7

$1,244.3 Noncurrent Assets 325.7 626.0 Total Assets 587.4 1,870.3 Current Liabilities 1,340.0 483.5 Noncurrent Liabilities 707.3 1,035.5 Total Liabilities 2,047.3 1,519.0 Net risk management (liability) asset

$(1,459.9)

$ 351.3ý The decrease in our net risk management asset of $1.8 billion since December 31, 2005 was due primarily to decreases in power prices that reduced the fair value of our cash-flow hedge positions and the settlement of cash-flow hedges during 2006. A decrease in the fair value of our cash-flow hedges indicates an increase in value of the accrual positions to which these hedges are related.

Other 2006 2005 2004 (In millions)

Revenues

$74.8

$58.0

$73.6 Our merchant energy business holds up to a 50% voting interest in 24 operating domestic energy projects that consist of electric generation, fuel processing, or fuel handling facilities.

Of these 24 projects, 17 are "qualify'ing facilities" that receive certain exemptions based on the facilities' energy source or the use of a cogeneration process. Earnings from our investments were $13.8 million in 2006, $3.6 million in 2005, and

$18.0 million in 2004.

Our investment in qualifying facilities and domestic power projects consisted of the following:

Book Value at December 3 1, 2006 2005 (In millions)

Project Type Coal

$125.7

$127.8 Hydroelectric 55.1 55.9 Geothermal 40.5 43.7 Biomass 46.6 48.0 Fuel Processing 33.7 23.8 Solar 7.0 7.0 Total

$308.6

$306.2 We believe the current market conditions for our equity-method investments that own geothermal, coal, hydroelectric, and fuel processing projects provide sufficient positive cash flows to recover our investments. We continuously monitor issues that potentially could impact future profitability of these investments, including environmental and legislative initiatives. We discuss certain risks and uncertainties in more detail in our Forward Looking Statements and Item ]A. Risk Factors sections. However, should future events cause these investments to become uneconomic, our investments in these projects could become impaired under the provisions of APB No. 18.

The ability to recover our equity-and cost-method investments that own biomass and solar projects is partially dependent upon subsidies from the State of California. Under the California Public Utility Act, subsidies currently exist in that the California Public Utilities Commission (CPUC) requires load-serving entities to identify a separate rate component to be collected from customers to fund the development of renewable resources technologies, including solar, biomass, and wind facilities. In addition, legislation in California requires that each load-serving entity increase its total procurement of eligible renewable energy resources by at least one percent per year so that 20% of its retail sales are procured from eligible renewable energy resources by 2017.

The legislation also requires the California Energy Commission to award supplemental energy payments to load-serving entities to cover above-market costs of renewable energy.

Given the need for electric power and the desire for renewable resource technologies, we believe California will continue to subsidize the use of renewable energy to make these projects economical to operate. However, should the California legislation fail to adequately support the renewable energy initiatives, our equity-method investments in these types of projects could become impaired under the provisions of APB No. 18, and any losses recognized could be material.

Operating Expene Our merchant energy business operating expenses increased

$203.3 million in 2006 compared to 2005 mostly due to the following:

• an increase of $139.2 million at our competitive supply operations primarily related to higher labor and benefit costs and the impact of inflation on other costs, 47

• an increase of $22.7 million at our upstream gas operations, primarily due to acquisitions made in June 2005, and

• an increase of approximately $18 million at our generating facilities, which includes higher expenses associated with longer planned outages, offset in part by lower expenses that resulted from our productivity initiatives.

Our merchant energy business operating expenses increased $196.2 million in 2005 compared to 2004 mostly due to the following:

+ an increase of $101.8 million at our wholesale marketing, risk management, and trading operation due to an increase in compensation and benefit costs including our expanding gas and coal operations,

• an increase of $81.5 million from Ginna, which was acquired in June 2004,

• an increase of $26.5 million at our retail operation primarily related to a $10.8 million increase in uncollectible expenses and a $8.7 million increase in aggregator fees,

• an increase of $17.3 million at our gas-fired generating facilities primarily due to increased corporate overhead expenses, and

• an increase of $13.0 million at Calvert Cliffs primarily due to an increase in corporate overhead expenses, partially offset by fewer employees and a shorter refueling outage in 2005.

These increases in expense were partially offset by lower operating expenses of $56.5 million at Nine Mile Point primarily due to lower refueling outage expenses and a lower number of employees and contractors.

Workforce Reduction Costs Our merchant energy business recognized expenses associated with our workforce reduction efforts as discussed in more detail in Note 2.

Merger-Related Costs We discuss costs related to the merger with FPL Group, which has been terminated, in Note 15.

Depreciation, Depletion, and Amortization Expense Merchant energy depreciation, depletion, and amortization expenses increased $28.5 million in 2005 compared to 2004 mostly due to:

• $10.2 million related to our South Carolina synthetic fuel facility,

• $8.8 million related to Ginna, which was acquired in June 2004, and

• $6.0 million increase related to our 2005 investments in gas producing facilities.

Accretion ofAsset Retirement Obligations The increase in accretion expense of $8.9 million in 2005 compared to 2004 is primarily due to Ginna which was acquired in June 2004 and the impact of normal compounding.

Taxes Other Than Income Taxes Merchant energy taxes other than income taxes increased

$13.3 million in 2006 compared to 2005 mostly due to

$5.3 million related to higher gross receipts taxes at our retail competitive supply operation and $3.1 million related to our working interests in gas producing properties.

Merchant energy taxes other than income taxes increased

$23.4 million in 2005 compared to 2004 mostly due to

$19.6 million related to higher gross receipts taxes at our retail electric operation and $4.0 million related to property taxes for Ginna.

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

Business-Electric Business section.

Results 2006 2005 2004 (In millions)

Revenues

$ 2,115.9

$ 2,036.5

$ 1,967.7 Electricity purchased for resale expenses (1,167.8)

(1,068.9)

(1,034.0)

Operations and maintenance expenses (351.3)

(318.4)

(304.2)

Merger-related costs (3.3)

(4.0)

Depreciation and amortization (181.5)

(185.8)

(194.2)

Taxes other than income taxes (134.9)

(135.3)

(132.8)

Income from Operations 277.1 324.1 302.5 Net Income 120.2 149.4 131.1 Other Items Included in Operations (afler-tax)

Merger-related costs (0.8)

(3.7)

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

Net income from the regulated electric business decreased

$29.2 million in 2006 compared to 2005 mostly because of the following:

• increased operations and maintenance expenses of

$19.9 million after-tax mostly due to higher labor and benefit costs and incremental costs associated with 2006 storms, and

+ decreased revenues less electricity purchased for resale expenses of $11.8 million after-tax.

Net income from the regulated electric business increased

$18.3 million in 2005 compared to 2004 mostly because of the following:

• increased revenues less electricity purchased for resale expenses of $20.7 million after-tax,

+ decreased depreciation and amortization expense of

$5.1 million after-tax, and

• increased other income primarily due to gains on the sales of land of $3.6 million after-tax.

48

These favorable results were partially offset by the following:

• increased operations and maintenance expenses of

$8.7 million after-tax mostly due to higher labor and benefit costs and the impact of inflation on other costs, and

• merger-related transaction costs of $3.7 million after-tax.

Electric Revenues The changes in electric revenues in 2006 and 2005 compared to the respective prior year were caused by:

Distribution volumes Standard offer service Rate stabilization credits Total change in electric revenues from electric system sales Other Total chanize in electric revenues 2006 2005 (In millions)

$ (40.9)

$21.3 433.7 38.8 (321.9) 70.9 60.1 8.5 8.7 79.4

$68.8 Distribution Volumes Distribution volumes are the amount of electricity that BCE delivers to customers in its service territory.

The percentage changes in our electric system distribution volumes, by type of customer, in 2006 and 2005 compared to the respective prior year were:

2006 2005 Residential (6.4)%

3.4%

Commercial (0.6) 5.1 Industrial (7.5)

(6.4)

In 2006, we distributed less electricity to residential customers mostly due to milder weather and decreased usage per customer, partially offset by an increased number of customers. We distributed less electricity to commercial customers mostly due to milder weather, partially offset by an increased number of customers and increased usage per customer. We distributed less electricity to industrial customers mostly due to decreased usage per customer.

In 2005, we distributed more electricity to residential customers compared to 2004 mostly due to warmer summer weather and an increased number of customers. We distributed more electricity to commercial customers mostly due to increased usage per customer, an increased number of customers, and warmer summer weather. We distributed less electricity to industrial customers mostly due to decreased usage per customer.

Standard 04Zer Service BCE provides standard offer service for customers that do not select an alternative supplier. We discuss the provisions of Maryland's Senate Bill 1 related to residential electric rates in the Item 1. Business-Electric Regulatory Matters and Competition section.

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.

Standard offer service revenues increased in 2005 compared to 2004 mostly because of increased standard offer service volumes to residential customers and increased standard offer service rates for all customers partially offset by lower standard offer service volumes associated with those commercial and industrial customers that elected alternative suppliers beginning July 1, 2004.

Rate Stabilization Credits As a result of Senate Bill 1, we are required to defer a portion of the full market rate increase during the eleven month period from July 1, 2006 until May 31, 2007 for recovery in the future. Therefore, the increase in standard offer service revenues is partially offset by rate stabilization credits in order to reduce rates for residential customers from market price to the approved increase of 15% in Senate Bill 1.

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

2006 2005 2004 (in millions)

Actual costs

$1,489.7

$1,068.9

$ 1,034.0 Deferral under rate stabilization plan (321.9)--

Electricity purchased for resale expenses

$1,167.8

$1,068.9

$1,034.0 Actual Costs BCE's actual costs for electricity purchased for resale increased

$420.8 million in 2006 compared to 2005 due to higher contract prices to purchase electricity resulting from the expiration of contracts that were executed in 2000 as part of the implementation of electric deregulation in Maryland, partially offset by lower standard offer service volumes.

BCE's actual costs for electricity purchased for resale increased $34.9 million in 2005 compared to 2004 mostly because of increased standard offer service volumes to residential customers and higher costs to serve all standard offer service customers, partially offset by lower electricity purchased for resale expenses associated with commercial and industrial customers that elected alternative suppliers beginning July 1, 2004.

Deferral under Rate Stabilization Plan We defer the difference between our actual costs of electricity purchased for resale and what we are allowed to bill customers under Senate Bill 1. 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 BCE' S, Consolidated Balance Sheets.

We discuss the provisions of Senate Bill 1 related to residential 49

electric rates in the Item 1. Business-Electric Regulatory Matters and Competition section.

Electric Operations and Maintenance Ex~penses Regulated electric operations and maintenance expenses 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 restoration expenses associated with 2006 storms.

Regulated electric operations and maintenance expenses increased $14.2 million in 2005 compared to 2004 mostly due to higher labor and benefit costs and the impact of inflation on other costs.

Merger-Related Transaction Costs We discuss costs related to the merger with FPL Group, which has been terminated, in Note 15.

Electric Depreciation andAinortization Expense Regulated electric depreciation and amortization expense decreased $4.3 million in 2006 compared to 2005 mostly because of the absence of $6.9 million amortization expense associated with certain software, partially offset by $3.0 million related to additional property placed in service.

Regulated electric depreciation and amortization expense decreased $8.4 million in 2005 compared to 2004 mostly because of the absence of $12.6 million of accelerated amortization expense associated with certain information technology assets replaced in 2004, partially offset by

$4.2 million related to additional property placed in service.

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

Business-Gas Business section.

Results 2006 2005 2004 (In millions)

Revenues

$ 899.5

$ 972.8

$ 757.0 Gas purchased for resale expenses (581.5)

(687.5)

(484.3)

Operations and maintenance expenses (144.8)

(131.8)

(123.6)

Merger-related costs (1.4)

(1.4)

Depreciation and amortization (46.0)

(46.6)

(48.1)

Taxes other than income taxes (33.8)

(33.1)

(32.1)

Income from Operations 92.0

$ 72.4

$ 68.9 Net Income 37.0

$ 26.7

$ 22.2 Other Items Included in Operations (after-tax)

Merger-related costs (0.4)

(1.3)

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

Net income from the regulated gas business increased

$10.3 million in 2006 compared to 2005 mostly due to increased revenues less gas purchased for resale expenses of

$19.8 million after-tax, which was primarily due to the increase in gas base rates that was approved by the Matyland PSC in December 2005. This increase was partially offset by higher operations and maintenance expenses of $7.9 million after-tax.

Net income from our regulated gas business was about the same in 2005 compared to 2004.

Gas Revenues The changes in gas revenues in 2006 and 2005 compared to the respective prior year were caused by:

2006 2005 (in millions)

Distribution volumes

$ (38.0) 3.9 Base rates 33.4 2.6 Revenue decoupling 28.4 2.5 Gas cost adjustments (112.3) 129.1 Total change in gas revenues from gas system sales (88.5) 138.1 Off-system sales 13.9 77.5 Other 1.3 0.2 Total change in gas revenues

$ (73.3)

$215.8 Distribution Volumes The percentage changes in our distribution volumes, by type of customer, in 2006 and 2005 compared to the respective prior year were:

Residential Commercial Industrial 2006 (17.0)%

(13.3) 3.2 2005 (1-3)%

(9.0) 33.6 In 2006, we distributed less gas to residential and commercial customers compared to 2005 mostly due to milder weather and decreased usage per customer, partially offset by an increased number of customers. We distributed more gas to industrial customers mostly due to increased usage per customer.

In 2005, we distributed less gas to residential and commercial customers compared to 2004 mostly due to decreased usage per customer partially offset by colder winter weather and an increased number of customers. We distributed more gas to industrial customers mostly due to increased usage per customer.

Base Rates In December 2005, the Matyland PSC issued an order granting BGE a $35.6 million annual increase in its gas base rates. In December 2006, the Baltimore City Circuit Court upheld the rate order. However, certain parties have filed an appeal with the Court of Special Appeals. We cannot provide assurance that the Matyland PSC's order will not be reversed in whole or in part or that certain issues will not be remanded to the Maryland PSC for reconsideration.

50

Revenue Decouplinp, The Maryland PSC allows us to record a monthly adjustment to our gas distribution revenues to eliminate the effect of abnormal weather patterns on our gas distribution volumes.

This means our monthly gas distribution revenues are based on weather that is considered "normal" for the month and, therefore, are not affected by actual weather conditions.

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

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

Gas cost adjustment revenues decreased in 2006 compared to 2005 because we sold less gas at lower prices.

Gas cost adjustment revenues increased in 2005 compared to 2004 because we sold more gas at higher prices.

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

Revenues from off-system gas sales increased in 2006 compared to 2005 because we sold more gas, partially offset by lower prices.

Revenues from off-system gas sales increased in 2005 compared to 2004 because we sold more gas at higher prices.

Gas Purchased For Resale Expenses Gas purchased for resale expenses include the cost of gas purchased for resale to our customers and for off-system sales.

These costs do not include the cost of gas purchased by delivery service only customers.

Gas purchased for resale expenses decreased

$106.0 million in 2006 compared to 2005 because we purchased less gas at lower prices.

Gas purchased for resale expenses increased in 2005 compared to 2004 because we purchased more gas at higher prices.

Gas Operations and Maintenance Expenses Regulated gas operations and maintenance expenses increased $13.0 million in 2006 compared to 2005 mostly due to higher labor and benefit costs and the impact of inflation on other costs.

Regulated gas operations and maintenance expenses increased $8.2 million in 2005 compared to 2004 mostly due to higher compensation and benefit costs and the impact of inflation on other costs.

Merger-Related Transaction Costs We discuss costs related to the merger with FPL Group, which has been terminated, in Note 15.

Other Nonregulated Businesses Results 2006 2005 2004 (In millions)

Revenues

$ 231.0

$ 207.0

$ 201.1 Operating expenses (173.1)

(156.2)

(180.0)

Merger-related costs (0.5)

(0.4)

Depreciation and amortization (37.7)

(40.2)

(24.2)

Taxes other than income taxes (2.0)

(2.0)

(2.4)

Income (Loss) from Operations 17.7 8.2 (5.5)

Income (Loss) from continuing operations and before cumulative effects of changes in accounting principles (after-tax) 11.3 0.4

$ (12.9)

Income from discontinued operations (after-tax) 0.9 20.6 9.4 Cumulative effects of changes in accounting principles (after-tax) 0.2 Net Income (Loss) 12.2

$ 21.2 (3.5)

Other Items Included In Operations (after-tax)

Merger-related costs (0.2)

(0.2)

Certain prior-year amounts have been reclassified to conform with the current year's presentation. Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. Note 3 provides a reconciliation ofoperating results by segment to our Consolidated Financial Statements.

Net income from our other nonregulated businesses decreased

$9.0 million in 2006 compared to 2005 primarily due to a

$19.7 million decrease in income from discontinued operations, partially offset by a $10.7 million increase in net income from our remaining other nonregulated businesses, including an increase in net income from our continued liquidation of our real estate investments.

Net income from our other nonregulated businesses increased $24.7 million in 2005 compared to 2004 primarily due to:

• a $16.1 million after-tax gain on sale of Constellation Power International Investments, Ltd., which held our other nonregulated international investments, in October 2005, and

• a $13.2 million after-tax increase in net income from the continued liquidation of our financial investments.

51

These increases were partially offset by $4.9 million lower net income from our other nonregulated international investments due to their sale in October 2005. We discuss the sale of our other nonregulated international investments in more detail in Note 2.

In 2001, we decided to sell certain non-core assets and accelerate the exit strategies on other assets that we continued to hold and own. While our intent is to dispose of these remaining non-core assets, market conditions and other events beyond our control may affect the actual sale of these assets. In addition, a future decline in the fair value of these assets could result in losses that could have a material impact on our financial results.

Consolidated Nonoperating Income and Expenses Gain on Initial Public Offering of CEP LLC In November 2006, CEP, a limited liability company formed by Constellation Energy, completed an initial public offering of 5.2 million common units at $21 per unit. As a result of the initial public offering of CEP, we recognized a pre-tax gain of

$28.7 million, or $17.9 million after recording deferred taxes on the gain. We discuss the initial public offering of CEP in more detail in Note 2.

Other Income Other income increased $40.0 million in 2005 compared to 2004 primarily because of higher interest and investment income due to a higher cash balance and higher decommissioning trust asset earnings and gains on the sales of land at BGE.

Total other income at BGE increased $12.3 million in 2005 compared to 2004 primarily due to approximately

$7 million of gains on the sales of land.

Fixed Charges Total fixed charges increased $18.5 million 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 decreased $16.6 million in 2005 compared to 2004 mostly because of the benefit of lower interest rates due to interest rate swaps entered into during the third quarter of 2004 and a lower level of debt outstanding. We discuss the interest rate swaps in more detail in Note 13.

Total fixed charges for BGE increased $9.1 million in 2006 compared to 2005 mostly because of a higher level of debt outstanding. Total fixed charges for BGE decreased

$2.7 million in 2005 compared to 2004 mostly because of a lower level of debt outstanding.

Income Taxes The differences in income taxes result from a combination of the changes in income and the impact of the recognition of tax credits on the effective tax rate. We include an analysis of the changes in the effective tax rate in Note 10.

Total income taxes increased $187.1 million in 2006 compared to 2005 primarily due to a higher level of pre-tax income, including the gain on sale of gas-fired plants and the gain on initial public offering of CEP, as well as a decrease in synthetic fuel tax credits. We discuss all of these events in the Significant Events section.

Total income taxes increased $45.5 million in 2005 compared to 2004 primarily due to the recognition of $35.9 million in synthetic fuel tax credits in 2004 related to 2003 production.

Total income taxes for BGE decreased $17.7 million in 2006 compared to 2005 mostly due to lower pre-tax income.

Total income taxes for BGE increased $17.4 million in 2005 compared to 2004 mostly due to higher pre-tax income.

Defined Benefit Obhlgations We expect to contribute $125 million to our pension plans in 2007.

At December 31, 2006, we recorded a net after-tax charge to "Accumulated other comprehensive income" of $93.9 million. This net after-tax charge was a result of the following:

• reducing our additional minimum pension liability, which resulted in an increase to "Accumulated other comprehensive income" of $75.6 million, and

• the adoption of SFAS No. 158, Employers'Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 106 and 132(R), which resulted in a decrease to "Accumulated other comprehensive income" of $169.5 million.

SFAS No. 158, discussed in Note 1, creates the potential for additional volatility in accumulated other comprehensive income. We discuss our defined benefit obligations in more detail in Note 7.

52

Financial Condition Cash Flows The following table summarizes our 2006 cash flows by business segment, as well as our consolidated cash flows for 2006, 2005, and 2004.

2006 Segment Cash Flows Consolidated Cash Flows Merchant Regulated Other 2006 2005 2004 (In millions)

Operating Activities Net income

$ 767.0

$ 157.2

$ 12.2 936.4 623.1 539.7 Non-cash adjustments to net income 160.3 13.9 21.2 195.4 746.0 905.3 Changes in working capital (858.0) 108.4 77.7 (671.9)

(775.3)

(319.6)

Defined benefit obligations*

40.5 3.4 (13.6)

Other (0.8)

(30.1) 55.8 24.9 30.0 (25.0)

Net cash provided by operating activities 68.5 249.4 166.9 525.3 627.2 1,086.8 Investing Activities Investments in property, plant and equipment (613.4)

(332.5)

(17.0)

(962.9)

(760.0)

(703.6)

Asset acquisitions and business combinations, net of cash acquired (137.6)

(137.6)

(237.2)

(457.3)

Investment in nuclear decommissioning trust fund securities (394.6)

(394.6)

(370.8)

(424.2)

Proceeds from nuclear decommissioning trust fund securities 385.8 385.8 353.2 402.2 Net proceeds from sale of gas-fired plants and discontinued operations 1,630.7 1,630.7 289.4 72.7 Issuances of loans receivable (65.4)

(65.4)

(82.8)

Sale of investments and other assets 23.4 20.5 43.9 14.4 36.1 Contract and portfolio acquisitions (2.3)

(2.3)

(336.2)

Other investments 57.0 10.3 (4.8) 62.5 (44.0)

(78.6)

Net cash orovided by (used in) investing activities 883.6 (322.2)

(1.3) 560.1 (1.174.0)

(1.152.7)

Cash flows from operating activities less cash flows from investing activities Financing Activities*

Net issuance (repayment) of debt Proceeds from issuance of common stock Common stock dividends paid Proceeds from initial public offering of CEP LLC Proceeds from contract and portfolio acquisitions Other Net cash provided by financing activities Net increase (decrease) in cash and cash equivalents 952.1

$ (72.8)

$ 165.6 1,085.4 (546.8)

(65.9) 242.2 84.4 (264.0) 101.3 221.3 5.5 390.7 1,476.1 (339.6) 96.9 (228.8) 1,026.9 98.1 653.5 106.7 (152.8) 293.9 (189.7) 117.5 (18.0) 50.9 (15.0)

• Items are not allocated to the business segments because they are managed for the company as a whole.

Cash Flows from Operating Activities Cash provided by operating activities was $525.3 million in 2006 compared to $627.2 million in 2005. This

$101.9 million decrease was primarily due to a decrease in non-cash adjustments to net income in 2006, partially offset by favorable changes in net income and working capital.

Non-cash adjustments to net income decreased by

$550.6 million in 2006 compared to 2005 primarily due to the change in deferred fuel costs of $336.6 million related mostly to the deferred recovery of electricity purchased for resale under the BGE rate stabilization plan. We discuss the rate stabilization plan in more detail in the Item 1-.Business--

Electric Regulatory Matters and Competition section and Note 1.

In addition, our gains on the sale of gas-fired plants and discontinued operations increased $177.6 million in 2006 compared to 2005. We discuss this in more detail in Note 2.

Changes in working capital had a negative impact of

$671.9 million on cash flow from operations in 2006 compared to a negative impact of $775.3 million in 2005. The negative impact of $671.9 million related to working capital was primarily due to the commodity price environment and increased risk management and trading activities that resulted in an increase of approximately $630 million in net cash collateral requirements, primarily for requirements on exchange-settled transactions. This increase in cash collateral requirements was accompanied by a decrease in our letters of credit requirements.

Cash provided by operating activities was $627.2 million in 2005 compared to $1,086.8 million in 2004. Net income was higher by $83.4 million in 2005 compared to 2004. Non-cash adjustments to net income were $159.3 million lower in 2005 compared to 2004. The decrease in non-cash adjustments 53

to net income was primarily due to the reclassification of

$72.6 million of proceeds from derivative power sales contracts as financing activities under SFAS No. 149, Amendment of FASB Statement No. 133 on Derivative and Hedging Activities and $63.9 million related to the impact of discontinued operations.

Changes in working capital had a negative impact of

$775.3 million on cash flow from operations in 2005 compared to a negative impact of $319.6 million in 2004. The decrease of $455.7 million was due to a $598 million unfavorable change in working capital primarily related to our accounts receivable, accounts payable, and fuel stocks mostly due to higher commodity prices, increased value of emissions credits, and business growth. This was partially offset by an increase of $142 million of net cash collateral received, which was also due to higher commodity prices.

Cash Flo ws from In vesting A cavities Cash provided by investing activities was $560.1 million in 2006 compared to cash used in investing activities

$1,174.0 million in 2005. The $1,734.1 million favorable change in 2006 compared to 2005 was primarily due to the increase in proceeds from sale of gas-fired plants and discontinued operations of $1,341.3 million and a decrease of

$333.9 million in cash paid for contract and portfolio acquisitions. We discuss contract and portfolio acquisitions in more detail below.

Cash used in investing activities was $1,174.0 million in 2005 compared to $1,152.7 million in 2004. The slight increase in cash used in investing activities was mostly due to

$336.2 million of cash paid for contract and portfolio acquisitions and $82.8 million in issuances of loans receivable related primarily to a customer contract restructuring. We discuss contract and portfolio acquisitions in more detail below, and the customer contract restructuring is discussed in more detail in Note 4. These increases in cash used in 2005 compared to 2004 were partially offset by less cash paid for asset acquisitions and business combinations of $220.1 million in 2005 compared to 2004 and an increase in cash proceeds from the sale of discontinued operations of $216.7 million, primarily due to the sale of Oleander and our other nonregulated international investments in 2005 as discussed in more detail in Note 2.

Cash Flows from FinancingActivities Cash provided by financing activities was $390.7 million in 2006 compared to $653.5 million in 2005. The decrease of

$262.8 million in cash provided in 2006 compared to 2005 was primarily due to a decrease in proceeds from acquired contracts of $805.6 million, a decrease in other financing activities of $92.6 million, and a $35.2 million increase in our dividends paid in 2006 compared to 2005. We discuss the proceeds from acquired contracts below. These decreases were partially offset by a net increase in cash related to changes in short-term borrowings and long-term debt of $581.8 million and $101.3 million in proceeds from the initial public offering of CEP.

Cash provided by financing activities was $653.5 million in 2005 compared to $50.9 million in 2004. The increase in 2005 compared to 2004 was mostly due to an increase in proceeds from contract and portfolio acquisitions of

$909.4 million. We discuss proceeds from contract and portfolio acquisitions in more detail below. This increase in cash provided by financing activities was partially offset by a reduction in proceeds from issuances of common stock, an increase in cash used for repayments of debt, and higher dividend payments in 2005 compared to 2004.

Contract and Portfolio Acquisitions During 2006, 2005, and 2004, our merchant energy business acquired several pre-existing energy purchase and sale agreements, which generated significant cash flows at the inception of the contracts. These agreements had contract prices that differed from market prices at closing, which resulted in cash payments from the counterparty at the acquisition of the contract. We received net cash of

$219.0 million in 2006, $690.7 million in 2005, and $117.5 million in 2004 for various contract and portfolio acquisitions.

We reflect the underlying contracts on a gross basis as assets or liabilities in our Consolidated Balance Sheets depending on whether they were at above-or below-market prices at closing; therefore, we have also reflected them on a gross basis in cash flows from investing and financing activities in our Consolidated Statements of Cash Flows as follows:

Year ended December 31, 2006 2005 2004 (In millions)

Financing activities-proceeds from contract and portfolio acquisitions

$221.3

$1,026.9

$117.5 Investing activities-contract and portfolio acquisitions (2.3)

(336.2)

Cash flows from contract and portfolio acquisitions

$219.0 $ 690.7

$117.5 We record the proceeds we receive to acquire energy purchase and sale agreements as a financing cash inflow because it constitutes a prepayment for a portion of the market price of energy, which we will buy or sell over the term of the agreements and does not represent a cash inflow from current period operating activities. For those acquired contracts that are derivatives, we record the ongoing cash flows related to the contract with the counterparties as financing cash inflows in accordance with SFAS No. 149.

We discuss certain of these contract and portfolio acquisitions in more detail in Note 4 and Note 5.

Security Ratings Independent credit-rating agencies rate Constellation Energy's and BGE's fixed-income securities. The ratings indicate the agencies' assessment of each company's ability to pay interest, distributions, dividends, and principal on these securities.

These ratings affect how much it will cost each company to sell these securities. Generally, the better the rating, the lower the cost of the securities to each company when they sell them.

The factors that credit rating agencies consider in establishing Constellation Energy's and BGE's credit ratings include, but are not limited to, cash flows, liquidity, business 54

risk profile, and the amount of debt as a component of total capitalization.

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

Standard

& Poors Rating Grout)

Moody's Investors Service Fitch-Ratines Constellation Energy Commercial Paper Senior Unsecured Debt BGE Commercial Paper Mortgage Bonds Senior Unsecured Debt Trust Preferred Securities Preference Stock A-2 P-2 F-2 BBB+

Baal BBB+

A-2 A

BBB+

BBB-BBB-P-2 Baal Baa2 Baa3 Bal F-2 A

A-BBB+

BBB+

Available Sources of Funding We continuously monitor our liquidity requirements and believe that our credit facilities and access to the capital markets provide sufficient liquidity to meet our business requirements.

We discuss our available sources of funding in more detail below.

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 subsidiaries. At December 31, 2006, we had approximately

$4,550 million of credit under several facilities. These facilities include:

+ a $1.0 billion 364-day credit facility expiring October 2007,

• a $200.0 million 364-day credit facility expiring December 2007,

• a $1.5 billion five-year revolving credit facility that expires in March 2010,

• a $1.1 billion five-year revolving credit facility that expires in November 2010, and

• a $750.0 million five-year revolving credit facility that expires in November 2010.

We enter into these facilities to ensure adequate liquidity to support our operations. Currently, we use the facilities to issue letters of credit primarily for our merchant energy business. Additionally, we can borrow directly from the banks or use the facilities to allow the issuance of commercial paper with the exception of the $1.0 billion 364-day facility, which only supports $500.0 million of letters of credit and the $200.0 million 364-day facility, which only supports letters of credit.

These revolving credit facilities allow the issuance of letters of credit up to $4,050 million. At December 31, 2006, letters of credit that totaled $1,648 million were issued under all of our facilities, which results in approximately $2.9 billion of unused credit facilities.

We expect to fund future acquisitions with an overall goal of maintaining a strong investment grade credit profile.

Merchant Energy In November 2006, we completed the initial public offering of CEP and received $101.3 million of net cash proceeds. We discuss the initial public offering in more detail in Note 2. We may obtain additional cash by completing sales of our other natural gas properties. Our ability to complete these sales will depend on market conditions, and we cannot give assurances that these sales could be completed.

On October 31, 2006, CEP entered into a $200.0 million secured revolving credit facility. The credit facility will mature on October 31, 2010. We discuss this long-term facility in more detail in Note 9.

In December 2006, we completed the sale of our gas-fired plants and received $1.6 billion in cash. The proceeds from the sale are expected to be applied to reduce debt and invest in our business or repurchase equity. We discuss this sale in more detail in Note 2.

BGE BGE currently maintains a $400.0 million five-year revolving credit facility expiring in 2011. BGE can borrow directly from the banks or use the facilities to allow commercial paper to be issued. As of December 31, 2006, BGE had no outstanding commercial paper, which results in $400.0 million in unused credit facilities.

Pursuant to Senate Bill 1, BGE is permitted to recover deferred costs associated with the residential electric rate deferral by issuing rate stabilization bonds after January 1, 2007 that securitize the deferred costs. In December 2006, the Maryland PSC issued an order, which allows BGE to issue bonds in an aggregate principal amount of approximately $630 million, subject to adjustment. We currently intend to issue such bonds in 2007. We discuss Senate Bill I in more detail in Item 1. Business-Electric Regulatory Matters and Competition section.

Other Nonregulated Businesses If we can get a reasonable value for our remaining real estate projects and other investments, additional cash may be obtained by selling them. Our ability to sell or liquidate assets will depend on market conditions, and we cannot give assurances that these sales or liquidations could be made.

Capital Resources Our actual consolidated capital requirements for the years 2004 through 2006, along with the estimated annual amount for 2007, are shown in the table on the next page.

We will continue to have cash requirements for:

• working capital needs,

• . payments of interest, distributions, and dividends,

• capital expenditures, and

• the retirement of debt and redemption of preference stock.

Capital requirements for 2007 and 2008 include estimates of spending for existing and anticipated projects. We continuously review and modify those estimates. Actual requirements may vary from the estimates included in the table on the next page because of a number of factors including:

+ regulation, legislation, and competition,

• BGE load requirements, 55

• environmental protection standards,

• the type and number of projects selected for construction or acquisition,

• the effect of market conditions on those projects,

• the cost and availability of capital,

• the availability of cash from operations, and

• business decisions to invest in capital projects.

Our estimates are also subject to additional factors. Please see the Forward Looking Statements and Item MA. Risk Factors sections.

2004 2005 2006 2007 (In millions)

Nonregulated Capital Requirements:

Merchant energy (excludes acquisitions)

Generation plants

$182

$ 182 $ 235 $ 235 Nuclear fuel 133 130 137 150 Environmental controls 1

17,

330 Portfolio acquisitions/investments 11 231 227 550 Technology/other 129 165 152 200 Total merchant energy capital requirements 455 709 768 1,465 Other nonregulated capital requirements 42 32 21 10 Total nonregulated capital requirements 497 741 789 1,475 Regulated Capital Requirements:

Regulated electric 209 241 297 380 Regulated gas 56 50 63 60 Total regulated capital requirements 265 291 360 440 Totalcapitalrequirements

$762

$1,032

$1,149

$1,915 The table above does not include amounts related to pre-acquisition capital requirements but does include post-acquisition capital requirements. We discuss our acquisitions in more detail in Note 15.

As of the date of this report, we have not completed our 2008 capital budgeting process, but expect our 2008 capital requirements to be approximately $1.7 billion.

Our environmental controls capital requirements are affected by new rules or regulations that require modifications to our facilities. Based on information currently available to us regarding recently issued regulations, we will install additional air emission control equipment at certain of our coal-fired generating facilities in Maryland and at co-owned coal-fired generating facilities in Pennsylvania. We estimate another

$800 million of capital spending from 2008-2011 for environmental controls. We discuss environmental matters in more detail in Item 1. Business-Environmental Matters.

Capital Requirements Merchant Energy Business Our merchant energy business' capital requirements consist of its continuing requirements, including expenditures for:

• improvements to generating plants,

• nuclear fuel costs,

• upstream gas investments,

+ portfolio acquisitions and other investments,

• costs of complying with the Environmental Protection Agency (EPA), Maryland, and Pennsylvania environmental regulations and legislation, and

• enhancements to our information technology infrastructure.

Regulated Electric and Gas Regulated electric and gas construction expenditures primarily include new business construction needs and improvements to existing facilities, including projects to improve reliability.

Funding for Capital Requirements Merchant Energy Business Funding for our merchant energy business is expected from internally generated funds. If internally generated funds are not sufficient to meet funding requirements, we have available sources from commercial paper issuances, issuances of long-term debt and equity, leases, and other financing activities.

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

We expect to fund acquisitions with a mixture of debt and equity with an overall goal of maintaining a strong investment grade credit profile.

Regulated Electric and Gas Funding for regulated electric and gas capital expenditures is expected from internally generated funds. If internally generated funds are not sufficient to meet funding requirements, we have available sources from commercial paper issuances, available capacity under credit facilities, the issuance of long-term debt, trust preferred securities, or preference stock, and/or from time to time equity contributions from Constellation Energy. We discuss BGE's planned issuance of rate stabilization bonds in the Available Sources of Funding section. BGE also participates in a cash pool administered by Constellation Energy as discussed in Note 16.

Other Nonregulated Businesses Funding for our other nonregulated businesses is expected from internally generated funds. If internally generated funds are not sufficient to meet funding requirements, we have available sources from commercial paper issuances, issuances of long-term debt of Constellation Energy, sales of securities and assets, and/or from time to time equity contributions from Constellation Energy.

Our ability to sell or liquidate securities and non-core assets will depend on market conditions, and we cannot give assurances that these sales or.liquidations could be made. We discuss our remaining non-core assets and market conditions in the Results of Operations-Other Nonregulated Businesses section.

Contractual Payment Obligations and Committed Amounts We enter into various agreements that result in contractual payment obligations in connection with our business activities.

These obligations primarily relate to our financing 56

arrangements (such as long-term debt, preference stock, and operating leases), purchases of capacity and energy to support the growth in our merchant energy business activities, and purchases of fuel and transportation to satisfy the fuel requirements of our power generating facilities.

Our total contractual payment obligations as of December 31, 2006, increased $2.4 billion compared to 2005 primarily due to an increase in fuel and transportation obligations and long-term debt. Our fuel and transportation obligations increased mostly due to new coal contracts related to our merchant energy business. Our long-term debt increased mostly due to the issuance of BGE Notes, offset in part by repayments made during the year. We detail our contractual payment obligations as of December 31, 2006 in the following table:

Lquidity Provisions In many cases, customers of our merchant energy business rely on the creditworthiness of Constellation Energy. A decline below investment grade by Constellation Energy would negatively impact the business prospects of that operation.

We regularly review our liquidity needs to ensure that we have adequate facilities available to meet collateral requirements. This includes having liquidity available to meet margin requirements for our wholesale marketing, risk management, and trading operation and our retail competitive supply activities.

We have certain agreements that contain provisions that would require additional collateral upon credit rating decreases in the senior unsecured debt of Constellation Energy.

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

Under counterparty contracts related to our wholesale marketing, risk management, and trading operation, we are obligated to post collateral if Constellation Energy's senior unsecured credit ratings declined below established contractual levels. Based on contractual provisions at December 31, 2006, we estimate that if Constellation Energy's senior unsecured debt were downgraded we would have the following additional collateral obligations:

Payments 2008-2010-2007 2009 2011 Thereafter Total (In millions)

Contractual Payment Obligations Long-term debt:'

Nonregulared Principal

$ 620.5 507.7 58.8

$2,203.3

$ 3,390.3 Interest 183.9 333.6 286.9 1,276.1 2,080.5 Total 804.4 841.3 345.7 3,479.4 5,470.8 BGE Principal 121.4 306.1 22.0 1,267.2 1,716.7 Interest 97.3 162.6 155.7 1,408.7 1,824.3 Total 218.7 468.7 177.7 2,675.9 3,541.0 BGE preference stock 190.0 190.0 Operating leases' 186.0 222.3 153.4 391.6 953.3 Purchase obligations:'

Purchased capacity and energye 367.1 755.5 271.8 526.0 1,920.4 Fuel and tmnsportation 2,866.5 1,867.3 475.9 894.4 6,104.1 Other 103.2 68.0 9.6 26.1 206.9 Other noncurrent liabilities:

Pension benefits' 128.8 71.5 144.0 344.3 Postretirement and post employment benefits' 35.2 81.1 91.5 290.7 498.5 Total contractual payment obligations

$4,709.9

$4,375.7

$1,669.6

$8,474.1

$19,229.3 1

Amounts in lone-termn debt rt'lect the oriminal mnatuity dlates JInoesws man reauirecus L

B, Credit Ratings Cu Downgraded to PR BBB/Baa2 BBB-/Baa3 Below investment

-low Cumulative irrent Incremental Incremental iting Obligations Obligations (In millions) 1

$495

$ 495 2

246 741 to repay $384.3 million early throughput options and remarketingfearures. Interest on variable rate debt is included based on the December31, 2006forward curve for interest rates.

2 Our operating lease commitments include fture payment obligations under certain power purchase agreements as discussedfrrther in Note 11.

3 Contracts topurchasegoods or services that specify all significant terms. Amounts related to certain purchase obligations are based onjuture purchase expectations which may diffir tom actual purchases.

4 Our contractual obligationsforpurchased capacity and energy are shown on a gross basis f*r certain transactions, including both the fixed payment portions of tolling contracts and estimated variable payments under unit-contingent power purchase agreements.

5 Amounts related to pension benefits reflect our current 5-yearforecastfor contributions for our qualified pension plans and participant payments for our nonqualifiedpension plans. Refer to Note 7for more detail on our pension plans.

6 Amounts related to postretirement andpostemployment benefits arefor unfundedplans and reflect present value amounts consistent with the determination of the related liabilities recorded in our Consolidated Balance Sheets as discussed in Note 7.

Termination ofMerger w4rh FPL Group, Inc.

In connection with the termination of the merger agreement with FPL Group, there are contingencies relating to certain types of transactions entered into prior to September 30, 2007.

We discuss these contingencies in Note 15.

grade 3

547 1,288 Based on market conditions and contractual obligations at the time of a downgrade, we could be required to post collateral in an amount that could exceed the amounts specified above, which could be material. We discuss our credit ratings in the Security Ratings section and our credit facilities in the Available Sources of Funding section.

The credit facilities of Constellation Energy and BGE have limited material adverse change clauses that only consider a material change in financial condition and are not directly affected by decreases in credit ratings. If these clauses are invoked, the lending institutions can decline to make new advances or issue new letters of credit, but cannot accelerate the payment of existing amounts outstanding. The long-term debt indentures of Constellation Energy and BGE do not contain material adverse change clauses or financial covenants.

Certain credit facilities of Constellation Energy contain a provision requiring Constellation Energy to maintain a ratio of debt to capitalization equal to or less than 65%. At December 31, 2006, the debt to capitalization ratios as defined in the credit agreements were no greater than 48%. 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, 2006, the debt to capitalization ratio for BGE as defined in this credit agreement was 49%. At December 31, 2006, no amount was outstanding under this agreement.

57

Failure by Constellation Energy, or BGE, to comply with these provisions could result in the acceleration of the maturity of the debt outstanding under these facilities. The credit facilities of Constellation Energy contain usual and customary cross-default provisions that apply to defaults on debt by Constellation Energy and certain subsidiaries over a specified threshold.

The BGE credit facility also contains usual and customary cross-default provisions that apply to defaults on debt by BGE over a specified threshold. The indenture pursuant to which BGE has issued and outstanding mortgage bonds provides that a default under any debt instrument issued under the indenture may cause a default of all debt outstanding under such indenture.

Constellation Energy also provides credit support to Calvert Cliffs, Nine Mile Point, and Ginna to ensure these plants have funds to meet expenses and obligations to safely operate and maintain the plants.

Pursuant to Senate Bill 1 and an order issued by the Maryland PSC, BGE is permitted to recover deferred costs associated with the residential electric rate deferral after January 1, 2007, including through the issuance of rate stabilization bonds that securitize the deferred costs. We discuss Senate Bill 1 in more detail in Item 1.-Business-Electric Regulatory Matters and Competition section and the rate stabilization bonds in Available Sources of Funding section.

We discuss our short-term credit facilities in Note 8, long-term debt in Note 9, lease requirements in Note 11, and commitments and guarantees in Note 12.

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

We use these arrangements when they enable us to obtain financing or execute commercial transactions on favorable terms.

As of December 31, 2006, we have no material off-balance sheet arrangements including:

• guarantees with third-parties that are subject to the initial recognition and measuremeht requirements of FASB Interpretation No. 45, Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others,

• retained interests in assets transferred to unconsolidated

entities,

• derivative instruments indexed to our common stock, and classified as equity, or

• variable interests in unconsolidated entities that provide financing, liquidity, market risk or credit risk support, or engage in leasing, hedging or research and development services.

At December 31, 2006, Constellation Energy had a total of

$11,277.3 million in guarantees outstanding, of which

$10,001.8 million related to our competitive supply activities.

These amounts do not represent incremental consolidated Constellation Energy obligations; rather, they primarily represent parental guarantees of certain subsidiary obligations to third parties. These guarantees are put into place in order to allow our subsidiaries the flexibility needed to conduct business with counterparties without having to post other forms of collateral.

While the stated limit of these guarantees is $10,001.8 million, our calculated fair value of obligations for commercial transactions covered by these guarantees was $2,190.6 million at December 31, 2006. If the parent company was required to fund these subsidiary obligations, the total amount based on December 31, 2006 market prices would be $2,190.6 million.

For those guarantees related to our mark-to-market energy or risk management liabilities, the fair value of the obligation is recorded in our Consolidated Balance Sheets. We believe it is unlikely that we would be required to perform or incur any losses associated with guarantees of our subsidiaries' obligations.

We discuss our other guarantees in Note 12 and our significant variable interests in Note 4.

Market Risk We are exposed to various risks, including, but not limited to, energy commodity price and volatility risk, credit risk, interest rate risk, equity price risk, foreign exchange risk, and operations risk. Our risk management program is based on established policies and procedures to manage these key business risks with a strong focus on the physical nature of our business. This program is predicated on a strong risk management culture combined with an effective system of internal controls.

The Audit Committee of the Board of Directors periodically reviews compliance with our risk parameters, limits and trading guidelines, and our Board of Directors has established a value at risk limit. We have a Risk Management Division that is responsible for monitoring the key business risks, enforcing compliance with risk management policies and risk limits, as well as managing credit risk. The Risk Management Division reports to the Chief Risk Officer (CRO) who provides regular risk management updates to the Audit Committee and the Board of Directors.

We have a Risk Management Committee (RMC) that is responsible for establishing risk management policies, reviewing procedures for the identification, assessment, measurement and management of risks, and the monitoring and reporting of risk exposures. The RMC meets on a regular basis and is chaired by the Vice Chairman of Constellation Energy & Chairman of Constellation Energy Commodities Group, and consists of our Chief Executive Officer, our Chief Financial Officer and Chief Administrative Officer, our Executive Vice President of Corporate Strategy and Retail Competitive Supply, the Co-Presidents & Chief Executive Officers of Constellation Energy Commodities Group, the President of Constellation Generation Group and the Chief Risk Officer. In addition, the CRO coordinates with the risk management committees at the major operating subsidiaries that meet regularly to identify, assess, and quantify material risk issues and to develop strategies to manage these risks.

(7 58

Interest Rate Risk We are exposed to changes in interest rates as a result of financing through our issuance of variable-rate and fixed-rate debt and certain related interest rate swaps. We may use derivative instruments to manage our interest rate risks.

In December 2006, in order to manage the exposure to fluctuations in interest rates on variable rate debt, CEP entered into a pay fixed and receive floating interest rate swap relating to

$16.5 million of its outstanding debt.

In July 2004, to optimize the mix of fixed and floating-rate debt, we entered into interest rate swaps relating to

$450.0 million of our long-term debt. These fair value hedges effectively convert our current fixed-rate debt to a floating-rate instrument tied to the three month London Inter-Bank Offered Rate. Including the $450.0 million in interest rate swaps, approximately 14% of our long-term debt is floating-rate.

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

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

Principal Payments and Interest Rate Derail by Contractual Maturity Date 2007 2008 2009 2010 2011 (Dollars in millions)

Thereafter Total Long-term debt Variable-rate debt Average interest rate Fixed-rate debt Average interest rate Fair value at December 31, 2006

$ 723.2

$4,513.8

$741.9(A) $301.1

$512.7 6.47%

6.09%

6.13%

$ 5.5 6.63%

$16.8 6.60%

$36.0

$ 681.7

$ 723.2 3.55%

5.50%

5.52%

$22.5

$2,788.8

$4,383.8 6.63%

6.41%

6.55%

(A) Amount excludes $384.3 million of long-term debt that contains certain put options under which lenders could potentially require us to repay the debt prior to maturity of which $136.9 million is classified as current portion of long-term debt in our Consolidated Balance Sheets and in our Consolidated Statements of Capitalization.

Commodity Risk We are exposed to the impact of market fluctuations in the price and transportation costs of electricity, natural gas, coal, and other commodities. These risks arise from our ownership and operation of power plants, the load-serving activities of BGE and our competitive supply operations, and our origination, risk management, and trading activities. We discuss these risks separately for our merchant energy and our regulated businesses below.

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

Commodit Prices Commodity price risk arises from:

• the potential for changes in the price of, and transportation costs for, electricity, natural gas, coal, and other commodities,

+ the volatility of commodity prices, and

• changes in interest rates and foreign exchange rates.

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

• seasonal, daily, and hourly changes in demand,

• extreme peak demands due to weather conditions,

• available supply resources,

• transportation availability and reliability within and between regions,

• location of our generating facilities relative to the location of our load-serving obligations,

• procedures used to maintain the integrity of the physical electricity system during extreme conditions,

• changes in the nature and extent of federal and state regulations, and

• geopolitical concerns affecting global supply of oil and natural gas.

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

• weather conditions,

• market liquidity,

• capability and reliability of the physical electricity and gas systems, and

• the nature and extent of electricity deregulation.

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

Supply and Demand Risk We are exposed to the risk that available sources of supply may differ from the amount of power demanded by our customers 59

under fixed-price load-serving contracts. During periods of high demand, our power supplies may be insufficient to serve our customers' needs and could require us to purchase additional energy at higher prices. Alternatively, during periods of low demand, our power supplies may exceed our customers' needs and could result in us selling that excess energy at lower prices.

Either of those circumstances could have a negative impact on our financial results.

We are also exposed to variations in the prices and required volumes of natural gas, oil, and coal we burn at our power plants to generate electricity. During periods of high demand on our generation assets, our fuel supplies may be insufficient and could require us to procure additional fuel at higher prices.

Alternatively, during periods of low demand on our generation assets, our fuel supplies may exceed our needs, and could result in us selling the excess fuels at lower prices. Either of these circumstances will have a negative impact on our financial results.

Operations Risk Operations risk is the risk that a generating plant will not be available to produce energy and the risks related to physical delivery of energy to meet our customers' needs. If one or more of our generating facilities is not able to produce electricity when required due to operational factors, we may have to forego sales opportunities or fulfill fixed-price sales commitments through the operation of other more costly generating facilities or through the purchase of energy in the wholesale market at higher prices. We purchase power from generating facilities we do not own. If one or more of those generating facilities were unable to produce electricity due to operational factors, we may be forced to purchase electricity in the wholesale market at higher prices.

This could have a material adverse impact on our financial results.

Our nuclear plants produce electricity at a relatively low marginal cost. The Nine Mile Point facility sells 90% of its output under unit-contingent power purchase agreements (we have no obligation to provide power if the units are not available) to the previous owners. Based on its new capacity, beginning in 2007, we will sell approximately 80% of Ginna's output under a unit-contingent power purchase agreement to the former owners. However, if an unplanned outage were to occur at Calvert Cliffs during periods when demand was high, we may have to purchase replacement power at potentially higher prices to meet our obligations, which could have a material adverse impact on our financial results.

Risk Management and Tradins As part of our overall portfolio, we manage the commodity price risk of our competitive supply activities and our electric generation facilities, including power sales, fuel and energy purchases, emission credits, interest rate and foreign currency risks, weather risk, and the market risk of outages. In order to manage these risks, we may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from forecasted sales and purchases of energy, including:

• forward contracts, which commit us to purchase or sell energy commodities in the future;

+ futures contracts, which are exchange-traded standardized commitments to purchase or sell a commodity or financial instrument, or to make a cash settlement, at a specific price and future date;

• swap agreements, which require payments to or from counterparties based upon the differential between two prices for a predetermined contractual (notional) quantity; and

• option contracts, which convey the right to buy or sell a commodity, financial instrument, or index at a predetermined price.

The objectives for entering into such hedges include:

+ fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return on our electric generation operations,

• fixing the price of a portion of anticipated fuel purchases for the operation of our power plants,

+ fixing the price for a portion of anticipated energy purchases to supply our load-serving customers, and

• managing our exposure to interest rate risk and foreign currency exchange risks.

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

While some of the contracts we use to manage risk represent commodities or instruments for which prices are available from external sources, other commodities and certain contracts are not actively traded and are valued using other pricing sources and modeling techniques to determine expected future market prices, contract quantities, or both. We use our best estimates to determine the fair value of commodity and derivative contracts we hold and sell. These estimates consider various factors including closing exchange and over-the-counter price quotations, time value, volatility factors, and credit exposure. However, it is likely that future market prices could vary from those used in recording mark-to-market energy assets and liabilities, and such variations could be material.

We measure the sensitivity of our wholesale marketing and risk management mark-to-market energy contracts to potential changes in market prices using value at risk. Value at risk is a statistical model that attempts to predict risk of loss based on historical market price volatility. We calculate value at risk using a historical variance/covariance technique that models option positions using a linear approximation of their value.

Additionally, we estimate variances and correlation using historical commodity price changes over the most recent rolling three-month period. Our value at risk calculation includes all wholesale marketing and risk management mark-to-market energy assets and liabilities, including contracts for energy commodities and derivatives that result in physical settlement and contracts that require cash settlement.

The value at risk calculation does not include market risks associated with activities that are subject to accrual accounting, primarily our generating facilities and our competitive supply load-serving activities. We manage these risks by monitoring our fuel and energy purchase requirements and our estimated contract sales volumes compared to associated supply arrangements. We also engage in hedging activities to manage these risks. We describe those risks and our hedging activities earlier in this section.

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The value at risk amounts below represent t pre-tax loss in the fair value of our wholesale mar management mark-to-market energy assets and li one and ten-day holding periods.

Total Wholesale Value at Risk For the year ended December 31, 99% Confidence Level, One-Day Holding Period Year end Average High Low 95% Confidence Level, One-Day Holding Period Year end Average High Low 95% Confidence Level, Ten-Day Holding Period he potential 2005, for the trading portion of our wholesale trading portfolio keting and risk due to increased commodity prices, volatility, and trading abilities over activity. Our trading positions can be used to manage the commodity price risk of our competitive supply activities and our generation facilities. We also engage in trading activities for profit. These activities are managed through daily value at risk 2006 2005 and stop loss limits and liquidity guidelines.

(In millions)

Due to the inherent limitations of statistical measures such as value at risk and the seasonality of changes in market prices, the value at risk calculation may not reflect the full extent of our

$13.4

$10.0 commodity price risk exposure. Additionally, actual changes in 16.7 6.1 the value of options may differ from the value at risk calculated 28.0 14.5 using a linear approximation inherent in our calculation method.

9.6 2.4 As a result, actual changes in the fair value of mark-to-market energy assets and liabilities could differ from the calculated value at risk, and such changes could have a material impact on our

$10.2

$ 7.6 financial results.

12.7 21.3 7.3 4.7 11.0 1.8 Year end

$32.3

$24.1 Average 40.2 14.7 High 67.4 34.9 Low 23.0 5.8 Based on a 99% confidence interval, we would expect a one-day change in the fair value of the portfolio greater than or equal to the daily value at risk approximately once in every 100 days. In 2006, we did not experience any instance where the actual daily mark-to-market change in portfolio value exceeded the predicted value at risk. However, published market studies conclude that exceeding daily value at risk less than seven times in a one-year period is considered consistent with a 99%

confidence interval.

The table above is the value at risk associated with our wholesale marketing, risk management, and trading operation's mark-to-market energy assets and liabilities, including both trading and non-trading activities. We experienced higher value at risk for the year ended December 31, 2006 compared to the year ended December 31, 2005, primarily due to a higher number of economic hedges of accrual positions and an increase in our trading activities discussed below. We discuss our mark-to-market results in more detail in the Competitive Supply section.

The following table details our value at risk for the trading portion of our wholesale marketing and risk management mark-to-market energy assets and liabilities over a one-day holding period at a 99% confidence level for 2006 and 2005:

Wholesale Trading Value at Risk For the year ended December 31, 2006 2005 (In millions)

Average

$11.2

$ 5.5 High 17.6 13.3 We experienced higher value at risk for the year ended December 31, 2006 compared to the year ended December 31, Regulated Electric Business BGE's residential base rates were frozen for the six-year period ended June 30, 2006, and its commercial and industrial base rates were frozen for a four-year period that ended June 30, 2004. The commodity and transmission components of rates were frozen for different time periods depending on the customer type and service options selected by customers.

Our wholesale marketing, risk management, and trading operation provided BGE 100% of the energy and capacity to meet its residential standard offer service obligations through June 30, 2006. Bidding to supply BGE's standard offer service to all customers will occur from time to time through a competitive bidding process approved by the Maryland PSC. Our wholesale marketing, risk management, and trading operation is supplying a portion of BGE's standard offer service obligation to all customers. We discuss standard offer service and the impact on base rates in more detail in Item 1. Business-Electric Business section.

BGE may receive performance assurance collateral from suppliers to mitigate suppliers' credit risks in certain circumstances. Performance assurance collateral is designed to protect BGE's potential exposure over the term of the supply contracts and will fluctuate to reflect changes in market prices. In addition to the collateral provisions, there are supplier "step-up" provisions, where other suppliers can step in if the early termination of a Full-Requirements Service Agreement with a supplier should occur, as well as specific mechanisms for BGE to otherwise replace defaulted supplier contracts. All costs incurred by BGE to replace the supply contract are to be recovered from the defaulting supplier or from customers through rates. Finally, BGE's exposure to uncollectible expense or credit risk from customers for the commodity portion of the bill is covered by the administrative fee included in Provider of Last Resort rates.

Our regulated electric business may enter into electric futures, options, and swaps to hedge its price. We discuss this further in Note 13. At December 31, 2006 and 2005, our exposure to commodity price risk for our regulated electric business was not material.

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Regulated Gas Business Our regulated gas business may enter into gas futures, options, and swap's to hedge its price risk under our market-based rate incentive mechanism and our off-system gas sales program. We discuss this further in Note 13. At December 31, 2006 and 2005, our exposure to commodity price risk for our regulated gas business was not material.

Credit Risk We are exposed to credit risk, primarily through our merchant energy business. Credit risk is the loss that may result from counterparties' nonperformance. We evaluate the credit risk of our wholesale marketing, risk management, and trading operation and our retail competitive supply activities separately as discussed below.

Wholesale Credit Risk We measure wholesale credit risk as the replacement cost for open energy commodity and derivative transactions (both mark-to-market and accrual) adjusted for amounts owed to or due from counterparties for settled transactions. The replacement cost of open positions represents unrealized gains, net of any unrealized losses, where we have a legally enforceable right of setoff. We monitor and manage the credit risk of our wholesale marketing, risk management, and trading operation through credit policies and procedures which include an established credit approval process, daily monitoring of counterparty credit limits, the use of credit mitigation measures such as margin, collateral, or prepayment arrangements, and the use of master netting agreements.

As of December 31, 2006 and 2005, the credit portfolio of our wholesale marketing, risk management, and trading operation had the following public credit ratings:

At December31, 2006 2005 Rating Investment Grade' 61%

53%

Non-Investment Grade 3

7 Not Rated 36 40 1 Includes counterparties with an investmentgrade rating by at least one of the major credit rating agencies. If split rating exists, the lower rating is used.

Our exposure to "Not Rated" counterparties was

$1.1 billion at December 31, 2006 compared to $1.4 billion at December 31, 2005. This decrease was mostly due to a decrease in our credit portfolio related to natural gas and international coal customers that do not have public credit ratings. Although not rated, a majority of these counterparties are considered investment grade equivalent based on our internal credit ratings.

We utilize internal credit ratings to evaluate the creditworthiness of our wholesale customers, including those companies that do not have public credit ratings. Based on internal credit ratings, approximately $643.8 million or 59% of the exposure to unrated counterparties was rated investment grade equivalent at December 31, 2006 and approximately $915.7 million or 68%

was rated investment grade equivalent at December 31, 2005.

The following table provides the breakdown of the credit quality of our wholesale credit portfolio based on our internal credit ratings.

At December 31, Investment Grade Equivalent Non-Investment Grade 2006 2005 82%

80%

18 20 A portion of our total wholesale credit risk is related to transactions that are recorded in our Consolidated Balance Sheets. These transactions primarily consist of open positions from our wholesale marketing, risk management, and trading operation that are accounted for using mark-to-market accounting, as well as amounts owed by wholesale counterparties for transactions that settled but have not yet been paid. The following table highlights the credit quality and exposures related to these activities:

Number of Net Total Counterparties Exposure of Exposure Greater Cotuterparties Before than 10%

Greater than Credit Credit Net of Net 10% of Net Rating Collateral Collateral Exposure Exposure Exposure (Dollars in millions)

Investment grade

$1,268

$130

$1,138 S-Split rating 34 5

29 Non-investment grade 81 44 37 Internally rated-investment grade 511 71 440 Internally rated-non-investment trade 229 55 174 Total

$2,123

$305

$1,818 Due to the possibility of extreme volatility in the prices of energy commodities and derivatives, the market value of contractual positions with individual counterparties could exceed established credit limits or collateral provided by those counterparties. If such a counterparty were then to fail to perform its obligations under its contract (for example, fail to deliver the electricity our wholesale marketing, risk management, and trading operation had contracted for), we could incur a loss that could have a material impact on our financial results.

Additionally, if a counterparty were to default and we were to liquidate all contracts with that entity, our credit loss would include the loss in value of mark-to-market contracts, the amount owed for settled transactions, and additional payments, if any, that we would have to make to settle unrealized losses on accrual contracts.

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Retail Credit Risk We are exposed to retail credit risk through our competitive electricity and natural gas supply activities which serve commercial and industrial companies. Retail credit risk results when customers default on their contractual obligations. This risk represents the loss that may be incurred due to the nonpayment of a customer's accounts receivable balance, as well as the loss from the resale of energy previously committed to serve the customer.

Retail credit risk is managed through established credit policies, monitoring customer exposures, and the use of credit mitigation measures such as letters of credit or prepayment arrangements.

Our retail credit portfolio is well diversified with no significant company or industry concentrations. During 2006, we did not experience a material change in the credit quality of our retail credit portfolio compared to 2005. Retail credit quality is dependent on the economy and the ability of our customers to manage through unfavorable economic cycles and other market changes. If the business environment were to be negatively affected by changes in economic or other market conditions, our retail credit risk may be adversely impacted.

Foreign Currency Risk Our merchant energy business is exposed to the impact of foreign exchange rate fluctuations. This foreign currency risk arises from our activities in countries where we transact in currencies other than the U.S. dollar. In 2006, our exposure to foreign currency risk was not material. However, we expect our foreign currency exposure to grow due to our Canadian operations, global power, coal, freight, and natural gas operations, and our UniStar venture. We manage our exposure to foreign currency exchange rate risk using a comprehensive foreign currency hedging program. While we cannot predict currency fluctuations, the impact of foreign currency exchange rate risk could be material.

Equity Price Risk We are exposed to price fluctuations in equity markets primarily through our pension plan assets, our nuclear decommissioning trust funds, and trust assets securing certain executive benefits.

We are required by the NRC to maintain externally funded trusts for the costs of decommissioning our nuclear power plants.

We discuss our nuclear decommissioning trust funds in more detail in Note 1.

A hypothetical 10% decrease in equity prices would result in an approximate $130 million reduction in the fair value of our financial investments that are classified as trading or available-for-sale securities. In 2006, our actual return on pension plan assets was $141.1 million due to advances in the markets in which plan assets are invested. We describe our 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.

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Item 8. Financial Statements and Supplementary Data REPOR OFMNGMN Financial Statements The management of Constellation Energy Group, Inc. and Baltimore Gas and Electric Company (the "Companies") is responsible for the information and representations in the Companies' financial statements. The Companies prepare the financial statements in accordance with accounting principles generally accepted in the United States of America based upon available facts and circumstances and management's best estimates and judgments of known conditions.

PricewaterhouseCoopers LLP, an independent registered public accounting firm, has audited the financial statements and expressed their opinion on them. They performed their audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).

The Audit Committee of the Board of Directors, which consists of three independent Directors, meets periodically with management, internal auditors, and PricewaterhouseCoopers LLP to review the activities of each in discharging their responsibilities. The internal audit staff and PricewaterhouseCoopers LLP have free access to the Audit Committee.

Management's Report on Internlal Control Over Financial Reporting The management of Constellation Energy Group, Inc.

("Constellation Energy"), under the direction of its principal executive officer and principal financial officer, is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Exchange Act Rule 13a-15(0.

Constellation Energy's system of internal control over financial reporting is designed to provide reasonable assurance to Constellation Energy's management and Board of Directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States of America.

The management of Constellation Energy conducted an evaluation of the effectiveness of Constellation Energy's internal control over financial reporting using the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). As noted in the COSO framework, an internal control system, no matter how well conceived and operated, can provide only reasonable-not absolute-assurance to management and the Board of Directors regarding achievement of an entity's financial reporting objectives. Based upon the evaluation under this framework, management concluded that Constellation Energy's internal control over financial reporting was effective as of December 31, 2006.

PricewaterhouseCoopers LLP, an independent registered public accounting firm, has audited management's assessment of the effectiveness of Constellation Energy's internal control over financial reporting at December 31, 2006, as stated in their report set forth below.

As discussed in Item 9A. Controls and Procedures, the management of Baltimore Gas & Electric Company ("BGE")

has not assessed the effectiveness of BGE's internal control over financial reporting on a standalone basis because it is not yet required to do so by applicable federal securities laws and regulations.

Mayo A. Shattuck III Chairman of the Board, President and Chief Executive Officer E. Follin Smith Executive Vice-President, Chief Financial Officer, and ChiefAdministrative Officer I

S RPR S OF INEEDN REITEE PULI ACONTN FIR To the Board ofDirectors and Shareholders of Constellation Energy Group, Inc.

We have completed integrated audits of Constellation Energy Group, Inc. and Subsidiaries' consolidated financial statements and of its internal control over financial reporting as of December 31, 2006 in accordance with the standards of the Public Company Accounting Oversight Board (United States).

Our opinions, based on our audits, are presented below.

Consolidated financial statements and financial statement schedule In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a) (1) present fairly, in all material respects, the financial position of Constellation Energy Group, Inc. and Subsidiaries (the Company) at December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a) (2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management.

Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the 64

amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note I to the consolidated financial statements, in 2006 the Company changed its method of accounting for defined benefit pension and other postretirement plans. As discussed in Note 1 to the consolidated financial statements, in 2005 the Company changed its method of accounting for conditional asset retirement obligations and the accounting for stock based compensation.

We have also previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets and statements of capitalization of Constellation Energy Group, Inc. and Subsidiaries as of December 31, 2004, 2003, and 2002, and the related consolidated statements of income, cash flows, and common shareholders' equity and comprehensive income for the years ended December 31, 2003 and 2002 (none of which are presented herein); and we expressed unqualified opinions on those consolidated financial statements. In our opinion, the information set forth in the Summary of Operations and Summary of Financial Condition of Constellation Energy Group, Inc. and Subsidiaries included in the Selected Financial Data for each of the five years in the period ended December 31, 2006, is fairly stated, in all material respects, in relation to the consolidated financial statements from which it has been derived.

Internal control over financial reporting Also, in our opinion, management's assessment, included in Management's Report on Internal Control Over Financial Reporting appearing under Item 8, that the Company maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control-Integrated Framework issued by the COSO. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management's assessment and on the effectiveness of the Company's internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.

Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

"10' PricewaterhouseCoopers LLP Baltimore, Maryland February 26, 2007 To Board of Directors and Shareholder of Baltimore Gas and Electric Company In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a) (1) present fairly, in all material respects, the financial position of Baltimore Gas and Electric Company and Subsidiaries (the Company) at December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a) (2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Threse financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the 65

financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

We have also previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Baltimore Gas and Electric Company and Subsidiaries as of December 31, 2004, 2003 and 2002, and the related consolidated statements of income, cash flows, and comprehensive income for the years ended December 31, 2003 and 2002 (none of which are presented herein); and we expressed unqualified opinions on those consolidated financial statements. In our opinion, the information set forth in the Summary of Operations and Summary of Financial Condition of Baltimore Gas and Electric Company and Subsidiaries included in the Selected Financial Data for each of the five years in the period ended December 31, 2006, is fairly stated, in all material respects, in relation to the consolidated financial statements from which it has been derived.

PricewaterhouseCoopers LLP Baltimore, Maryland February 26, 2007 66

Constellation Energy Group, Inc. and Subsidiaries Year Ended December 31, 2006 2005 2004 (In millions, except per share amounts)

Revenues Nonregulated revenues

$ 16,279.0

$ 13,970.1

$ 9,404.5 Regulated electric revenues 2,115.9 2,036.5 1,967.6 Regulated gas revenues 890.0 961.7 755.1 Total revenues 19,284.9 16,968.3 12,127.2 Expenses Fuel and purchased energy expenses 14,930.7 13,239.6 8,693.2 Operating expenses 2,165.8 1,900.7 1,714.0 Workforce reduction costs 28.2 4.4 9.7 Merger-related costs 18.3 17.0 Depreciation, depletion, and amortization 523.9 523.0 488.4 Accretion of asset retirement obligations 67.6 62.0 53.1 Taxes other than income taxes 290.7 277.1 250.7 Total expenses 18,025.2 16,023.8 11,209.1 Gain on Sale of Gas-Fired Plants 73.8 Income from Operations 1,333.5 944.5 918.1 Gain on Initial Public Offering of CEP LLC 28.7 Other Income 66.1 65.5 25.5 Fixed Charges Interest expense 329.2 306.9 324.4 Interest capitalized and allowance for borrowed funds used during construction (13.7)

(9.9)

(10.8)

BGE preference stock dividends 13.2 13.2 13.2 Total fixed charges 328.7 310.2 326.8 Income from Continuing Operations Before Income Taxes 1,099.6 699.8 616.8 Income Tax Expense 351.0 163.9 118.4 Income from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles 748.6 535.9 498.4 Income from discontinued operations, net of income taxes of $107.7, $61.6,

$27.3, respectively 187.8 94.4 41.3 Cumulative effects of changes in accounting principles, net of income taxes of

$(4.7)

(7.2)

Net Income 936.4 623.1 539.7 Earnings Applicable to Common Stock 936.4 623.1 539.7 Average Shares of Common Stock Outstanding-Basic 179.4 177.5 172.1 Average Shares of Common Stock Outstanding-Diluted 181.4 179.7 173.1 Earnings Per Common Share from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles-Basic 4.17 3.02 2.90 Income from discontinued operations 1.05 0.53 0.24 Cumulative effects of changes in accounting principles (0.04)

Earnings Per Common Share-Basic 5.22 3.51 3.14 Earnings Per Common Share from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles-Diluted 4.12, 2.98 2.88 Income from discontinued operations 1.04 0.53 0.24 Cumulative effects of changes in accounting principles (0.04)

Earnings Per Common Share-Diluted 5.16 3.47 3.12 Dividends Declared Per Common Share 1.51 1.34 1.14 See Notes to Consolidated Financial Statements.

Certain prior-year amounts have been reclassified to conform with the current year 1presentation.

67

Constellation Energy Group, Inc. and Subsidiaries At December31, 2006 2005 (In millions)

Assets Current Assets Cash and cash equivalents

$ 2,289.1 813.0 Accounts receivable (net of allowance for uncollectibles of $48.9 and $47.4, respectively) 3,248.3 2,727.9 Fuel stocks 599.5 489.5 Materials and supplies 200.2 197.0 Mark-to-market energy assets 1,294.8 1,339.2 Risk management assets 261.7 1,244.3 Unamortized energy contract assets 35.2 55.6 Deferred income taxes 674.3 Other 497.0 555.3 Total current assets 9,100.1 7,421.8 Investments and Other Assets Nuclear decommissioning trust funds 1,240.1 1,110.7 Investments in qualifying facilities and power projects 308.6 306.2 Regulatory assets (net) 389.0 154.3 Goodwill 157.6 147.1 Mark-to-market energy assets 623.4 1,089.3 Risk management assets 325.7 626.0 Unamortized energy contract assets 123.6 141.2 Other 311.4 410.6 Total investments and other assets 3,479.4 3,985.4 Property, Plant and Equipment Nonregulated property, plant and equipment 7,587.6 8,580.8 Regulated property, plant and equipment 5,752.9 5,520.5 Nuclear fuel (net of amortization) 339.9 302.0 Accumulated depreciation (4,458.3)

(4,336.6)

Net property, plant and equipment 9,222.1 10,066.7 Total Assets

$21,801.6

$21,473.9 See Notes to Consolidated Financial Statements.

68

Constellation Energy Group, Inc. and Subsidiaries At December31, 2006 2005 (In millions)

Liabilities and Equity Current Liabilities Short-term borrowings 0.7 Current portion of long-term debt 878.8 491.3 Accounts payable and accrued liabilities 2,137.2 1,667.9 Customer deposits and collateral 347.2 458.9 Mark-to-market energy liabilities 1,071.7 1,348.7 Risk management liabilities 1,340.0 483.5 Unamortized energy contract liabilities 378.3 489.5 Deferred income taxes 151.4 Accrued expenses and other 969.5 780.4 Total current liabilities 7,122.7 5,872.3 Deferred Credits and Other Liabilities Deferred income taxes 1,435.8 1,180.8 Asset retirement obligations 974.8 908.0 Mark-to-market energy liabilities 392.4 912.3 Risk management liabilities 707.3 1,035.5 Unamortized energy contract liabilities 958.0 1,118.7 Defined benefit obligations 928.3 784.0 Deferred investment tax credits 57.2 64.1 Other 109.0 101.0 Total deferred credits and other liabilities 5,562.8 6,104.4 Capitalization (See Consolidated Statements of Capitalization)

Long-term debt 4,222.3 4,369.3 Minority interests 94.5 22.4 BGE preference stock not subject to mandatory redemption 190.0 190.0 Common shareholders' equity 4,609.3 4,915.5 Total capitalization 9,116.1 9,497.2 Commitments, Guarantees, and Contingencies (see Note 12)

Total Liabilities and Equity

$21,801.6

$21,473.9 See Notes to Consolidated Financial Statements.

69

COSOLIDAT.

STAEMNS OCAHF WS Constellation Energy Group, Inc. and Subsidiaries Year Ended December 31.

2006 Cash Flows From Operating Activities Net income Adjustments to reconcile to net cash provided by operating activities (Gain) loss on sales of gas-fired plants and discontinued operations Cumulative effects of changes in accounting principles Depreciation, depletion, and amortization Accretion of asset retirement obligations Deferred income taxes Investment tax credit adjustments Deferred fuel costs Defined benefit obligation expense Defined benefit obligation payments Gain on initial public offering of CEP LLC Equity in earnings of affiliates less than dividends received Proceeds from derivative power sales contracts classified as financing activities under SFAS No. 149 Changes in Accounts receivable Mark-to-market energy assets and liabilities Risk management assets and liabilities Materials, supplies, and fuel stocks Other current assets Accounts payable and accrued liabilities Other current liabilities Other Net cash provided by operating activities

$ 936.4 (191.4) 545.1 67.6 128.0 (6.9)

(348.5) 129.7 (89.2)

(28.7) 27.6 2.6 2005 (In millions) 623.1 (13.8) 7.2 606.5 62.1 136.9 (7.1)

(11.9) 94.2 (90.8) 38.7 539.7 50.1 650.3 53.2 123.4 (7.2) 6.0 81.1 (94.7) 29.5 2004 (653.7)

(275.9)

(4.4)

(267.2) 240.6 380.5 (91.8) 24.9 (72.6)

(961.2)

(88.4)

(27.5)

(250.3)

(277.1) 282.8 546.4 30.0 (397.4)

(27.2)

(39.7)

(112.1) 5.3 260.2 (8.7)

(25.0) 525.3 627.2 1,086.8 Cash Flows From Investing Activities Investments in property, plant and equipment (962.9)

(760.0)

(703.6)

Asset acquisitions and business combinations, net of cash acquired (137.6)

(237.2)

(457.3)

Investments in nuclear decommissioning trust fund securities (394.6)

(370.8)

(424.2)

Proceeds from nuclear decommissioning trust fund securities 385.8 353.2 402.2 Net proceeds from sale of gas-fired plants and discontinued operations 1,630.7 289.4 72.7 Issuances of loans receivable (65.4)

(82.8)

Sale of investments and other assets 43.9 14.4 36.1 Contract and portfolio acquisitions (2.3)

(336.2)

Other investments 62.5 (44.0)

(78.6)

Net cash provided by (used in) investing activities 560.1 (1,174.0)

(1,152.7)

Cash Flows From Financing Activities Net (maturity) issuance of short-term borrowings Proceeds from issuance of Common stock Long-term debt Proceeds from initial public offering of Constellation Energy Partners LLC Common stock dividends paid Proceeds from contract and portfolio acquisitions Repayment of long-term debt Proceeds from derivative power sales contracts classified as financing activities under SFAS No. 149 Other Net cash provided by financing activities Net Increase (Decrease) in Cash and Cash Equivalents Cash and Cash Equivalents at Beginning of Year Cash and Cash Equivalents at End of Year (0.7) 84.4 852.0 101.3 (264.0) 221.3 (609.1)

(2.6) 8.1 390.7 1,476.1 813.0

$2,289.1 10.7 96.9 12.0 (228.8) 1,026.9 (362.3) 72.6 25.5 653.5 106.7 706.3 813.0 (9.6) 293.9 100.0 (189.7) 117.5 (243.2)

(18.0) 50.9 (15.0) 721.3 706.3 Other Cash Flow Information:

Cash paid during the year for:

Interest (net of amounts capitalized)

Income taxes See Notes to Consolidated Financial Statements.

$ 304.7 109.3 301.3 115.3 327.9 203.9 Certain prior-year amounts have been reclassified to conform with the current year's presentation.

70

COSOIAE STAT.MEN S OF COMO SHREODES EQIT AN COPEESV INCOM Constellation Energy Group, Inc. and Subsidiaries Year Ended December 31, 2006, 2005, and 2004 Accumulated Other Common Stock Retained Comprehensive Total Shares Amount Earnings Loss Amount (Dollar amounts in millions, number of shares in thousands) 167,819 $ 2,179.8 $ 2,081.9 (121.2)

$ 4,140.5 Balance at December 31, 2003 Comprehensive Income Net income Other comprehensive income Hedging instruments:,

Reclassification of net gains on hedging instruments from OCI to net income, net of taxes of $169.0 Net unrealized gain on hedging instruments, net of taxes of

$124.7 Available-for-sale securities:

Reclassification of net loss on securities from OCI to net income, net of taxes of $1.4 Net unrealized gain on securities, net of taxes of $22.2 Minimum pension liability, net of taxes of $27.9 Net unrealized gain on foreign currency translation 539.7 (270.8) 196.8 2.2 33.7 (42.6) 0.4 539.7 (270.8) 196.8 2.2 33.7 (42.6) 0.4 Total Comprehensive Income 539.7 (80.3) 459.4 Common stock dividend declared ($1.14 per share)

(196.3)

(196.3)

Common stock issued 8,514 322.7 322.7 Other 0.6 0.6 Balance at December 31, 2004 176,333 2,502.5 2,425.9 (201.5) 4,726.9 Comprehensive Income Net income 623.1V 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 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 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 See Notes to Consolidated Financial Statements.

71

ONSOLIATE STAEMN S OF CAIAIZTO Constellation Energy Group, Inc. and Subsidiaries At December 31, 2006 2005 (In millions)

Long-Term Debt Long-term debt of Constellation Energy 6.35% Fixed-Rate Notes, due April 1, 2007

$ 600.0

$ 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 (7.1)

(0.9)

Total long-term debt of Constellation Energy 3,042.9 3,049.1 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 5.55% Pollution control revenue refunding loan, due July 15, 2014 47.0 Economic development loan, due December 1, 2018 35.0 35.0 6.00% Pollution control revenue refunding loan, due April 1, 2024 75.0 Floating-rate pollution control loan, due June 1, 2027 8.8 8.8 Tax-exempt variable rate notes, due April 1, 2024 75.0 Tax-exempt variable rate notes, due December 1, 2025 47.0 District Cooling facilities loan, due December 1, 2031 25.0 25.0 CEP credit facility loan, due October 31, 2010 22.0 4.875% Inflation protection loan due February 15, 2012 12.0 5.00% Mortgage note, due July 5, 2010 7.5 12.8 4.25% Mortgage note, due March 15, 2009 1.3 1.9 7.3% Fixed Rate Note, due June 1, 2012 1.8 South Carolina synthetic fuel facility loan, due January 15, 2008 (imputed interest rate of 3.47%)

20.0 36.0 Total long-term debt of nonregulated businesses 347.4 357.5 First Refunding Mortgage Bonds of BGE Remarketed floating-rate series, due September 1, 2006 97.4 71/2% Series, due January 15, 2007 121.4 122.0 65%% Series, due March 15, 2008 123.1 123.4 Total First Refunding Mortgage Bonds of BGE 244.5 342.8 Other long-term debt of BGE 5.25% Notes, due December 15, 2006 300.0 5.90% Notes, due October 1,2016 300.0 5.20% Notes, due June 15, 2033 200.0 200.0 6.35% Notes, due October 1, 2036 400.0 Medium-term notes, Series B 12.0 Medium-term notes, Series D 10.0 Medium-term notes, Series E 174.5 199.5 Medium-term notes, Series G 140.0 140.0 Total other long-term debt of BGE 1,214.5 861.5 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 Unamortized discount and premium (5.9)

(8.0)

Current portion of long-term debt (878.8)

(491.3)

Total long-term debt

$4,222.3

$4,369.3 See Notes to Consolidated Financial Statements.

continued on next page 72

CON SOLDAE STAEMN S OFCPTLZTO Constellation Energy Group, Inc. and Subsidiaries At December31, 2006 2005 (In millions)

Minority Interests 94.5 22.4 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 $102.49 per share until June 30, 2007, and at lesser amounts thereafter 40.0 40.0 6.97%, 1993 Series, 500,000 shares outstanding, callable at $102.44 per share until September 30, 2007, and at lesser amounts thereafter 50.0 50.0 6.70%, 1993 Series, 400,000 shares outstanding, callable at $102.35 per share until December 31, 2007, and at lesser amounts thereafter 40.0 40.0 6.99%, 1995 Series, 600,000 shares outstanding, callable at $103.15 per share until September 30, 2007, 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; 180,519,180 and 178,300,844 shares issued and outstanding at December 31, 2006 and 2005, respectively.

(At December 31, 2006, 3,739,214 shares were reserved for the long-term incentive plans, 7,511,741 shares were reserved for the Shareholder Investment Plan, 1,520,000 shares were reserved for the continuous offering programs, and 1,546,143 shares were reserved for the employee savings plan.)

2,738.6 2,620.8 Retained earnings 3,474.3 2,810.2 Accumulated other comprehensive loss (1,603.6)

(515.5)

Total common shareholders' equity 4,609.3 4,915.5 Total Capitalization

$ 9,116.1

$9,497.2 See Notes to Consolidated Financial Statements.

73

COSLIAE STTMET OF INCOM Baltimore Gas and Electric Company and Subsidiaries Year Ended December 31, 2006 2005 2004 (In millions)

Revenues Electric revenues

$2,115.9

$2,036.5

$1,967.7 Gas revenues 899.5 972.8 757.0 Total revenues 3,015.4 3,009.3 2,724.7 Expenses Operating Expenses Electricity purchased for resale 1,167.8 1,068.9 1,034.0 Gas purchased for resale 581.5 687.5 484.3 Operations and maintenance 496.1 450.2 427.8 Merger-related costs 4.7 5.4 Depreciation and amortization 227.5 232.4 242.3 Taxes other than income taxes 168.7 168.4 164.9 Total expenses 2,646.3 2,612.8 2,353.3 Income from Operations 369.1 396.5 371.4 Other Income (Expense) 6.0 5.9 (6.4)

Fixed Charges Interest expense 104.6 95.6 97.3 Allowance for borrowed funds used during construction (2.0)

(2.1)

(1. 1)

Total fixed charges 102.6 93.5 96.2 Income Before Income Taxes 272.5 308.9 268.8 Income Taxes Current (22.8) 122.6 69.4 Deferred 126.6 (0.9) 34.9 Investment tax credit adjustments (1.6)

(1.8)

(1.8)

Total income taxes 102.2 119.9 102.5 Net Income 170.3 189.0 166.3 Preference Stock Dividends 13.2 13.2 13.2 Earnings Applicable to Common Stock

$ 157.1

$ 175.8 153.1 COSLIAE STTMET OF COPEESV INCOME Baltimore Gas and Electric Company and Subsidiaries Year Ended December 31, 2006 2005 2004 (In millions)

Earnings Applicable to Common Stock 157.1

$ 175.8 153.1 Other comprehensive income Reclassification of net gains on hedging instruments from OCI to net income, net of taxes of $-

(0.1)

Comprehensive Income 157.1 175.8 153.0 See Notes to Consolidated Financial Statements 74

Baltimore Gas and Electric Company and Subsidiaries At December31, 2006 2005 (In millions)

Assets Current Assets Cash and cash equivalents 10.9 15.1 Accounts receivable (net of allowance for uncollectibles of $16.1 and $13.0, respectively) 344.7 480.5 Investment in cash pool, affiliated company 60.6 Accounts receivable, affiliated companies 2.5 1.8 Fuel stocks 110.9 102.7 Materials and supplies 40.2 40.1 Prepaid taxes other than income taxes 48.0 45.7 Regulatory assets (net) 62.5 Other 35.2 6.5 Total current assets 715.5 692.4 Investments and Other Assets Regulatory assets (net) 389.0 154.3 Receivable, affiliated company 150.5 154.7 Other 127.5 144.0 Total investments and other assets 667.0 453.0 Utility Plant Plant in service Electric 4,060.2 3,891.1 Gas 1,148.3 1,116.7 Common 444.6 416.0 Total plant in service 5,653.1 5,423.8 Accumulated depreciation (1,994.7)

(1,923.8)

Net plant in service 3,658.4 3,500.0 Construction work in progress 97.1 93.9 Plant held for future use 2.7 2.8 Net utility plant 3,758.2 3,596.7 Total Assets

$ 5,140.7

$ 4,742.1 See Notes to Consolidated Financial Statements.

75

Baltimore Gas and Electric Company and Subsidiaries At December31, 2006 2005 (In millions)

Liabilities and Equity Current Liabilities Current portion of long-term debt

$ 258.3

$ 469.6 Accounts payable and accrued liabilities 187.3 169.7 Accounts payable and accrued liabilities, affiliated companies 163.4 152.8 Borrowing from cash pool, affiliated company 3.2 Customer deposits 71.4 65.1 Current portion of deferred income taxes 47.4 9.6 Accrued taxes 18.8 35.5 Accrued expenses and other 79.5 70.0 Total current liabilities 826.1 975.5 Deferred Credits and Other Liabilities Deferred income taxes 697.7 608.9 Payable, affiliated company 250.7 277.7 Deferred investment tax credits 13.5 15.1 Other 14.0 19.0 Total deferred credits and other liabilities 975.9 920.7 Long-term Debt First refunding mortgage bonds of BGE 244.5 342.8 Other long-term debt of BGE 1,214.5 861.5 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 (2.9)

(2.3)

Current portion of long-term debt (258.3)

(469.6)

Total long-term debt 1,480.5 1,015.1 Minority Interest 16.7 18.3 Preference Stock Not Subject to Mandatory Redemption 190.0 190.0 Common Shareholder's Equity Common stock 912.2 912.2 Retained earnings 738.6 709.6 Accumulated other comprehensive income 0.7 0.7 Total common shareholder's equity 1,651.5 1,622.5 Commitments, Guarantees, and Contingencies (see Note 12)

Total Liabilities and Equity

$5,140.7

$4,742.1 See Notes to Consolidated Financial Statements.

76

COSLIAE STTMET OF CAS FLOW Baltimore Gas and Electric Company and Subsidiaries Year Ended December 31, 2006 2005 (In millions) 2004 Cash Flows From Operating Activities Net income Adjustments to reconcile to net cash provided by operating activities Depreciation and amortization Deferred income taxes Investment tax credit adjustments Deferred fuel costs Defined benefit plan expenses Allowance for equity funds used during construction Changes in Accounts receivable Receivables, affiliated companies Materials, supplies, and fuel stocks Other current assets Accounts payable and accrued liabilities Accounts payable and accrued liabilities, affiliated companies Other current liabilities Long-term receivables and payables, affiliated companies Other

$ 170.3 241.1 126.6 (1.7)

(348.5) 47.2 (3.7) 135.8 (0.7)

(8.2)

(31.0) 17.6 10.6 (0.9)

(70.1)

(27.5)

$ 189.0 250.5 (0.9)

(1.8)

(11.9) 37.8 (3.9)

$ 166.3 260.9 34.9 (1.8) 6.0 31.9 (2.0)

(98.7)

(0.8)

(21.7)

(0.5) 44.3 6.7 12.0 (42.9)

(37.4)

(27.0) 3.5 (28.4) 1.0 24.2

.(5.6)

(10.3)

(52.0)

(30.2)

Net cash provided by operating activities 256.9 319.8 371.4 Cash Flows From Investing Activities Utility construction expenditures (excluding equity portion of allowance for funds used during construction)

(320.6)

(270.5)

(246.4)

Change in cash pool at parent (63.8) 131.1 102.3 Sales of investments and other assets (0.4) 11.0 4.9 Other 10.3 (10.4) 2.7 Net cash used in investing activities (374.5)

(138.8)

(136.5)

Cash Flows From Financing Activities Proceeds from issuance of long-term debt 700.0 Repayment of long-term debt (445.3)

(41.6)

(149.8)

Preference stock dividends paid (13.2)

(13.2)

(13.2)

Distribution to parent (128.1)

(119.3)

(74.7)

Net cash provided by (used in) financing activities 113.4 (174.1)

(237.7)

Net (Decrease) Increase in Cash and Cash Equivalents (4.2) 6.9 (2.8)

Cash and Cash Equivalents at Beginning of Year 15.1 8.2 11.0 Cash and Cash Equivalents at End of Year 10.9 15.1 8.2 Other Cash Flow Information:

Cash paid during the year for:

Interest (net of amounts capitalized)

Income taxes See Notes to Consolidated Financial Statements.

87.2 18.7

$ 88.6

$ 123.3

$ 95.5

$ 80.7 77

Notes to Consolidated Financial Statements I

Significant Accounting Policies Nature of Our Business Constellation Energy Group, Inc. (Constellation Energy) is an energy company that conducts its business through various subsidiaries including a merchant energy business and Baltimore Gas and Electric Company (BGE). Our merchant energy business is a competitive provider of energy solutions for a variety of customers. BGE is a regulated electric transmission and distribution utility company and a regulated gas distribution utility company with a service territory that covers the City of Baltimore and all or part often counties in central Maryland. We describe our operating segments in Note 3.

This report is a combined report of Constellation Energy and BGE. References in this report to "we" and "our" are to Constellation Energy and its subsidiaries. References in this report to the "regulated business(es)" are to BGE.

Termination of Merger Agreement with FPL Group, Inc.

On October 24, 2006, Constellation Energy and FPL Group, Inc. (FPL Group) agreed to terminate the Agreement and Plan of Merger the parties had entered into on December 18, 2005. We discuss the terminated merger in more detail in Note 15.

Consolidation Policy We use three different accounting methods to report our investments in our subsidiaries or other companies:

consolidation, the equity method, and the cost method.

Consolidation We use consolidation for two types of entities:

• subsidiaries (other than variable interest entities) in which we own a majority of the voting stock, and

• variable interest entities (VIEs) for which we are the primary beneficiary. Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46R, Consolidation of Variable Interest Entities, requires us to use consolidation when we are the primary beneficiary of a VIE, which means that we have a controlling financial interest in a VIE. We discuss our investments in VIEs in more detail in Note 4.

Consolidation means that we combine the accounts of these entities with our accounts. Therefore, our consolidated financial statements include our accounts, the accounts of our majority-owned subsidiaries that are not VIEs, and the accounts of VIEs for which we are the primary beneficiary. We have not consolidated any entities for which we do not have a controlling voting interest. We eliminate all intercompany balances and transactions when we consolidate these accounts.

The Equity Method We usually use the equity method to report investments, corporate joint ventures, partnerships, and affiliated companies (including qualifying facilities and power projects) where we hold a 20% to 50% voting interest. Under the equity method, we report:

+ our interest in the entity as an investment in our Consolidated Balance Sheets, and

• our percentage share of the earnings from the entity in our Consolidated Statements of Income.

The only time we do not use this method is if we can exercise control over the operations and policies of the company. If we have control, accounting rules require us to use consolidation.

The Cost Method We usually use the cost method if we hold less than a 20%

voting interest in an investment. Under the cost method, we report our investment at cost in our Consolidated Balance Sheets. The only time we do not use this method is when we can exercise significant influence over the operations and policies of the company. If we have significant influence, accounting rules require us to use the equity method.

Sale of Subsidiary Stock We may sell portions of our ownership interests through public offerings of a subsidiary's stock. We record any gains or losses on public offerings in our Consolidated Statements of Income, as a component of non-operating income.

Regulation of Electric and Gas Business The Maryland Public Service Commission (Maryland PSC) and the Federal Energy Regulatory Commission (FERC) provide the final determination of the rates we charge our customers for our regulated businesses. Generally, we use the same accounting policies and practices used by nonregulated companies for financial reporting under accounting principles generally accepted in the United States of America. However, sometimes the Maryland PSC or the FERC orders an accounting treatment different from that used by nonregulated companies to determine the rates we charge our customers.

When this happens, we must defer (include as an asset or liability in our, and BGE's, Consolidated Balance Sheets and exclude from our, and BGE's, Consolidated Statements of Income) certain regulated business expenses and income as regulatory assets and liabilities. We have recorded these regulatory assets and liabilities in our, and BGE's, Consolidated Balance Sheets in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation.

We summarize and discuss our regulatory assets and liabilities further in Note 6.

Use of Accounting Estimates Management makes estimates and assumptions when preparing financial statements under accounting principles generally 78

accepted in the United States of America. These estimates and assumptions affect various matters, including:

• our reported amounts of revenues and expenses in our Consolidated Statements of Income during the reporting periods,

• our reported amounts of assets and liabilities in our Consolidated Balance Sheets at the dates of the financial statements, and

• our disclosure of contingent assets and liabilities at the dates of the financial statements.

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

Reclassifications We have reclassified certain prior-year amounts for comparative purposes. These reclassifications primarily relate to operations that have been classified as discontinued operations in the current year and did not affect consolidated net income for the years presented.

Revenues AccrualAccounring We record revenues from the sale of energy, energy-related products, and energy services under the accrual method of accounting in the period when we deliver energy commodities or products, render services, or settle contracts. We use accrual accounting for our merchant energy and other nonregulated business transactions, including the generation or purchase and sale of electricity, gas, and coal as part of our physical delivery activities and for power, gas, and coal sales contracts that are not subject to mark-to-market accounting. Sales contracts that are eligible for accrual accounting include non-derivative transactions and derivatives that qualify for and are designated as normal purchases and normal sales of commodities that will be physically delivered. We record accrual revenues, including settlements with independent system operators, on a gross basis because we are a principal to the transaction and otherwise meet the requirements of Emerging Issues Task Force (EITF) 03-11, Reporting Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposes, and EITF 99-19, Reporting Revenue Gross as a Principal versus Net as an Agent.

We may make or receive cash payments at the time we assume a power sale agreement for which the contract price differs from current market prices. We recognize the cash payment at inception in our Consolidated Balance Sheets as an "Unamortized energy contract" asset or liability. We amortize these assets and liabilities into revenues based on the expected cash flows provided by the contracts.

During 2006 and 2005, we terminated or restructured in-the-money contracts in exchange for upfront cash payments and a reduction or cancellation of future performance obligations. The termination or restructuring of contracts allowed us to lower our exposure to performance risk under these contracts, and resulted in the realization of $56.7 million of pre-tax earnings in 2006 and $77.0 million of pre-tax earnings in 2005 that would have been recognized over the life of these contracts.

Mark-to-Market Accounting We record revenues using the mark-to-market method of accounting for derivative contracts for which we are not permitted to use accrual accounting or hedge accounting. We discuss our use of hedge accounting in the Derivatives and Hedging Activities section later in this Note. These mark-to-market activities include derivative contracts for energy and other energy-related commodities. Under the mark-to-market method of accounting, we record the fair value of these derivatives as mark-to-market energy assets and liabilities at the time of contract execution. Our wholesale marketing, risk management, and trading operation records changes in mark-to-market energy assets and liabilities on a net basis in "Nonregulated revenues" in our Consolidated Statements of Income. Our retail competitive supply operation records changes in sale contracts accounted for as mark-to-market in "Nonregulated revenues" in our Consolidated Statements of Income.

Mark-to-market energy assets and liabilities consist of derivative contracts. While some of these contracts represent commodities or instruments for which prices are available from external sources, other commodities and certain contracts are not actively traded and are valued using modeling techniques to determine expected future market prices, contract quantities, or both. The market prices and quantities used to determine fair value reflect management's best estimate considering various factors, including closing exchange and over-the-counter quotations, time value, and volatility factors. However, future market prices and actual quantities will vary from those used in recording mark-to-market energy assets and liabilities, and it is possible that such variations could be material.

Mark-to-market revenues include:

• gains or losses on new transactions at origination to the extent permitted by applicable accounting rules,

+ unrealized gains and losses from changes in the fair value of open contracts,

• net gains and losses from realized transactions, and

• changes in valuation adjustments.

Origination gains, which are included in mark-to-market revenues, arise primarily from contracts that our wholesale marketing, risk management, and trading operation structures to meet the risk management needs of our customers.

Transactions that result in origination gains may be unique and provide the potential for individually significant gains from a single transaction.

Origination gains represent the initial fair value recognized on these structured transactions. The recognition of origination gains is dependent on the existence of observable market data that validates the initial fair value of the contract.

Origination gains were:

• $13.5 million pre-tax in 2006,

• $61.6 million pre-tax in 2005, and

• $19.7 million pre-tax in 2004.

Origination gains arose primarily from:

• 3 transactions completed in 2006, of which no transaction contributed in excess of $10 million pre-tax, 79

+ 6 transactions completed in 2005, one of which contributed approximately $35 million pre-tax, and

• 7 transactions completed in 2004, of which no transaction contributed in excess of $10 million pre-tax.

Valuation Adjustments We record valuation adjustments to reflect uncertainties associated with certain estimates inherent in the determination of the fair value of mark-to-market energy assets and liabilities.

To the extent possible, we utilize market-based data together with quantitative methods for both measuring the uncertainties for which we record valuation adjustments and determining the level of such adjustments and changes in those levels.

We describe below the main types of valuation adjustments we record and the process for establishing each.

Generally, increases in valuation adjustments reduce our earnings, and decreases in valuation adjustments increase our earnings. However, all or a portion of the effect on earnings of changes in valuation adjustments may be offset by changes in the value of the underlying positions.

• Close-out adjustment-represents the estimated cost to close out or sell to a third-party open mark-to-market positions. This valuation adjustment has the effect of valuing "long" positions (the purchase of a commodity) at the bid price and "short" positions (the sale of a commodity) at the offer price. We compute this adjustment based on our estimate of the bid/offer spread for each commodity and option price and the absolute quantity of our net open positions for each year. The level of total close-out valuation adjustments increases as we have larger unhedged positions, bid-offer spreads increase, or market information is not available, and it decreases as we reduce our unhedged positions, bid-offer spreads decrease, or market information becomes available. To the extent that we are not able to obtain observable market information for similar contracts, the close-out adjustment is equivalent to the initial contract margin, thereby recording no gain or loss at inception. In the absence of observable market information, there is a presumption that the transaction price is equal to the market value of the contract, and therefore we do not recognize a gain or loss at inception. We recognize such gains or losses in earnings as we realize cash flows under the contract or when observable market data becomes available.

• Credit-spread adjustment-for risk management purposes we compute the value of our mark-to-market energy assets and liabilities using a risk-free discount rate. In order to compute fair value for financial reporting purposes, we adjust the value of our mark-to-market energy assets to reflect the credit-worthiness of each customer (counterparty) based upon either published credit ratings, or equivalent internal credit ratings and associated default probability percentages.

We compute this adjustment by applying the appropriate default probability percentage to our outstanding credit exposure, net of collateral, for each counterparry. The level of this adjustment increases as our credit exposure to counterparties increases, the maturity terms of our transactions increase, or the credit ratings of our counterparties deteriorate, and it decreases when our credit exposure to counterparties decreases, the maturity terms of our transactions decrease, or the credit ratings of our counterparties improve.

Financial Statement Presentation Certain transactions entered into under master agreements and other arrangements provide our wholesale competitive supply operation with a right of setoff in the event of bankruptcy or default by the counterparty. We report such transactions net in our Consolidated Balance Sheets in accordance with FASB Interpretation No. 39, Offietting ofAmounts Related to Certain Contracts.

Equity in Earnings We include equity in earnings from our investments in qualifying facilities and power projects in "Nonregulated revenues" in our Consolidated Statements of Income in the period they are earned.

Fuel and Purchased Energy Expenses We incur costs for:

• the fuel we use to generate electricity,

+ purchases of electricity from others, and

• natural gas and coal that we resell.

These costs are included in "Fuel and purchased energy expenses" in our Consolidated Statements of Income. We discuss certain of these separately below. We also include certain non-fuel direct costs, such as ancillary services, transmission costs, and brokerage fees in "Fuel and purchased energy expenses" in our Consolidated Statements of Income.

Our retail competitive supply operation records changes in purchase contracts accounted for as mark-to-market in "Fuel and purchased energy expenses" in our Consolidated Statements of Income.

Fuel Used to Generate Electricity and Purchases of Electricity Nonregulated Businesses We assemble a variety of power supply resources, including baseload, intermediate, and peaking plants that we own, as well as a variety of power supply contracts that may have similar characteristics, in order to enable us to meet our customers' energy requirements, which vary on an hourly basis. The amount of power purchased depends on a number of factors, including the capacity and availability of our power plants, the level of customer demand, and the relative economics of generating power versus purchasing power from the spot market.

We also have acquired contracts and certain power purchase agreements that qualify as operating leases. Under these operating leases, we record fuel and purchased energy expense as we make fixed capacity payments, as well as variable payments based on the actual output of the plants.

80

We may make or receive cash payments at the time we acquire a contract or assume a power purchase agreement when the contract price differs from market prices at closing. We recognize the cash payment or receipt at inception in our Consolidated Balance Sheets as an "Unamortized energy contract" asset (payment) or liability (receipt). We amortize these assets and liabilities into fuel and purchased energy expenses based on the expected cash flows provided by the contracts.

Reulated Electric BGE is obligated to provide market-based standard offer service to residential and small commercial customers for the indefinite future, and for large commercial and industrial customers for varying periods beyond June 30, 2004, depending on customer load. The Provider of Last Resort (POLR) rates charged during these time periods will recover BGE's wholesale power supply costs and include an administrative fee. The administrative fee includes a shareholder return component and an incremental cost component. Pursuant to Senate Bill 1, the energy legislation enacted in Maryland in June 2006, collection of the shareholder return component of the administrative fee for residential POLR service will be suspended beginning January 1, 2007 for a 10-year period.

In accordance with the POLR settlement agreement approved by the Maryland PSC, BGE defers the difference between certain of its actual costs related to the electric commodity and what it collects from customers under the commodity charge in a given period. BGE either bills or refunds its customers the difference in the future. In addition, Senate Bill 1 imposed a 15% rate cap for BGE residential electric customers from July 1, 2006 until May 31, 2007. We discuss this in more detail in Note 6.

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

Reeulated Gas BGE charges its gas customers for the natural gas they purchase from BGE using "gas cost adjustment clauses" set by the Maryland PSC. Under these clauses, BGE defers the difference between certain of its actual costs related to the gas commodity and what it collects from customers under the commodity charge in a given period. BGE either bills or refunds its customers the difference in the future. The Maryland PSC approved a modification of the gas cost adjustment clauses to provide a market-based rates incentive mechanism. Under the market-based rates incentive mechanism, BGE's actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between BGE's actual cost and the market index is shared equally between shareholders and customers. Effective November 2001, the Maryland PSC approved a settlement that modifies certain provisions of the market-based rates incentive mechanism. These provisions require that BGE secure fixed-price contracts for at least 10%,

but not more than 20%, of forecasted system supply requirements for the November through March period. These fixed-price contracts are not subject to sharing under the market-based rates incentive mechanism.

Derivatives and Hedging Activities We are exposed to market risk, including changes in interest rates and the impact of market fluctuations in the price and transportation costs of electricity, natural gas, and other commodities as discussed further in Note 13. In order to manage these risks, we use both derivative and non-derivative contracts that may provide for settlement in cash or by delivery of a commodity, including:

• forward contracts, which commit us to purchase or sell energy commodities in the future,

+ futures contracts, which are exchange-traded standardized commitments to purchase or sell a commodity or financial instrument, or to make a cash settlement, at a specific price and future date,

• swap agreements, which require payments to or from counterparties based upon the differential between two prices for a predetermined contractual (notional) quantity, and

• option contracts, which convey the right to buy or sell a commodity, financial instrument, or index at a predetermined price.

SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, requires that we recognize at fair value all derivatives not qualifying for accrual accounting under the normal purchase and normal sale exception. We record derivatives that are designated as hedges in "Risk management assets or liabilities" and derivatives not designated as hedges in "Mark-to-market energy assets or liabilities" in our Consolidated Balance Sheets.

We record changes in the value of derivatives that are not designated as cash-flow hedges in earnings during the period of change. We record changes in the fair value of derivatives designated as cash-flow hedges that are effective in offsetting the variability in cash flows of forecasted transactions in other comprehensive income until the forecasted transactions occur. At the time the forecasted transactions occur, we reclassify the amounts recorded in other comprehensive income into earnings.

We record the ineffective portion of changes in the fair value of derivatives used as cash-flow hedges immediately in earnings.

81

We summarize our cash-flow hedging activities under SFAS No. 133 and the income statement classification of amounts reclassified from "Accumulated other comprehensive income (loss)" as follows:

Risk Interest rate risk associated with new debt issuances Interest rate risk associated with variable-rate debt Nonregulated energy sales Nonregulated fuel and energy purchases Nonregulated gas purchases for resale Regulated gas purchases for resale Regulated electricity purchases for resale Derivative Interest rate swaps Interest rate swaps Futures and forward contracts Futures and forward contracts Futures and forward contracts and price and basis swaps Price and basis swaps Price and basis swaps Income Statement Classification Interest expense Interest expense Nonregulated revenues Fuel and purchased energy expenses Fuel and purchased energy expenses Fuel and purchased energy expenses Fuel and purchased energy expenses "Risk management assets and liabilities" in our Consolidated Balance Sheets. In addition, we record the difference between interest on hedged fixed-rate debt and floating-rate swaps in "Interest expense" in the periods that the swaps settle.

Unamortized Energy Assets and Liabilities Unamortized energy contract assets and liabilities represent the remaining unamortized balance of non-derivative energy contracts that we acquired or derivatives designated as normal purchases and normal sales that we had previously recorded as "Mark-to-market energy assets or liabilities" or "Risk management assets and liabilities." The initial amount recorded represents the fair value of the contract at the time of acquisition or designation, and the balance is amortized over the life of the contract in relation to the present value of the underlying cash flows. The amortization of these values is discussed in the Revenues and Fuel and Purchased Energy Expenses sections of this Note.

Credit Risk Credit risk is the loss that may result from counterparty non-performance. We are exposed to credit risk, primarily through our merchant energy business. We use credit policies to manage our credit risk, including utilizing an established credit approval process, daily monitoring of counterparty limits, employing credit mitigation measures such as margin, collateral or prepayment arrangements, and using master netting agreements.

We measure credit risk as the replacement cost for open energy commodity and derivative positions (both mark-to-market and accrual) plus amounts owed from counterparties for settled transactions. The replacement cost of open positions represents unrealized gains, less any unrealized losses where we have a legally enforceable right of setoff.

Electric and gas utilities, municipalities, cooperatives, generation owners, and energy marketers comprise the majority of counterparties underlying our assets from our wholesale marketing and risk management activities. We held cash collateral from these counterparties totaling $252.6 million as of December 31, 2006 and $388.4 million as of December 31, 2005. These amounts are included in "Customer deposits and collateral" in our Consolidated Balance Sheets.

Taxes We summarize our income taxes in Note 10. BGE and our other subsidiaries record their allocated share of our consolidated federal income tax liability using the percentage complementary method specified in U.S. income tax regulations. As you read this section, it may be helpful to refer to Note 10.

Income Tax Expense We have two categories of income tax expense-current and deferred. We describe each of these below:

• current income tax expense consists solely of regular tax less applicable tax credits, and

+ deferred income tax expense is equal to the changes in the net deferred income tax liability, excluding amounts charged or credited to accumulated other comprehensive income. Our deferred income tax expense is increased or reduced for changes to the "Income taxes recoverable We designate certain derivatives as fair value hedges. We record changes in the fair value of these derivatives and changes in the fair value of the hedged assets or liabilities in earnings as the changes occur. We summarize our fair value hedging activities and the income statement classification of changes in the fair value of these hedges and the related hedged items as follows:

Risk Optimize mix of fixed and floating-rate debt Value of natural gas in storage Derivative Interest rate swaps Forward contracts and price and basis swaps Income Statement Classification Interest expense Nonregulated revenues and Fuel and purchased energy expenses We record changes in the fair value of interest rate swaps and the debt being hedged in "Risk management assets and liabilities" and "Long-term debt" and changes in the fair value of the gas being hedged and related derivatives in "Fuel stocks" and 82

through future rates (net)" regulatory asset (described below) during the year.

Tax Credits We have deferred the investment tax credits associated with our regulated business and assets previously held by our regulated business in our Consolidated Balance Sheets. The investment tax credits are amortized evenly to income over the life of each property. We reduce current income tax expense in our Consolidated Statements of Income for the investment tax credits and other tax credits associated with our nonregulated businesses.

We have certain investments in facilities that manufacture solid synthetic fuel produced from coal as defined under the Internal Revenue Code for which we claim tax credits on our Federal income tax return. We recognize the tax benefit of these credits in our Consolidated Statements of Income when we believe it is highly probable that the credits will be sustained.

Deferred Income Tax Assets and Liabilities We must report some of our revenues and expenses differently for our financial statements than for income tax return purposes.

The tax effects of the temporary differences in these items are reported as deferred income tax assets or liabilities in our Consolidated Balance Sheets. We measure the deferred income tax assets and liabilities using income tax rates that are currently in effect.

A portion of our total deferred income tax liability relates to our regulated business, but has not been reflected in the rates we charge our customers. We refer to this portion of the liability as "Income taxes recoverable through future rates (net)." We have recorded that portion of the net liability as a regulatory asset in our Consolidated Balance Sheets. We discuss this further in Note 6.

State and Local Taxes State and local income taxes are included in "Income taxes" in our Consolidated Statements of Income.

BGE also pays Maryland public service company franchise tax on distribution, and delivery of electricity and natural gas.

We include the franchise tax in "Taxes other than income taxes" in our Consolidated Statements of Income.

Earnings Per Share Basic earnings per common share (EPS) is computed by dividing earnings applicable to common stock by the weighted-average number of common shares outstanding for the year. Diluted EPS reflects the potential dilution of common stock equivalent shares that could occur if securities or other contracts to issue common stock were exercised or converted into common stock.

Our dilutive common stock equivalent shares consist of stock options and other stock-based compensation awards. The following table presents stock options that were not dilutive and were excluded from the computation of diluted EPS in each period, as well as the dilutive common stock equivalent shares as follows:

Year Ended December 31, Non-dilutive stock options Dilutive common stock equivalent shares 2006 2005 2004 (In millions) 0.1 2.0 2.2 1.0 Stock-Based Compensation Under our long-term incentive plans, we have granted stock options, performance-based units, performance and service-based restricted stock, and equity to officers, key employees, and members of the Board of Directors. We discuss these awards in more detail in Note 14.

We elected to early adopt SFAS No. 123 Revised (SFAS No. 123R), Share-Based Payment, on October 1, 2005, which was prior to the required effective date of January 1, 2006. SFAS No. 123R requires companies to recognize compensation expense for all equity-based compensation awards issued to employees that are expected to vest. Equity-based compensation awards include stock options, restricted stock, and any other share-based payments. We recognized a small, favorable cumulative effect of change in accounting principle of

$0.2 million after-tax due to the requirement to reduce compensation expense for estimated forfeitures relating to outstanding unvested service-based restricted stock awards and performance-based unit awards at October 1, 2005.

Under SFAS No. 123R, we recognize compensation cost ratably or in tranches (depending if the award has cliff or graded vesting) over the period during which an employee is required to provide service in exchange for the award, which is typically a one to five-year period. We use a forfeiture assumption to estimate the number of awards that are expected to vest during the service period, and ultimately true-up the estimated expense to the actual expense associated with vested awards. We estimate the fair value of stock option awards on the date of grant using the Black-Scholes option-pricing model and we remeasure the fair value of liability awards each reporting period. The following table presents the pro-forma effect on net income and earnings per share for all outstanding stock options and stock awards in each period that the fair value provisions of SFAS No. 123R were not in effect. We do not capitalize any portion of our stock-based compensation.

83

Year Ended December 31, 2005 2004 (In millions, except per share amounts)

Net income, as reported

$623.1

$539.7 Add: Actual stock-based compensation expense determined under intrinsic value method and included in reported net income, net of related tax effects 17.8*

13.2 Deduct: Pro-forma stock-based compensation expense determined under fair value based method for all awards, net of related tax effects (24.5)*

(21.3)

Pro-forma net income

$616.4

$531.6 Earnings per share:

Basic-as reported

$ 3.51

$ 3.14 Basic-pro-forma

$ 3.47

$ 3.09 Diluted-as reported

$ 3.47

$ 3.12 Diluted-pro-forma

$ 3.43

$ 3.07

• Represents expense for the nine months ended September 30, 2005, which was prior to adoption of SEAS No. 123R Cash and Cash Equivalents All highly liquid investments with original maturities of three months or less are considered cash equivalents.

Accounts Receivable and Allowance for Uncollectibles Accounts receivable, which includes cash collateral posted in our margin account with a third-parry broker, are stated at the historical carrying amount net of write-offs and allowance for uncollectibles. We establish an allowance for uncollectibles based on our expected exposure to the credit risk of customers based on a variety of factors.

Materials, Supplies, and Fuel Stocks We record our fuel stocks, emissions credits, coal held for resale, and materials and supplies at the lower of cost or market. We determine cost using the average cost method for all of our inventory other than our coal held for resale for which we use the specific identification method.

Financial Investments In Note 4, we summarize the financial investments that are in our Consolidated Balance Sheets.

SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities, applies particular requirements to some of our investments in debt and equity securities. We report those investments at fair value, and we use either specific identification or average cost to determine their cost for computing realized gains or losses.

A vailable-for-Sale Securities We classify our investments in the nuclear decommissioning trust funds as available-for-sale securities. We describe the nuclear decommissioning trusts and the related asset retirement obligations later in this Note. In addition, we have investments in marketable equity securities and trust assets securing certain executive benefits that are classified as available-for-sale securities.

We include any unrealized gains or losses on our available-for-sale securities in "Accumulated other comprehensive income" in our Consolidated Statements of Common Shareholders' Equity and Comprehensive Income and Consolidated Statements of Capitalization.

Evaluation of Assets for Impairment and Other Than Temporary Decline in Value Long-Lived Assets We are required to evaluate certain assets that have long lives (for example, generating property and equipment and real estate) to determine if they are impaired when certain conditions exist.

SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, provides the accounting requirements for impairments of long-lived assets and proved gas properties. We are required to test our long-lived assets and proved gas properties for recoverability whenever events or changes in circumstances indicate that their carrying amount may not be recoverable.

We determine if long-lived assets and proved gas properties are impaired by comparing their undiscounted expected future cash flows to their carrying amount in our accounting records.

We would record an impairment loss if the undiscounted expected future cash flows were less than the carrying amount of the asset. Cash flows for long-lived assets, or a group of long-lived assets, are determined at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. Proven gas properties' cash flows are determined at the field level. Undiscounted expected future cash flows include risk-adjusted probable and possible reserves.

We are also required to evaluate our equity-method and cost-method investments (for example, in partnerships that own power projects) for impairment. Accounting Principles Board (APB) No. 18, The Equity Method ofAccountingfor Investments in Common Stock (APB No. 18), provides the accounting requirements for these investments. The standard for determining whether an impairment must be recorded under APB No. 18 is whether the investment has experienced a loss in value that is considered an "other than a temporary" decline in value.

We are also required to evaluate unproved gas producing properties at least annually to determine if it is impaired under SFAS No. 19, FinancialAccounting and Reporting by Oil and Gas Producing Properties. Impairment for unproved property occurs if there are no firm plans to continue drilling, lease expiration is at risk, or historical experience necessitates a valuation allowance.

We use our best estimates in making these evaluations and consider various factors, including forward price curves for energy, fuel costs, legislative initiatives, and operating costs.

However, actual future market prices and project costs could vary from those used in our impairment evaluations, and the impact of such variations could be material.

Debt and Equity Securities Our investments in debt and equity securities, which primarily consist of our nuclear decommissioning trust fund investments, are subject to impairment evaluations under FASB Staff Position (FSP) FAS 115-1, The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments. FSP FAS 115-1 requires us to determine whether a decline in fair value of an investment below the amortized cost basis is other 84

than temporary. If we determine that the decline in fair value is judged to be other than temporary, the cost basis of the investment must be written down to fair value as a new cost basis.

Intangible Assets Goodwill is the excess of the purchase price of an acquired business over the fair value of the net assets acquired. We account for goodwill and other intangibles under the provisions of SFAS No. 142, Goodwill and Other Intangible Assets. We do not amortize goodwill. SFAS No. 142 requires us to evaluate goodwill for impairment at least annually or more frequently if events and circumstances indicate the business might be impaired. Goodwill is impaired if the carrying value of the business exceeds fair value. Annually, we estimate the fair value of the businesses we have acquired using techniques similar to those used to estimate future cash flows for long-lived assets as previously discussed. If the estimated fair value of the business is less than its carrying value, an impairment loss is required to be recognized to the extent that the carrying value of goodwill is greater than its fair value. SFAS No. 142 also requires the amortization of intangible assets with finite lives. We discuss the changes in our intangible assets in more detail in Note 5.

Property, Plant and Equipment, Depreciation, Depletion, Amortization, and Accretion of Asset Retirement Obligations We report our property, plant and equipment at its original cost, unless impaired under the provisions of SFAS No. 144.

Our original costs include:

• material and labor,

+ contractor costs, and

• construction overhead costs, financing costs, and costs for asset retirement obligations (where applicable).

We own an undivided interest in the Keystone and Conemnaugh electric generating plants in Western Pennsylvania, as well as in the transmission line that transports the plants' output to the joint owners' service territories. Our ownership interests in these plants are 20.99% in Keystone and 10.56% in Conemnaugh. These ownership interests represented a net investment of $183.1 million at December 31, 2006 and

$171.8 million at December 31, 2005. Each owner is responsible for financing its proportionate share of the plants' working funds. Working funds are used for operating expenses and capital expenditures. Operating expenses related to these plants are included in "Operating expenses" in our Consolidated Statements of Income. Capital costs related to these plants are included in "Nonregulated property, plant and equipment" in our Consolidated Balance Sheets.

The "Nonregulated property, plant and equipment" in our Consolidated Balance Sheets includes nonregulated generation construction work in progress of $229.5 million at December 31, 2006 and $228.8 million at December 31, 2005.

W~Qhen we retire or dispose of property, plant and equipment, we remove the asset's cost from our Consolidated Balance Sheets. We charge this cost to accumulated depreciation for assets that were depreciated under the group, straight-line method. This includes regulated properry, plant and equipment and nonregulared generating assets transferred from BCE to our merchant energy business. For all other assets, we remove the accumulated depreciation and amortization amounts from our Consolidated Balance Sheets and record any gain or loss in our Consolidated Statements of Income.

The costs of maintenance and certain replacements are charged to "Operating expenses" in our Consolidated Statements of Income as incurred.

Our oil and gas exploitation and production activities consist of working interests in gas producing fields. We account for these activities under the successful efforts method of accounting. Acquisition, development, and exploitation costs are capitalized as permitted by SFAS No. 19. Costs of drilling exploratory wells are initially capitalized and later charged to expense if reserves are not discovered or deemed not to be commercially viable. Other exploratory costs are charged to expense when incurred.

Capitalized exploratory well costs were $24.7 million at December 31, 2006 and $11.4 million at December 31, 2005, and do not include amounts that were capitalized and subsequently expensed within the same period. During 2006, there were $23.9 million of well costs capitalized at December 31, 2005 that were reclassified to well, facilities, and equipment based on the determination of proved reserves.

During 2005, there were $1.4 million of well costs capitalized at December 31, 2004 that were reclassified to well, facilities, and equipment based on the determination of proved reserves.

No exploratory well costs have been capitalized for a period greater than one year since the completion of drilling.

Depreciation and Depleton Espense We compute depreciation for our generating, electric transmission and distribution, and gas distribution facilities. We compute depletion for our exploitation and production activities.

Depreciation and depletion are determined using the following methods:

• the group straight-line method, approved by the Maryland PSC, applied to the average investment, adjusted for anticipated costs of removal less salvage, in classes of depreciable property based on an average rate of approximately 3.5% per year for our regulated

business,

• the group straight-line method using rates averaging approximately 2.5% per year for the fossil generating assets transferred from BCE to our merchant energy business and our nuclear generating assets,

• the modified units of production method (greater of straight-line method or units of production method) for fossil generating assets constructed after deregulation that were not previously owned by BCE, or

• the units-of-production method over the remaining life of the estimated proved reserves at the field level for acquisition costs and over the remaining life of proved developed reserves at the field level for development costs. The estimates for gas reserves are based on internal calculations.

85

Other assets are depreciated primarily using the straight-line method and the following estimated useful lives:

Asset Building and improvements Office equipment and furniture Transportation equipment Computer software Estimated Useful Lives 5 - 50 years 3 - 20 years 5 -

15 years 3 - 10 years Amortization Expense Amortization is an accounting process of reducing an amount in our Consolidated Balance Sheets over a period of time that approximates the useful life of the related item. W~(hen we reduce amounts in our Consolidated Balance Sheets, we increase amortization expense in our Consolidated Statements of Income.

Accretion Expense SFAS No. 143, Accountingfor Asset Retirement Obligations, provides the accounting requirements for recognizing an estimated liability for legal obligations associated with the retirement of tangible long-lived assets. In the fourth quarter of 2005, we adopted FIN 47, Accounting for Conditional Asset Retirement Obligations-an Interpretation of FASB Statement No. 143. FIN 47 clarifies that asset retirement obligations that are conditional upon a future event are subject to the provisions of SFAS No. 143. Our conditional asset retirement obligations relate primarily to asbestos removal at certain of our generating facilities. In 2005, we recorded an asset retirement obligation of

$13.9 million for these facilities and recorded a $7.4 million after-tax charge to earnings as a cumulative effect of change in accounting principle.

At December 31, 2006, $950.4 million of our total asset retirement obligation of $974.8 million was associated with the decommissioning of our nuclear power plants-Calvert Cliffs Nuclear Power Plant (Calvert Cliffs), Nine Mile Point Nuclear Station (Nine Mile Point) and R. E. Ginna Nuclear Power Plant (Cinna). The remainder of our asset retirement obligations is associated with our other generating facilities and certain other long-lived assets. From time to time, we will perform studies to updaxe our asset retirement obligations. We record a liability when we are able to reasonably estimate the fair value of any future legal obligations associated with retirement that have been incurred and capitalize a corresponding amount as part of the book value of the related long-lived assets.

The increase in the capitalized cost is included in determining depreciation expense over the estimated useful lives of these assets. Since the fair value of the asset retirement obligations is determined using a present value approach, accretion of the liability due to the passage of time is recognized each period to "Accretion of asset retirement obligations" in our Consolidated Statements of Income until the settlement of the liability. We record a gain or loss when the liability is settled after retirement for any difference between the accrued liability and actual costs. The change in our "Asset retirement obligations" liability during 2006 was as follows:

(In millions)

Liability at January 1, 2006

$908.0 Liabilities incurred 3.4 Liabilities settled (0.3)

Accretion expense 67.6 Revisions to cash flows (2.4)

Other (1.5)

Liability at December 31, 2006

$974.8 "Liabilities incurred" in the table above primarily reflect new asset retirement obligations recorded at our fossil generating facilities in Maryland. "Other" represents the asset retirement obligation associated with our gas-fired plants, which were sold in December 2006. At the time of the sale, the asset retirement obligation was transferred to the buyer of the gas-fired plants.

We discuss the sale of the gas-fired plants in more detail in Note 2.

Nuclear Fuel We amortize the cost of nuclear fuel, including the quarterly fees we pay to the Department of Energy for the future disposal of spent nuclear fuel, based on the energy produced over the life of the fuel. These fees are based on the kilowatt-hours of electricity sold. We report the amortization expense for nuclear fuel in "Fuel and purchased energy expenses" in our Consolidated Statements of Income.

Nuclear Decommissioning Effective January 1, 2003, we began to record decommissioning expense for Calvert Cliffs in accordance with SFAS No. 143. The "Asset retirement obligations" liability associated with the decommissioning of Calvert Cliffs was $332.4 million at December 31, 2006 and $308.2 million at December 31, 2005.

Our contributions to the nuclear decommissioning trust funds for Calvert Cliffs were $8.8 million for 2006, $17.6 million for 2005, and $22.0 million for 2004. Under the Maryland PSC's order deregulating electric generation, BCE's customers must pay a total of $520 million in 1993 dollars, adjusted for inflation, to decommission Calvert Cliffs. BCE is collecting this amount on behalf of and passing it to Calvert Cliffs. Calvert Cliffs is responsible for any difference between this amount and the actual costs to decommission the plant.

In 2006, BCE received approval from the Maryland PSC to continue annual customer collections of $18.7 million per year through December 31, 2016. BCE will be required to submit a filing to determine the level of customer contributions after December 31, 2016.

86

We began to record decommissioning expense for Nine Mile Point in accordance with SFAS No. 143 on January 1, 2003. The "Asset retirement obligations" liability associated with the decommissioning was $408.1 million at December 31, 2006 and $378.7 million at December 31, 2005. We determined that the decommissioning trust funds established for Nine Mile Point are adequately funded to cover the future costs to decommission the plant and as such, no contributions were made to the trust funds during the years ended December 31, 2006, 2005, and 2004.

Upon the closing of the Ginna acquisition in 2004, the seller transferred $200.8 million in decommissioning funds. In return, we assumed all liability for the costs to decommission the unit. We believe that this transfer will be sufficient to cover the future costs to decommission the plant and as such, no contributions were made to the trust funds during the years ended December 31, 2006, 2005, and 2004. Effective June 2004, we began to record decommissioning expense for Ginna in accordance with SFAS No. 143. The "Asset retirement obligations" liability associated with the decommissioning was

$209.9 million at December 31, 2006 and $196.6 million at December 31, 2005.

In accordance with Nuclear Regulatory Commission (NRC) regulations, we maintain external decommissioning trusts to fund the costs expected to be incurred to decommission Calvert Cliffs, Nine Mile Point, and Ginna. The NRC requires owners to provide financial assurance that they will accumulate sufficient funds to pay for the cost of nuclear decommissioning.

The assets in the trusts are reported in "Nuclear decommissioning trust funds" in our Consolidated Balance Sheets. These amounts are legally restricted for funding the costs of decommissioning. We classify the investments in the nuclear decommissioning trust funds as available-for-sale securities, and we report these investments at fair value in our Consolidated Balance Sheets as previously discussed in this Note. Investments by nuclear decommissioning trust funds are guided by the "prudent man" investment principle. The funds are prohibited from investing directly in Constellation Energy or its affiliates and any other entity owning a nuclear power plant.

As the owner of Calvert Cliffs we, along with other domestic utilities, were required by the Energy Policy Act of 1992 to make contributions to a fund for decommissioning and decontaminating the Department of Energy's uranium enrichment facilities. The contributions were paid by BGE over a 15 year period ending in 2006. BGE amortizes the deferred costs of decommissioning and decontaminating the Department of Energy's uranium enrichment facilities. The previous owners retained the obligation for Nine Mile Point and Ginna.

Capitalized Interest and Allowance for Funds Used During Construction Capitalized Interest Our nonregulated businesses capitalize interest costs under SFAS No. 34, Capitalizing Interest Costs, for costs incurred to finance our power plant construction projects, real estate developed for internal use, and other capital projects.

Allowance for Funds Used During Construction (AFC)

BGE finances its construction projects with borrowed funds and equity funds. BGE is allowed by the Maryland PSC to record the costs of these funds as part of the cost of construction projects in its Consolidated Balance Sheets. BGE does this through the AFC, which it calculates using rates authorized by the Maryland PSC. BGE bills its customers for the AFC plus a return after the utility property is placed in service.

The AFC rates are 9.4% for electric plant, 8.5% for gas plant, and 9.2% for common plant. BGE compounds AFC annually.

Long-Term Debt We defer all costs related to the issuance of long-term debt.

These costs include underwriters' commissions, discounts or premiums, other costs such as legal, accounting, and regulatory fees, and printing costs. We amortize these costs into interest expense over the life of the debt.

When BGE incurs gains or losses on debt that it retires prior to maturity, it amortizes those gains or losses over the remaining original life of the debt.

Accounting Standards Issued SFAS No. 157 In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. SFAS No. 157 defines fair value, establishes a framework for measuring fair value, and expands disclosures for fair value measurements. SFAS No. 157 is effective for all fair value measurements beginning January 1, 2008. We are currently assessing the potential impact of SFAS No. 157. Based upon our initial assessment, we believe that SFAS No. 157 will affect the accounting for derivatives, which is one of our critical accounting policies, in at least two ways:

• We record mark-to-market energy assets net of a close-out valuation adjustment, a portion of which represents the initial contract margin when we are unable to obtain observable market price information for similar contracts. As a result, we do not recognize gains or losses in earnings at the inception of such contracts; instead, we recognize gains or losses in earnings as we realize cash flows under the contract or when observable market data becomes available. In certain instances, SFAS No. 157 will require us to record mark-to-market energy assets at fair value without such a valuation adjustment, resulting in the potential for recognition of gains or losses in earnings at the inception of new mark-to-market derivative contracts executed after the effective date.

+ We presently determine fair value for mark-to-market energy liabilities and risk management liabilities for which prices are not available from external sources by discounting the expected cash flows from the contracts using a risk-free discount rate. We do not apply a credit-spread valuation adjustment to reflect our own credit risk in determining fair value for these liabilities.

SFAS No. 157 will require us to record all liabilities measured at fair value including the effect of the obligor's credit risk. As a result, we will have to apply a credit-spread adjustment in order to reflect our own credit risk in determining fair value for these liabilities, 87

which we expect would result in a lower recorded fair value for these liabilities.

Because SFAS No. 157 applies broadly to all fair value measurements, we have not completed our assessment of its requirements, the effects of which could extend beyond the matters discussed on the previous page. In accordance with the statement's provisions, we will record the initial effects of applying SFAS No. 157 by adjusting opening retained earnings as of the required January 1, 2008 adoption date for the effect of eliminating the close-out valuation adjustment for inception gains. The remaining impacts of adoption will be reflected in earnings in 2008. The ultimate impact of applying the provisions of SFAS No. 157 could be material to our, or BGE's, financial results.

FIN 48 In July 2006, the FASB issued Interpretation (FIN) No. 48, Accountingfor Uncertainty in Income Taxes. FIN 48 provides guidance for the recognition and measurement of an entity's uncertain tax positions through the use of a "more-likely-than-not" threshold. This threshold would be used to evaluate whether each tax position will be sustained based solely on its technical merits and assuming examination by a taxing authority.

FIN 48 must be applied to all tax positions beginning January 1, 2007. Based on the analysis performed to date, we estimate the adoption of FIN 48 will not have a material impact on our, or BGE's, financial results. As a result of pending implementation guidance, we are still evaluating the impact of FIN 48, and therefore the actual impact of FIN 48 on our, or BGE's, financial results could differ from the above estimate.

Accounting Standards Adopted SFAS No. 158 In September 2006, the FASB issued SFAS No. 158, Employers' Accountingfor Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 106 and 132(R). SFAS No. 158 requires the underfunded status of defined benefit postretirement plans to be recognized as a liability in the balance sheets. Unrecognized actuarial losses or gains, unrecognized prior service costs, and unrecognized transition amounts are recognized as part of accumulated other comprehensive income, net of tax. Subsequent changes in funded status are recognized in the year in which changes occur through accumulated other comprehensive income. SFAS No. 158 was effective for us on December 31, 2006.

Although we adopted SFAS No. 158 effective December 31, 2006, we were required to remeasure the additional minimum pension liability prior to calculating the impact of adopting SFAS No. 158. As a result, we recorded a

$75.6 million after-tax increase to accumulated other comprehensive income to reduce the additional minimum pension liability at December 31, 2006. This reflected favorable asset returns and an increase in our discount rate assumption in 2006.

We recorded an after-tax decrease to accumulated other comprehensive income of $169.5 million at December 31, 2006 upon the adoption of SFAS No. 158. This reflected the requirement in SFAS No. 158 to begin reflecting the funded status for postretirement benefit plans and to begin using the higher projected benefit obligation measure to reflect pension plan funded status. The adoption of SFAS No. 158 did not have any impact on BGE's financial results or our, or BGE's, debt covenants. We discuss the additional minimum pension liability and the adoption of SFAS No. 158 in more detail in Note 7.

FSP FIN 46R-6 In April 2006, the FASB issued Staff Position (FSP) FIN 46R-6, Determining the Variability to Be Considered in Applying FASB Interpretation No. 46R. FSP FIN 46R-6 provides that, in applying FASB Interpretation No. 46R, Consolidation of Variable Interest Entities an Interpretation ofARB No. 51, the reporting enterprise should consider the design of the entity, the nature of the entity's risks, and the purpose for which the entity was created. FSP FIN 46R-6 must be applied prospectively to new or modified contracts beginning July 1, 2006. The adoption of this FSP did not have a material impact on our, or BGE's, financial results.

FSP FAS 115-1 and FAS 124-1 In November 2005, FASB Staff Position SFAS 115-1 and SFAS 124-1 (FSP FAS 115-1 and FAS 124-1), The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments, was issued to replace the measurement and recognition criteria of EITF 03-1, The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments.

FSP FAS 115-1 and FAS 124-1 references existing guidance in SFAS No. 115, SEC Staff Accounting Bulletin No. 59, Accountingfor Noncurrent Marketable Equity Securities, and APB No. 18. FSP FAS 115-1 and FAS 124-1 requires an other-than-temporary analysis to be completed each reporting period (i.e.,

every quarter) beginning after December 15, 2005. The adoption of this standard did not have a material impact on our, or BGE's, financial results.

SAB 108 In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 108 (SAB 108), Considering the Effects of Prior Year Misstatements when Quanti~jing Misstatements in Current Year Financial Statements. SAB 108 was issued in order to eliminate the diversity in practice surrounding how public companies quantify financial statement misstatements.

SAB 108 establishes an approach that requires quantification of financial statement misstatements based on the effects of the misstatements on each financial statement and the related financial statement disclosures. This model requires quantification of errors based on both an income statement and balance sheet approach. SAB 108 required public companies to initially apply its provisions for fiscal periods ending after November 15, 2006.

The implementation of SAB 108 did not have any effect on our financial results.

88

2 Other Events 2006 Events Pre-Tax After-Tax (In millions)

Gain on sale of gas-fired plants

$ 73.8

$ 47.1 Workforce reduction costs (28.2)

(17.0)

Merger-related costs (18.3)

(5.7)

Gain on initial public offering of Constellation Energy Partners LLC 28.7 17.9 Income from discontinued operations High Desert 294.1 186.9 International investments 1.4 0.9 Total income from discontinued operations 295.5 187.8 Total other items

$351.5

$230.1 Sale of Gas-Fired Plants In December 2006, we completed the sale of the following natural gas-fired plants owned by our merchant energy business:

At the time of the agreement for sale, we evaluated these plants for classification as discontinued operations under SFAS No. 144. Discontinued operations classification only applies to assets held for sale that meet the definition of a component of an entity. A component of an entity comprises operations and cash flows that can be clearly distinguished, operationally and for financial reporting purposes, from the rest of the entity.

High Desert met the requirements to be classified as a discontinued operation because it had a power sales agreement for its full output, was determined to be a component of Constellation Energy, and had separately identifiable cash flows. The table below provides additional detail about the amounts recorded in "Income from discontinued operations" related to our High Desert facility.

The remaining gas-fired plants were managed within our merchant business as a group or on a portfolio basis because they have aggregated risks, were hedged as a group, and generated joint cash flows. These gas-fired plants do not meet the requirements to be classified as discontinued operations.

The results of operations for these gas-fired plants, as well as the $73.8 million pre-tax gain on sale, remain classified in continuing operations.

International Investments In the fourth quarter of 2005, we completed the sale of Constellation Power International Investments, Ltd. (CPII).

We recognized an after-tax gain of $0.9 million for the year ended December 31, 2006 due to the resolution of an outstanding contingency related to the sale. We discuss the details of the outstanding contingency later in this Note.

Presented in the table below are the amounts related to those discontinued operations that are included in "Income from discontinued operations" in our Consolidated Statements of Income:

Facility High Desert Rio Nogales Holland University Park Big Sandy Wolf Hills Capacity (MW 830 800 665 300 300 250 Unit Type Combined Cycle Combined Cycle Combined Cycle Peaking Peaking Peaking Location California Texas Illinois Illinois West Virginia Virginia We sold these gas-fired plants for cash of $1.6 billion, which is subject to working capital adjustments, and recognized a pre-tax gain on the sale of $259.0 million of which

$73.8 million was included in "Gain on sale of gas-fired plants" and $185.2 million was included in "Income from discontinued operations" in our Consolidated Statements of Income.

High Desert 2006 2005 2004 Oleander Intrenational Investments 2006 2005 2004 2006 2005 2004 (In millions)

Total 2006 2005 2004 Revenues

$ 161.2 $ 163.7

$ 159.2

$ 14.7 $42.5

-$228.1

$ 219.7 $ 161.2 $406.5

$421.4 Income befote income taxes 108.9 111.0 106.9 8.5 20.5 14.5 16.8 108.9 134.0 144.2 Net income 70.2 70.8 68.4 5.3 12.6 4.5 9.4 70.2 80.6 90.4 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 Income from discontinued operations, net of taxes 186.9 70.8 68.4 3.0 12.6 0.9 20.6 9.4 187.8 94.4 90.4 We recognized a pre-tax loss from discontinued operations of $(75. 6) million, before income taxes of $(26.5) million from the sale of our Hawaiian Geothermal facility in 2004. We discuss the sale of this facility later in this Note.

89

Workforce Reduction Costs In March 2006, we approved a restructuring of the workforce at our Ginna nuclear facility. In connection with this restructuring, 32 employees were terminated. During the quarter ended March 31, 2006, we recognized costs of

$2.2 million pre-tax related to recording a liability for severance and other benefits under our existing benefit programs.

We completed this workforce reduction effort in 2006. As a result, no involuntary severance liability was recorded at December 31, 2006.

In July 2006, we announced a planned restructuring of the workforce at our Nine Mile Point nuclear facility. We recognized costs during the quarter ended September 30, 2006 of $15.1 million pre-tax related to the elimination of 126 positions associated with this restructuring. We also initiated a restructuring of the workforce at our Calvert Cliffs nuclear facility during the third quarter of 2006 and we recognized costs of $2.9 million pre-tax related to the elimination of 30 positions associated with this restructuring.

In addition, we incurred a pre-tax settlement charge of

$12.7 million in accordance with Statement of Financial Accounting Standards (SFAS) No. 88, Employers'Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits. This charge reflects recognition of the portion of deferred actuarial gains and losses associated with employees who were terminated as part of the restructuring or retired in 2006 and who elected to receive their pension benefit in the form of a lump-sum payment. In accordance with SFAS No. 88, a settlement charge must be recognized when lump-sum payments exceed annual pension plan service and interest cost. The total SFAS No. 88 settlement charge incurred in 2006 includes a pre-tax charge of $8.0 million as a result of the Nine Mile Point restructuring. We discuss the settlement charges that we recorded during 2006 in Note 7.

The following table summarizes the status of the involuntary severance liability for Nine Mile Point and Calvert Cliffs at December 31, 2006:

Merger-Related costs We incurred costs during 2006 related to the proposed merger with FPL Group. The merger was terminated in October 2006.

These costs totaled $18.3 million pre-tax for 2006. In addition, during 2006 we recognized tax benefits of $5.3 million on merger costs incurred in 2005 that were not considered deductible for income tax purposes until the termination of the merger in 2006. Our total pre-tax merger-related costs were

$35.3 million.

Initial Public Offering of Constellation Energy Partners LLC In November 2006, Constellation Energy Partners LLC (CEP),

a limited liability company formed by Constellation Energy, completed an initial public offering of 5.2 million common units at $21 per unit. The initial public offering resulted in cash proceeds of $101.3 million, after expenses associated with the offering, for Constellation Energy.

We continue to own approximately 54% of CEP and as a result, we continue to consolidate CEP. As a result of the initial public offering of CEP, we recognized a pre-tax gain of

$28.7 million, or $17.9 million after recording deferred taxes on the gain.

2005 Events Pre-Tax After-Tax (In millions)

Merger-related costs

$ (17.0)

$ (15.6)

Workforce reduction costs (4.4)

(2.6)

Income from discontinued operations High Desert 111.0 70.8 International investments 40.1 20.6 Oleander 4.9 3.0 Total income from discontinued operations 156.0 94.4 Total other items

$134.6

$ 76.2 "Incomefrom discontinued operations" reflects the reclassification of earnings from our High Desert facility as required by SFAS No. 144.

Merger-Related Costs We incurred external costs associated with the execution of the agreement relating to our proposed merger with FPL Group.

We discuss the terminated merger in more detail in Note 15.

Workforce Reduction Costs As a result of the workforce reduction efforts initiated in 2004, in 2005 we were required to record a pre-tax settlement charge in our Consolidated Statements of Income of $4.4 million for one of our qualified pension plans under SFAS No. 88.

In 2005, we completed the 2004 workforce reduction effort. As a result, no involuntary severance liability was recorded at December 31, 2005.

Initial severance liability balance Amounts recorded as pension and postretirement liabilities Net cash severance liability Cash severance payments Other Severance liability balance at December 31, 2006 (In millions)

$19.6 (7.3) 12.3 (3.2)

$ 9.1 The severance liability above includes $1.6 million of costs that the joint owner of Nine Mile Point Unit 2 reimbursed us.

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Discontinued Operations Oleander In March 2005, we reached an agreement in principle to sell our Oleander generating facility, a four-unit peaking plant located in Florida. Our merchant energy business classified 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 than its fair value less costs to sell, and therefore in March 2005 we recorded an impairment charge of $4.8 million pre-tax as part of discontinued operations.

In June 2005, we completed the sale of this facility for

$217.6 million, and recognized a pre-tax gain on the sale of

$1.2 million as part of discontinued operations.

International Investments In October 2005, we sold CPII. CPII held our other nonregulated international investments, which represented an interest in a Panamanian electric distribution company and an investment in a fund that holds interests in two South American energy projects. We received cash of $71.8 million and recognized a pre-tax gain of approximately $25.6 million, or $16.1 million after-tax. An additional $3.6 million of the sales price was contingent upon the collection of certain receivables by March 31, 2006. At December 31, 2005, we recognized approximately $2.2 million of this amount based on cash collections, which was included in the $25.6 million pre-tax gain. We recognized the remaining $1.4 million of contingent proceeds in 2006 once realization was assured beyond a reasonable doubt.

2004 Events Pre-Tax After-Tax (In millions)

Workforce reduction costs

$ (9.7)

$ (5.9)

Recognition of 2003 synthetic fuel tax credits 35.9 (Loss) income from discontinued operations Hawaiian geothermal facility (75.6)

(49.1)

High Desert 106.9 68.4 International investments 16.8 9.4 Oleander 20.5 12.6 Total income from discontinued operations 68.6 41.3 Total other items

$ 58.9

$ 71.3 "Income from discontinued operations "reflects the reclassification of/earnings from our High Desert facility, the Oleander facility, and our international investments as required by SFAS No. 144.

Workforce Reduction Costs In the fourth quarter of 2004, we approved a restructuring of the work forces of the Nine Mile Point and Calvert Cliffs nuclear generating stations that was effective in January 2005.

In connection with this restructuring, approximately 108 employees received severance and other benefits under our existing benefit programs. At December 31, 2004, we accrued the estimated total cost of this reduction in workforce of

$9.7 million pre-tax, or $5.9 million after-tax, in accordance with applicable accounting requirements.

S~ynthetic Fuel Tax Credits In 2003, we purchased a 99% ownership in a South Carolina facility that produces synthetic fuel. We did not recognize in our Consolidated Statements of Income the tax benefit of

$35.9 million for credits claimed on our South Carolina facility in 2003 pending receipt of a favorable private letter ruling from the Internal Revenue Service (IRS). In April 2004, we received a favorable private letter ruling. We believe receipt of the private letter ruling provided assurance that it is highly probable that the credits will be sustained. Therefore, we recognized the tax benefit of $35.9 million in our Consolidated Statements of Income in 2004. We discuss the synthetic fuel tax credits in more detail in Note J0.

Discontinued Operations Geothermal Fclt In March 2004, management committed to a plan to sell our geothermal generating facility in Hawaii that met the "held for sale" criteria under SFAS No. 144. Under SFAS No. 144, we record assets and liabilities held for sale at the lesser of the carrying amount or fair value less cost to sell.

The fair value of the facility as of March 31, 2004, based on the bids under consideration, was below carrying value.

Therefore, we recorded a $71.6 million pre-tax, or

$47.3 million after-tax, impairment charge during the first.

quarter of 2004. We reported the after-tax impairment charge as a component of "Loss from discontinued operations" in our Consolidated Statements of Income. Additionally, we recognized $1.5 million pre-tax, or $1.0 million after-tax, of earnings from the facility for the quarter ended March 31, 2004 as a component of "Loss from discontinued operations."

In June 2004, we completed the sale of the facility. Based on the final sales price and other costs incurred over the remainder of the year, we recognized an additional loss of

$5.5 million pre-tax, or $2.8 million after-tax. The sale of this facility was reflected in our merchant energy business reportable segment.

91

3Information by Operating Segment Our reportable operating segments are-Merchant Energy, Regulated Electric, and Regulated Gas:

• Our merchant energy business is nonregulated and includes:

- full requirements load-serving sales of energy and capacity to utilities, cooperatives, and commercial, industrial, and governmental customers,

- structured transactions and risk management services for various customers (including hedging of output from generating facilities and fuel costs),

- deployment of risk capital through portfolio management and trading activities,

- gas retail energy products and services to commercial, industrial, and governmental customers,

- fossil, nuclear, and interests in hydroelectric generating facilities and qualifying facilities, fuel processing facilities, and power projects in the United States,

- upstream (exploration and production) and downstream (transportation and storage) natural gas operations,

- coal sourcing services for the variable or fixed supply needs of global customers, and

- generation operations and maintenance services.

• Our regulated electric business purchases, transmits, distributes, and sells electricity in Central Maryland.

• Our regulated gas business purchases, transports, and sells natural gas in Central Maryland.

Our remaining nonregulated businesses:

• design, construct, and operate heating, cooling, and cogeneration facilities for commercial, industrial, and governmental customers throughout North America, and

• provide home improvements, service electric and gas appliances, service heating, air conditioning, plumbing, electrical, and indoor air quality systems, and provide natural gas marketing to residential customers in Central Maryland.

During 2006, we sold six of our gas-fired facilities. In addition, we own several investments that we do not consider to be core operations. These include financial investments and real estate projects. During 2005, we sold our other nonregulated international investments. We discuss the sales of our gas-fired plants and our international investments in more detail in Note 2.

Our Merchant Energy, Regulated Electric, and Regulated Gas reportable segments are strategic businesses based principally upon regulations, products, and services that require different technology and marketing strategies. We evaluate the performance of these segments based on net income. We account for intersegment revenues using market prices. We present a summary of information by operating segment on the next page.

92

Reportable Segments Merchant Energy Regulated Electric Regulated Gas Other Nonregulated Business Business Business Businesses Eliminations Consolidated (In millions) 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 (a) 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 (b) 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 2004 Unaffiliated revenues

$ 9,203.7

$1,967.6 755.0

$200.9

$ 12,127.2 Intersegment revenues 984.6 0.1 2.0 0.2 (986.9)

Total revenues Depreciation and amortization Fixed charges Income tax expense (benefit)

Income from discontinued operations Net income (loss) (c)

Segment assets Capital expenditures 10,188.3 221.9 196.2 22.8 31.9 389.9 12,395.6 455.0 1,967.7 194.2 80.3 86.8 131.1 3,402.2 209.0 757.0 48.1 29.1 15.9 22.2 1,163.4 56.0 201.1 24.2 15.4 (7.1) 9.4 (3.5) 675.7 42.0 (986.9) 12,127.2 488.4 5.8 326.8 118.4 41.3 539.7 (289.8) 17,347.1 762.0 Certain prior-year amounts have been reclassified to conform with the current year ipresentation. The reclassifications primarily relate to operations that have been classified as discontinued operations in the current year.

(a)

Our merchant energy business recognized an after-tax gain of $47.1 million on sale ofgas-fired plants and an after-tax gain of

$17.9 million on the initial public offering of Constellation Energy Partners LLC as discussed in more detail in Note 2. Our merchant energy business, our regulated electric business, our regulated gas 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-related costs and workforce reduction costs as described in more detail in Note 2.

(b)

Our merchant energy business, our regulated electric business, our regulated gas business, and our other nonregulated businesses 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.

(c)

Our merchant energy business recognized after-tax income of $30.0 million, for recognition of2003 synthetic fuel tax credits and workforce reduction costs as described in more detail in Note 2.

93

4 Investments Investments in Qualifying Facilities and Power Projects Our merchant energy business holds up to a 50% voting interest in 24 operating domestic energy projects that consist of electric generation, fuel processing, or fuel handling facilities.

Of these 24 projects, 17 are "qualifying facilities" that receive certain exemptions and pricing under the Public Utility Regulatory Policies Act of 1978 based on the facilities' energy source or the use of a cogeneration process.

Investments in qualifying facilities and domestic power projects held by our merchant energy business consist of the following:

AtDecember3l, 2006 2005 (In millions)

Coal

$125.7

$127.8 Hydroelectric 55.1 55.9 Geothermal 40.5 43.7 Biomass 46.6 48.0 Fuel Processing 33.7 23.8 Solar 7.0 7.0 Total

$308.6

$306.2 Investments in qualifying facilities and domestic power projects were accounted for under the following methods:

AtDecember3l, 2006 2005 (In millions)

Equity method

$301.6

$299.2 Cost method 7.0 7.0 Total power projects

$308.6

$306.2 Our percentage voting interest in qualifying facilities and domestic power projects accounted for under the equity method ranges from 16% to 50%. Equity in earnings of these power projects was $13.8 million in 2006, $3.6 million in 2005, and $18.0 million in 2004.

Our power projects include investments of $220.5 million in 2006 and $228.6 million in 2005 that sell electricity in California under power purchase agreements.

Investments Classified as Available-for-Sale We classify the following investments as available-for-sale:

• nuclear decommissioning trust funds,

• marketable equity securities, and

• trust assets securing certain executive benefits.

This means we do not expect to hold them to maturity, and we do not consider them trading securities.

We show the fair values, gross unrealized gains and losses, and amortized cost basis for all of our available-for-sale securities, in the following tables. We use specific identification to determine cost in computing realized gains and losses.

Amortized At December 31, 2006 Cost Basis Unrealized Unrealized Fair Gains Losses Value (In millions)

Marketable equity securities

$ 811.0

$221.1

$(3.3)

$1,028.8 Corporate debt and U.S. treasuries 160.1 1.9 (0.3) 161.7 State municipal bonds 68.1 5.4 (0.2) 73.3 Totals

$1,039.2

$228.4

$(3.8)

$1,263.8 Amortized Unrealized Unrealized Fair At December 31, 2005 Cost Basis Gains Losses Value (In millions)

Marketable equity securities 804.4

$112.7

$(3.8) 913.3 Corporate debt and U.S. treasuries 114.8 0.2 (1.4) 113.6 State municipal bonds 107.1 2.8 (0.8) 109.1 Totals

$1,026.3

$115.7

$(6.0)

$1,136.0 In addition to the above securities, the nuclear decommissioning trust funds included $24.1 million at December 31, 2006 and $12.2 million at December 31, 2005 of cash and cash equivalents.

The preceding tables include $206.1 million in 2006 of net unrealized gains and $110.3 million in 2005 of net unrealized gains associated with the nuclear decommissioning trust funds that are reflected as a change in the nuclear decommissioning trust funds in our Consolidated Balance Sheets.

We have unrealized losses relating to certain available-for-sale investments included in our decommissioning trust funds.

We believe these losses are temporary in nature and expect the investments to recover their value in the future. We show the fair values and unrealized losses of our investments that were in a loss position at December 31, 2006 and 2005 in the tables below.

At December 31, 2006 Less than 12 months or 12 months more Total Description of Fair Unrealized Fair Unrealized Fair Unrealized Securities Value Losses Value Losses Value Losses (In millions)

Marketable equity securities

$ 9.5

$(0.8)

$12.4

$(1.7)

$21.9

$(2.5)

Corporate debt and U.S.

treasuries 10.3 23.7 (0.3) 34.0 (0.3)

State municipal bonds 4.8 14.0 (0.2) 18.8 (0.2)

Total temporarily impaired securities

$24.6

$(0.8)

$50.1

$(2.2)

$74.7

$(3.0) 94

At December 31, 2005 Less than 12 months or 12 months more Total Description of Fair Unrealized Fair Unrealized Fair Unrealized Securities Value Losses Value Losses Value Losses (In millions)

Marketable equity securities

$ 22.3

$(2.9)

$ 2.3

$(0.3)

$ 24.6

$(3.2)

Corporate debt and U.S.

treasuries 71.8 (1.1) 11.8 (0.3) 83.6 (1.4)

State municipal bonds 46.0 (0.6) 11.8 (0.2) 57.8 (0.8)

Total temporarily impaired securities

$140.1

$(4.6)

$25.9

$(0.8)

$166.0

$(5.4)

Gross and net realized gains and losses on available-for-sale securities were as follows:

2006 2005 2004 (In millions)

Gross realized gains

$ 13.3

$12.3

$ 4.1 Gross realized losses (13.0)

(9.3)

(7.7)

Net realized gains (losses) 0.3

$ 3.0

$(3.6)

Gross realized losses for 2004 include a $4.5 million pre-tax impairment charge we recognized on a nuclear decommissioning trust fund investment that we believed represented an other than temporary decline in value.

The corporate debt securities, U.S. Government agency obligations, and state municipal bonds mature on the following schedule:

At December 31, 2006 (In millions)

Less than 1 year 7.6 1-5 years 74.9 5-10 years 62.4 More than 10 years 90.1 Total maturities of debt securities

$235.0 Investments in Variable Interest Entities We have a significant interest in the following variable interest entities (VIE) for which we are not the primary beneficiary:

The following is summary information available as of December 31, 2006 about the VIEs in which we have a significant interest, but are not the primary beneficiary:

Power M

Total assets Total liabilities Our ownership interest Other ownership interests Our maximum exposure to loss Contract All lonetization Other VIEs VIEs (In millions)

$746.1

$355.5 592.6 162.0 51.5 Total

$1,101.6 754.6 51.5 153.5 142.0 295.5 65.8 92.3 158.1 The maximum exposure to loss represents the loss that we would incur in the unlikely event that our interests in all of these entities were to become worthless and we were required to fund the full amount of all guarantees associated with these entities. Our maximum exposure to loss as of December 31, 2006 consists of the following:

+ outstanding receivables, loans, and letters of credit totaling $94.0 million,

• the carrying amount of our investment totaling

$51.4 million, and

• debt and performance guarantees totaling

$12.7 million.

We assess the risk of a loss equal to our maximum exposure to be remote.

Customer Contract Restructurin.

In March 2005, our merchant energy business closed a transaction in which we assumed from a counterparty two power sales contracts with existing VIEs. Under the contracts, we sell power to the VIEs which, in turn, sell that power to an electric distribution utility through 2013.

The VIEs previously were created by the counterparty to issue debt in order to monetize the value of the original contracts to purchase and sell power. The difference between the contract prices at which the VIEs purchase and sell power is used to service the debt of the VIEs, which totaled

$568 million at December 31, 2006.

The market price for power at the closing of our transaction was higher than the contract price under the existing power sales contracts we assumed. Therefore, we received compensation totaling $308.5 million, equal to the net present value of the difference between the contract price under the power sales contracts and the market price of power at closing. We used a portion of this amount to settle

$68.5 million of existing derivative liabilities with the same counterparty, and we also loaned $82.8 million to the holder of the equity in the VIEs. As a result, we received net cash at closing of $157.2 million. We also guaranteed our subsidiaries' performance under the power sales contracts.

VIE Power projects and fuel supply entities Power contract monetization entities Oil & gas fields Retail power supply Nature of Involvement Equity investment and guarantees Power sale agreements, loans, and guarantees Equity investment Power sale agreement Date of Involvement Prior to 2003 March 2005 May 2006 September 2006 We discuss the nature of our involvement with the power contract monetization VIEs in the Customer Contract Restructuring section below.

95

The table below summarizes the transaction and the net cash received at closing:

(In millions)

Gross compensation from original power sales contracts counterparty equal to fair value of power sales contracts at closing

$308.5 Settlement of existing derivative liabilities (68.5)

Third-party loan secured by equity in VIE (82.8)

Net cash received at closing

$157.2 We recorded the closing of this transaction in our financial statements as follows:

Balance Sheet Cash Flows We recorded the gross compensation we received to assume the power sales contracts as a financing cash inflow because it constitutes a prepayment for a portion of the market price of power, which we will sell to the VIEs over the term of the contracts and does not represent a cash inflow from current period operating activities. We record the ongoing cash flows related to the sale of power to the VIEs as a financing cash inflow in accordance with SFAS No. 149, Amendment of FASB Statement No. 133 on Derivative and Hedging Activities.

If the electric distribution utility were to default under its obligation to buy power from the VIEs, the equity holder could transfer its equity interests to us in lieu of repaying the loan. In this event, we would have the right to seek recovery of our losses from the electric distribution utility.

Fair value of power sales contracts assumed (designated as cash-flow hedge)

Settlement of existing derivative liabilities Third-party loan Risk management liabilities Mark-to-market and risk management liabilities Other assets Financing cash inflow Operating cash outflow Investing cash outflow 96

5 Intangible Assets Goodwill Goodwill is the excess of the cost of an acquisition over the fair value of the net assets acquired. Our goodwill balance is primarily related to our merchant energy business acquisitions that occurred in 2002 and 2003. The changes in the carrying amount of goodwill for the years ended December 31, 2006 and 2005 are as follows:

Balance at Goodwill Balance at 2006 January 1, Acquired Other(a)

December 31, (In millions)

Goodwill

$147.1

$11.1

$(0.6)

$157.6 Balance at Goodwill Balance at 2005 January 1, Acquired Other December 31, (In millions)

Goodwill

$144.8

$2.3

$147.1 (a)

Other represents purchase price adjustments.

Goodwill is not amortized; rather, it is evaluated for impairment at least annually. We evaluated our goodwill in 2006 and 2005 and determined that it was not impaired. For tax purposes, $128.5 million of our goodwill balance is deductible.

Intangible Assets Subject to Amortization Intangible assets with finite lives are subject to amortization over their estimated useful lives. The primary assets included in this category are as follows:

At December 31, 2006 2005 Accumul-Accumul-Gross ated Gross ated Carrying Amortiz-Net Carrying Amortiz-Net Amount ation Asset Amount ation Asset (In millions)

Software

$392.3

$(182.6) $209.7

$364.7

$(156.5) $208.2 Permits and licenses 60.4 (5.9) 54.5 49.4 (12.6) 36.8 Operating manuals and procedures 38.5 (7.1) 31.4 38.6 (6.0) 32.6 Other 26.3 (17.2) 9.1 29.7 (14.3) 15.4 Total

$517.5

$(212.8)

$304.7

$482.4

$(189.4)

$293.0 BGE had intangible assets with a gross carrying amount of$191.3 million and accumulated amortization of $109.2 million at December 31, 2006 and $181.4 million and accumulated amortization of $98.7 million at December 31, 2005 that are included in the table above. Substantially all of BGE's intangible assets relate to software.

We recognized amortization expense related to our intangible assets as follows:

Year Ended December 31, 2006 2005 2004 (In millions)

Nonregulated businesses

$37.2

$30.6

$25.0 BGE 18.6 26.3 41.4 Total Constellation Energy

$55.8

$56.9

$66.4 The following is our, and BGE's, estimated amortization expense for 2007 through 2011 for the intangible assets included in our, and BGE's, Consolidated Balance Sheets at December 31, 2006:

Year Ended December 31, 2007 2008 2009 2010 2011 (In millions)

Estimated amortization expense-Nonregulated businesses

$41.6

$36.3

$29.0

$20.8

$15.2 Estimated amortization expense-BGE 19.3 16.7 13.4 12.0 9.9 Total estimated amortization expense-Constellation Energ

$60.9

$53.0

$42.4

$32.8

$25.1 Unamortized Energy Contracts As discussed in Note 1, unamortized energy contract assets and liabilities represent the remaining unamortized balance of nonderivative energy contracts acquired or derivatives designated as normal purchases and normal sales, which we previously recorded as mark-to-market energy or risk management assets and liabilities.

During 2005, we acquired several pre-existing nonderivative contracts that had been originated by other parties in prior periods when market prices were lower than current levels. We received approximately $530 million in cash and other consideration and recorded a liability in "Unamortized energy contracts." In addition, during 2005, we designated as normal purchases and normal sales contracts that we had previously recorded as cash-flow hedges in "Risk management liabilities."

This resulted in a reclassification of $888.5 million from "Risk management liabilities" to "Unamortized energy contract liabilities."

We present separately in our Consolidated Balance Sheets the net unamortized energy contract assets and liabilities for these contracts. The table below presents the gross and net carrying amount and accumulated amortization of the net liability that we have recorded in our Consolidated Balance Sheets:

At December 31 2006 2005 Accumul-Accumul-ated ated Carrying Amortiz-Net Carrying Amortiz-Net Amount anon Liability Amount ation Liability (In millions)

Unamortized energy contracts, net $(1,642.0)

$ 464.5

$(1,177.5)$(1,449.2) $ 37.8

$(1,411.4)

The table below presents the estimated net favorable impact on our operating results for the amortization for these assets and liabilities over the next five-years:

Year Ended December 31, 2007 2008 2009 2010 2011 (In millions)

Estimated amortization

$342.8

$255.4

$178.0

$166.6

$41.8 97

6Regulatory Assets (net)

As discussed in Note 1, the Maryland PSC and the FERC provide the final determination of the rates we charge our customers for our regulated businesses. Generally, we use the same accounting policies and practices used by nonregulated companies for financial reporting under accounting principles generally accepted in the United States of America. However, sometimes the Maryland PSC or FERC orders an accounting treatment different from that used by nonregulated companies to determine the rates we charge our customers. When this happens, we must defer certain regulated expenses and income in our Consolidated Balance Sheets as regulatory assets and liabilities. We then record them in our Consolidated Statements of Income (using amortization) when we include them in the rates we charge our customers.

We summarize regulatory assets and liabilities in the following table, and we discuss each of them separately below.

At December31, 2006 2005 (In millions)

Deferred fuel costs Rate stabilization deferral

$ 326.9 Other 37.8 16.2 Electric generation-related regulatory asset 154.8 173.6 Net cost of removal (161.3)

(148.7)

Income taxes recoverable through future rates (net) 67.1 70.9 Deferred postretirement and postemployment benefit costs 19.3 22.6 Deferred environmental costs 10.0 14.9 Workforce reduction costs 4.9 7.3 Other (net)

(8.0)

(2.5)

Total regulatory assets (net) 451.5 154.3 Less: Current portion of regulatory assets (net) 62.5 Long-term portion of regulatory assets (net)

$ 389.0

$ 154.3 Deferred Fuel Costs Rate Stabilization Deferral In June 2006, Senate Bill 1 was enacted in Maryland, which imposes a rate stabilization measure that caps rate increases by BGE for residential electric customers at 15% from July 1, 2006 to May 31, 2007. As a result, BGE is recording a regulatory asset on its Consolidated Balance Sheets equal to the difference between the costs to purchase power and the revenues collected from customers, as well as related carrying charges based on short-term interest rates from July 1, 2006 to May 31, 2007.

During 2006, BGE deferred $326.9 million of electricity purchased for resale expenses and carrying charges as a regulatory asset related to the rate stabilization plan. BGE will amortize the regulatory asset to earnings over a period not to exceed ten years once collection from customers begins.

Other As described in Note 1, deferred fuel costs are the difference between our actual costs of purchased energy and our fuel rate revenues collected from customers. We reduce deferred fuel costs as we collect them from or refund them to our customers.

We exclude deferred fuel costs from rate base because their existence is relatively short-lived. These costs are recovered in the following year through our fuel rates.

Electric Generation-Related Regulatory Asset As a result of the deregulation of electric generation, BGE ceased to meet the requirements for the application of SFAS No. 71 for the previous electric generation portion of its business. In accordance with SFAS No. 101, Regulated Enterprises-Accounting for the Discontinuation ofApplication of FASB Statement No. 71, and EITF 97-4, Deregulation of the Pricing of Electricity-Issues Related to the Application ofFASB Statements No. 71 and 101. BGE wrote-off all of its individual, generation-related regulatory assets and liabilities. BGE established a single, generation-related regulatory asset to be collected through its regulated transmission and distribution business, which is being amortized on a basis that approximates the pre-existing individual regulatory asset amortization schedules.

A portion of this regulatory asset represents income taxes recoverable through future rates that do not earn a regulated rate of return. These amounts were $89.4 million as of December 31, 2006 and $97.9 million as of December 31, 2005. We will continue to amortize this amount through 2017.

Another portion of this regulatory asset represents the decommissioning and decontamination fund payment for federal uranium enrichment facilities that do not earn a regulated rate of return on the rate base investment. These amounts were $5.5 million at December 31, 2006 and $8.6 million at December 31, 2005. Prior to the deregulation of electric generation, these costs were recovered through the electric fuel rate mechanism, and were excluded from rate base. We will continue to amortize this amount through 2008.

Net Cost of Removal As discussed in Note 1, we use the group depreciation method for the regulated business. This method is currently an acceptable method of accounting under accounting principles generally accepted in the United States of America and is widely used in the energy, transportation, and telecommunication industries.

Historically, under the group depreciation method, the anticipated costs of removing assets upon retirement were provided for over the life of those assets as a component of depreciation expense. However, effective January 1, 2003, we adopted SFAS No. 143, Accountingfor Asset Retirement Obligations. In addition to providing the accounting requirements for recognizing an estimated liability for legal obligations associated with the retirement of tangible long-lived assets, SFAS No. 143 precludes the recognition of expected net future costs of removal as a component of depreciation expense or accumulated depreciation.

BGE is required by the Maryland PSC to use the group depreciation method, including cost of removal, under regulatory accounting. For ratemaking purposes, net cost of removal is a component of accumulated depreciation and is included as a net reduction to BGE's rate base investment. In accordance with SFAS No. 71, BGE continues to accrue for the future cost of removal for its regulated gas and electric assets by increasing its regulatory liability. This liability is relieved when actual removal costs are incurred.

98

Income Taxes Recoverable Through Future Rates (net)

As described in Note 1, income taxes recoverable through future rates are the portion of our net deferred income tax liability that is applicable to our regulated business, but has not been reflected in the rates we charge our customers. These income taxes represent the tax effect of temporary differences in depreciation and the allowance for equity funds used during construction, offset by differences in deferred tax rates and deferred taxes on deferred investment tax credits. We amortize these amounts as the temporary differences reverse.

Deferred Postretirement and Postemployment Benefit Costs Deferred postretirement and postemployment benefit costs are the costs we recorded under SFAS No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions, and SFAS No. 112, Employers'Accounting for Postemployment Benefits, in excess of the costs we included in the rates we charge our customers. We began amortizing these costs over a 15-year period in 1998.

Deferred Environmental Costs Deferred environmental costs are the estimated costs of investigating and cleaning up contaminated sites we own. We discuss this further in Note 12. We amortized $21.6 million of these costs (the amount we had incurred through October 1995) and are amortizing $6.4 million of these costs (the amount we incurred from November 1995 through June 2000) over 10-year periods in accordance with the Maryland PSC's orders. We applied for and received rate relief for an additional $5.4 million of clean-up costs incurred during the period from July 2000 through November 2005. These costs are being amortized over a 10-year period that began in January 2006.

Workforce Reduction Costs The portions of the costs associated with our Voluntary Special Early Retirement Program and workforce reduction programs that relate to BGE's gas business are deferred as regulatory assets in accordance with the Maryland PSC's orders in prior rate cases.

As a result of a 2005 gas base rate case, the remaining regulatory assets associated with workforce reductions totaling $7.3 million as of December 31, 2005 are being amortized over a 3-year period that began in January 2006. These remaining regulatory assets were previously amortized over 5-year periods beginning in January and February 2002.

Other (Net)

Other regulatory assets are comprised of a variety of current assets and liabilities that do not earn a regulatory rate of return due to their short-term nature.

7Pension, Postretirement, Other Postemployment, and Employee Savings Plan Benefits We offer pension, postretirement, other postemployment, and employee savings plan benefits. BGE employees participate in the benefit plans that we offer. We describe each of our plans separately below. Nine Mile Point offers its own pension, postretirement, other postemployment, and employee savings plan benefits to its employees. The benefits for Nine Mile Point are included in the tables beginning below.

We use a December 31 measurement date for our pension, postretirement, other postemployment, and employee savings plans. In 2006, the FASB issued SFAS No. 158, which was adopted on December 31, 2006. We discuss SFAS No. 158 in more detail in Note 1. The following table summarizes our defined benefit liabilities and their classification in our Consolidated Balance Sheets:

At December31, 2006 2005 (in millions)

Pension benefits

$468.6

$401.4 Postretirement benefits 441.5 327.9 Postemployment benefits 57.0 54.7 Total defined benefit obligations 967.1 784.0 Less: Amount recorded in accrued expenses and other*

38.8 Total noncurrent defined benefit obligations

$928.3

$784.0

• Amount recorded as current portion of defined benefit liability in 2006is based on the expected cash payments associated with unfunded plans during the next 12 months. Constellation Energy did not record the current portion of its defined benefit obligation prior to the December 2006 implementation of SFAS No. 158.

Pension Benefits We sponsor several defined benefit pension plans for our employees. These include basic qualified plans that most employees participate in and several nonqualified plans that are available only to certain employees. A defined benefit plan specifies the amount of benefits a plan participant is to receive using information about the participant. Employees do not contribute to these plans. Generally, we calculate the benefits under these plans based on age, years of service, and pay.

Sometimes we amend the plans retroactively. These retroactive plan amendments require us to recalculate benefits related to participants' past service. We amortize the change in the benefit costs from these plan amendments on a straight-line basis over the average remaining service period of active employees.

We fund the qualified plans by contributing at least the minimum amount required under IRS regulations. We calculate the amount of funding using an actuarial method called the projected unit credit cost method. The assets in all of the plans at December 31, 2006 and 2005 were mostly marketable equity and fixed income securities.

Postretirement Benefits We sponsor defined benefit postretirement health care and life insurance plans that cover the majority of our employees.

Generally, we calculate the benefits under these plans based on age, years of service, and pension benefit levels or final base pay.

We do not fund these plans. For nearly all of the health care plans, retirees make contributions to cover a portion of the plan 99

costs. For the life insurance plan, retirees do not make contributions to cover a portion of the plan costs.

Effective in 2002, we amended our postretirement medical plans for all subsidiaries other than Nine Mile Point. Our contributions for retiree medical coverage for future retirees who were under the age of 55 on January 1, 2002 are capped at the 2002 level. We also amended our plans to increase the Medicare eligible retirees' share of medical costs.

In 2003, the President signed into law the Medicare Prescription Drug Improvement and Modernization Act of 2003 (the Act). This legislation provides a prescription drug benefit for Medicare beneficiaries, a benefit that we provide to our Medicare eligible retirees. Our actuaries concluded that prescription drug benefits available under our postretirement medical plan are "actuarially equivalent" to Medicare Part D and thus qualify for the subsidy under the Act. In 2005, the Center for Medicare and Medicaid Services accepted our application to receive a tax reimbursement for eligible prescription drug costs, and we began to receive the subsidy in 2006. The actual subsidy offsets a portion of our share of the cost of the underlying postretirement prescription drug coverage. This legislation reduced our Accumulated Postretirement Benefit Obligation by

$42.6 million at January 1, 2005 and our annual postretirement benefit expense in 2005 by $5.4 million. This subsidy reduced our 2006 cash medical costs by $1.8 million, or by 7%.

Pension Liability Adjustments Our pension accumulated benefit obligation has exceeded the fair value of our plan assets since 2001. At December 31, 2006 and 2005, our pension obligations were greater than the fair value of our plan assets for our qualified and our nonqualified pension plans as follows:

Qualified Plans Non-Qualified At December 31, 2006 Nine Mile Other Plans Total (In millions)

Accumulated benefit obligation

$107.5

$1,306.0

$63.8

$1,477.3 Fair value of assets 54.6 1,106.6 1,161.2 Unfunded obligation

$ 52.9

$ 199.4

$63.8

$ 316.1 Qualified Plans Non-Qualified At December 31, 2005 Nine Mile Other Plans Total (In millions)

Accumulated benefit obligation

$127.1

$1,325.1

$56.3

$1,508.5 Fair value of assets 84.9 1,022.2 1,107.1 Unfunded obligation

$ 42.2

$ 302.9

$56.3

$ 401.4 We were required to remeasure the additional minimum pension liability prior to calculating the impact of adopting SFAS No. 158 on December 31, 2006. We recorded the additional minimum pension liability adjustments as follows:

Increase (Decrease)

Pension Accumulated Other Liability Intangible Comprehensive Loss Adjustment Asset

• Pre-tax After-tax (In millions)

Cumulative through 2004

$ 359.6

$40.6

$(319.0)

$(192.8) 2005 121.4 (6.1)

(127.5)

(77.1) 2006 (131.1)

(5.9) 125.2 75.6 Total

$ 349.9

$28.6

$(321.3)

$(194.3)

Included in "Other assets" in our Consolidated Balance Sheets.

Upon adoption of SFAS No. 158, we reversed the intangible asset associated with the minimum pension liability adjustment, increased our pension and postretirement liabilities, and reduced equity. The following table summarizes the impact of the adoption of SFAS No. 158 at December 31, 2006:

Increase (Decrease)

Postrefirement Accumulated Other Pension Benefit Intangible Comprehensive Loss Liability Liability Asset Pre-tax After-tax (In millions)

December 31, 2006

$152.5

$99.7

$(28.6)

$(280.8)

$(169.5)

SFAS No. 158 reduced our deferred income tax liabiliy by $111.3 million.

Obligations and Assets As a result of workforce reduction initiatives in the generation business, pension and postretirement special termination benefits were recorded in 2006 and 2005. We discuss the workforce reduction initiatives further in Note 2.

We show the change in the benefit obligations and plan assets of the pension and postretirement benefit plans in the following tables. Postretirement benefit plan amounts are presented net of expected reimbursements under Medicare Part D.

Pension Postretirement Benefits Benefits 2006 2005 2006 2005 (In millions)

Change in benefit obligation (1)

Benefit obligation at January 1 $1,678.6

$1,513.2

$460.4

$423.2 Service cost 49.0 44.8 7.7 7.6 Interest cost 89.3 83.9 23.7 23.8 Plan participants' contributions 8.3 7.4 Actuarial (gain) loss (49.1) 143.6 (27.1) 35.6 Special termination benefits 4.2 (0.4) 3.5 Benefits paid (2)

(142.2)

(106.5)

(35.0)

(37.2)

Benefit obligation at December 31

$1,629.8

$1,678.6

$441.5

$460.4 (1)

Amounts reflect projected benefit obligation forpension benefits and accumulated postretirement benefit obligation for postretirement benefits.

(2)

Benefits paid include annuity payments, lump-sum distributions, and transfers to nonqualified deferred compensation plans.

100

Change in plan assets Fair value of plan assets at January 1 Actual return on plan assets Employer contribution(1)

Plan participants' contributions Benefits paid(2)

Fair value of plan assets at December 31 Pension Postretirement Benefits Benefits 2006 2005 2006 2005 (In millions)

$1,107.1

$1,084.4 141.1 76.2 55.2 53.0 26.7 29.8 8.3 7.4 (142.2)

(106.5)

(35.0)

(37.2)

As a result of adopting SFAS No. 158, at December 31, 2006 the following is a summary of amounts we have recorded in "Accumulated other comprehensive income" and of expected amortization of those amounts over the next twelve months:

Estimated Amortization Next 12 Pension Postretirement

$1,161.2

$ 1,107.1 (1)

Includes benefit payments for unfunded plans.

(2)

Benefits paid include annuity payments, lump-sum distributions, and transfers to nonqualified deferred compensation plans.

Net Periodic Benefit Cost and Amounts Recognized in Other Comprehensive Income We show the components of net periodic pension benefit cost in the following table:

Year Ended December 31, 2006 2005 2004 (In millions)

Components of net periodic pension benefit cost Service cost

$ 49.0 $ 44.8

$ 40.1 Interest cost 89.3 83.9 82.3 Expected return on plan assets (96.6)

(100.2)

(97.9)

Amortization of unrecognized prior service cost 5.7 5.7 5.8 Recognized net actuarial loss 37.3 25.1 14.3 Amount capitalized as construction cost (13.4)

(7.4)

(4.5)

Net periodic pension benefit cost (1)

$ 71.3 $

51.9

$ 40.1 (1)

Net periodic pension benefit cost excludes SFAS No. 88 settlement charge of $12.7 million, and termination benefits of $4.2 million in 2006, SFAS No. 88 settlement charge of$4. 4 million in 2005, and SFAS No. 88 settlement charge of $2.8 million and termination benefits of$2.4 million in 2004. BGEs portion of our net periodic pension benefit costs, excluding amount capitalized, was $25.0 million in 2006, $15.0 million in 2005,and $8.6 million in 2004. The vast majority of our retirees are BGE employees.

We show the components of net periodic postretirement benefit cost in the following table:

Year Ended December 31, 2006 2005 2004 (In millions)

Components of net periodic postretirement benefit cost Service cost

$ 7.7 $ 7.6 $ 6.5 Interest cost 23.7 23.8 22.6 Amortization of transition obligation 2.1 2.1 2.1 Recognized net actuarial loss 6.6 6.4 3.1 Amortization of unrecognized prior service cost (3.5)

(3.5)

(3.5)

Amount capitalized as construction cost (8.2)

(7.7)

(7.0)

Net periodic postretirement benefit cost (1)

$28.4

$28.7

$23.8 (1)

Net periodic postretirement benefit cost excludes SFAS No. 106 termination benefits of $3.5 million in 2006and $1.2 million in 2004.

BGE'portion of our net periodic postretirement benefit cost, excluding amounts capitalized, was $166million in 2006, $17.4 million in 2005, and $15.1 million in 2004.

At December 31, 2006 Benefits Benefits Months (In millions)

Unrecognized net actuarial loss

$475.7

$116.6

$37.1 Unrecognized prior service cost 26.7 (29.7) 1.7 Unrecognized transition obligation 12.8 2.1 Total

$502.4

$ 99.7

$40.9 Expected Cash Benefit Payments The pension and postretirement benefits we expect to pay in each of the next five calendar years and in the aggregate for the subsequent five years are shown below. These estimated benefits are based on the same assumptions used to measure the benefit obligation at December 31, 2006, but include benefits attributable to estimated future employee service.

Postretirement Benefits Before After Pension Medicare Medicare Benefits*

Part D Subsidy Part D (In millions) 2007

$105.5

$ 30.8

$ 2.7

$ 28.1 2008 97.7 31.9 2.9 29.0 2009 100.3 33.0 3.1 29.9 2010 111.5 33.8 3.2 30.6 2011 108.4 34.6 3.4 31.2 2012-2016 688.5 182.7 18.9 163.8

• Excludes transfers to nonqualified deferred compensation plans Assumptions We made the assumptions below to calculate our pension and postretirement benefit obligations and periodic cost.

Pension Postretirement Assumption Benefits Benefits Impacts 2006 2005 2006 2005 Calculation of Benefit Obligation and Discount rate 6.00%

5.50%

6.00%

5.50%

Periodic Cost Expected return on plan assets 8.75 9.0 NIA N/A Periodic Cost Rate of Benefit compensation Obligation and increase 4.0 4.0 4.0 4.0 Periodic Cost Our discount rate is based on a bond portfolio analysis of high quality corporate bonds whose maturities match our expected benefit payments. Our 8.75% overall expected long-term rate of return on plan assets reflects our long-term investment strategy in terms of asset mix targets and expected returns for each asset class. Effective in 2006, we reduced our assumed expected return on pension plan assets from 9.0% to 101

8.75% based on a fundamental analysis utilizing expected long-term returns applied to our targeted asset allocation.

Annual health care inflation rate assumptions also impact the calculation of our postretirement benefit obligation and periodic cost. We assumed the following health care inflation rates to produce average claims by year as shown below:

At December31, 2006 2005 Next year 8.5%

9.0%

Following year 8.0%

8.0%

Ultimate trend rate 5.0%

5.0%

Year ultimate trend rate reached 2014 2010 A one-percent increase in the health care inflation rate from the assumed rates would increase the accumulated postretirement benefit obligation by approximately $32.1 million as of December 31, 2006 and would increase the combined service and interest costs of the postretirement benefit cost by approximately $2.2 million annually.

A one-percent decrease in the health care inflation rate from the assumed rates would decrease the accumulated postretirement benefit obligation by approximately $26.8 million as of December 31, 2006 and would decrease the combined service and interest costs of the postretirement benefit cost by approximately $1.8 million annually.

Qualified Pension Plan Assets The asset allocations for our qualified pension plans were as follows:

At December31, 2006 2005 Equity securities 64%

59%

Debt securities 28 32 Other 8

9 Total 100%

100%

The category "Other" primarily represents investments in financial limited partnerships. Our long-term pension plan investment strategy is to seek an asset mix of 58% equity, 30%

fixed income, and 12% other investments. We rebalance our portfolio periodically when the sum of equity and other investments differs from 70% by three percentage points or more, we change an outside investment advisor, or we make contributions to the trust.

We determine expected return on plan assets using a market-related value of plan assets that recognizes asset gains and losses ratably over a five-year period.

Contributions and Benefit Payments We contributed an additional $52 million to our qualified pension plans in March 2006, even though there was no IRS required minimum contribution in 2006. We expect to contribute $125 million to our pension plans in 2007. Our non-qualified pension plans and our postretirement benefit programs are not funded. We estimate that we will incur approximately

$3.8 million in pension benefits for our non-qualified pension plans and approximately $28 million for retiree health and life insurance costs net of Medicare Part D during 2007.

Other Postemployment Benefits We provide the following postemployment benefits:

• health and life insurance benefits to eligible employees determined to be disabled under our Disability Insurance Plan,

• income replacement payments for Nine Mile Point union-represented employees determined to be disabled, and

• income replacement payments for other employees determined to be disabled before November 1995 (payments for employees determined to be disabled after that date are paid by an insurance company, and the cost is paid by employees).

We recognized expense associated with our other postemployment benefits of $9.6 million in 2006, $9.2 million in 2005, and $10.8 million in 2004. BGE's portion of expense associated with other postemployment benefits was $5.6 million in 2006, $5.4 million in 2005, and $8.2 million in 2004.

We assumed the discount rate for other postemployment benefits to be 5.50% in 2006 and 5.25% in 2005. This assumption impacts the calculation of our other postemployment benefit obligation and periodic cost.

Employee Savings Plan Benefits We sponsor defined contribution savings plans that are offered to all eligible employees. The savings plans are qualified 401(k) plans under the Internal Revenue Code. In a defined contribution plan, the benefits a participant is to receive result from regular contributions to a participant account. Matching contributions to participant accounts are made under these plans. Matching contributions to these plans were:

• $20.0 million, of which BGE contributed $5.4 million, in 2006,

• $18.6 million, of which BGE contributed $5.1 million, in 2005, and

• $16.7 million, of which BGE contributed $4.7 million, in 2004.

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8 Credit Facilities and Short-Term Borrowings Our short-term borrowings may include bank loans, commercial paper, and bank lines of credit. Short-term borrowings mature within one year from the date of issuance.

We pay commitment fees to banks for providing us lines of credit. When we borrow under the lines of credit, we pay market interest rates.

Constellation Energy Constellation Energy had committed bank lines of credit under credit facilities of $4,550 million at December 31, 2006 for short-term financial needs as follows:

• $1.0 billion 364-day credit facility expiring in October 2007,

• $200 million 364-day credit facility expiring in December 2007,

• $1.5 billion five-year revolving credit facility expiring in March 2010,

• $1.1 billion five-year revolving credit facility expiring in November 2010, and

• $750.0 million five-year revolving credit facility expiring in November 2010.

We enter into these facilities to ensure adequate liquidity to support our operations. Currently, we use the facilities to issue letters of credit primarily for our merchant energy business. Additionally, we can borrow directly from the banks or use the facilities to allow the issuance of commercial paper with the exception of the $1.0 billion 364-day facility, which only supports $500.0 million of letters of credit and the $200 million 364-day facility, which only supports letters of credit.

These facilities can issue letters of credit up to approximately $4,050 million. Letters of credit issued under all of our facilities totaled $1,648 million at December 31, 2006 and $2,486 million at December 31, 2005. The decrease in letters of credit issued is primarily due to changes in collateral requirements with counterparties as a result of commodity price changes.

In 2005, our merchant energy business executed several short-term repurchase agreements that resulted in $0.7 million of net short-term borrowings which matured in January 2006.

BiE BGE had no commercial paper outstanding at December 31, 2006 or 2005.

BGE has a $400.0 million five-year revolving credit facility expiring in 2011. BGE can borrow directly from the banks or use the agreements to allow the issuance of commercial paper.

9Long-Term Debt and Preference Stock Long-term Debt Long-term debt matures in one year or more from the date of issuance. We detail our long-term debt in our Consolidated Statements of Capitalization. As you read this section, it may be helpful to refer to those statements.

Constellation Energy On October 31, 2006, CEP entered into a $200.0 million secured revolving credit facility. The credit facility will mature on October 31, 2010. The amount available for borrowing at any one time is limited to the borrowing base, which is initially set at

$75.0 million. At December 31, 2006, CEP had $22.0 million of borrowings outstanding under this,facility. As discussed in Note 13, in 2006, CEP executed floating-to-fixed interest rate swaps related to $16.5 million of its outstanding debt.

In May 2006, we issued $122.0 million of tax-exempt variable rate notes to refinance tax-exempt pollution control loans. We used $75.0 million of the net proceeds to refinance a 6.00% pollution control revenue refunding loan in June 2006 and in July 2006 we used the remaining $47.0 million of proceeds to refinance a 5.55% pollution control revenue refunding loan.

BGE BGE's First Refunding MorZaae Bonds BGE's first refunding mortgage bonds are secured by a mortgage lien on all of its assets. The generating assets BGE transferred to subsidiaries of Constellation Energy also remain subject to the lien of BGE's mortgage, along with the stock of Safe Harbor Water Power Corporation and Constellation Enterprises, Inc.

BGE is required to make an annual sinking fund payment each August 1 to the mortgage trustee. The amount of the payment is equal to 1% of the highest principal amount of bonds outstanding during the preceding 12 months. The trustee uses these funds to retire bonds from any series through repurchases or calls for early redemption. However, the trustee cannot call the two remaining outstanding bonds for early redemption:

+ 7V2% Series, due 2007

+ 65/8% Series, due 2008 BGE's Other Long-Term Debt In October 2006, BGE issued $300.0 million of 5.90% Notes, due October 1, 2016 and $400.0 million of 6.35% Notes, due October 1, 2036. We used the proceeds from these issuances for general corporate purposes, including refinancing the following long-term debt of BGE:

+ $300.0 million of 5.25% Notes, due December 15,

2006,

• $121.4 million of 7.5% First Refunding Mortgage Bonds, due January 15, 2007, and

• $10.0 million of 6.70% Medium-term Notes, Series D, due December 1, 2006.

On July 1, 2000, BGE transferred $278.0 million of tax-exempt debt to our merchant energy business related to the transferred generating assets. At December 31, 2006, BGE remains contingently liable for the $147.8 million outstanding balance of this debt.

103

We show the weighted-average interest rates and maturity dates for BGE's fixed-rate medium-term notes outstanding at December 31, 2006 in the following table.

Series E

G Weighted-Average Interest Rate 6.66%

6.08%

Maturity Dates 2007-2012 2008 Some of the medium-term notes include a "put option."

These put options allow the holders to sell their notes back to BGE on the put option dates at a price equal to 100% of the principal amount. The following is a summary of medium-term notes with put options.

Series E Notes 6.75%, due 2012 6.75%, due 2012 6.73%, due 2012 Principal (In millions)

$59.5 25.0 25.0 Put Option Dates June 2007 June 2007 June 2007 BGE Deferrable Interest Subordinated Debentures On November 21, 2003, BGE Capital Trust II (BGE Trust II),

a Delaware statutory trust established by BGE, issued 10,000,000 Trust Preferred Securities for $250 million ($25 liquidation amount per preferred security) with a distribution rate of 6.20%.

BGE Trust II used the net proceeds from the issuance of common securities to BGE and the Trust Preferred Securities to purchase a series of 6.20% Deferrable Interest Subordinated Debentures due October 15, 2043 (6.20% debentures) from BGE in the aggregate principal amount of $257.7 million with the same terms as the Trust Preferred Securities. BGE Trust II must redeem the Trust Preferred Securities at $25 per preferred security plus accrued but unpaid distributions when the 6.20%

debentures are paid at maturity or upon any earlier redemption.

BGE has the option to redeem the 6.20% debentures at any time on or after November 21, 2008 or at any time when certain tax or other events occur.

BGE Trust II will use the interest paid on the 6.20%

debentures to make distributions on the Trust Preferred Securities. The 6.20% debentures are the only assets of BGE Trust II.

BGE fully and unconditionally guarantees the Trust Preferred Securities based on its various obligations relating to the trust agreement, indentures, 6.20% debentures, and the preferred security guarantee agreement.

For the payment of dividends and in the event of liquidation of BGE, the 6.20% debentures are ranked prior to preference stock and common stock.

Revolving Credit Agreement On December 18, 2001, BGE's subsidiary, District Chilled Water Partnership (ComfortLink) entered into a $25.0 million loan agreement with the Maryland Energy Financing Administration (MEFA). The terms of the loan exactly match the terms of variable rate, tax exempt bonds due December 1, 2031 issued by MEFA for ComfortLink to finance the cost of building a chilled water distribution system. The interest rate on this debt resets weekly. These bonds, and the corresponding loan, can be redeemed at any time at par plus accrued interest while under variable rates. The bonds can also be converted to a fixed rate at ComfortLink's option.

Debt Compliance and Covenants The credit facilities of Constellation Energy and BGE discussed in Note 8 have limited material adverse change clauses that only consider a material change in financial condition and are not directly affected by decreases in credit ratings. If these clauses are invoked, the lending institutions can decline to make new advances or issue new letters of credit, but cannot accelerate existing amounts outstanding. The long-term debt indentures of Constellation Energy and BGE do not contain material adverse change clauses or financial covenants.

Certain credit facilities of Constellation Energy contain a provision requiring Constellation Energy to maintain a ratio of debt to capitalization equal to or less than 65%. At December 31, 2006, the debt to capitalization ratio as defined in the credit agreements was 48%.

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, 2006, the debt to capitalization ratio for BGE as defined in this credit agreement was 49%. At December 31, 2006, no amounts were outstanding under these agreements.

Failure by Constellation Energy, or BGE, to comply with these covenants could result in the acceleration of the maturity of the debt outstanding under these facilities. The credit facilities of Constellation Energy contain usual and customary cross-default provisions that apply to defaults on debt by Constellation Energy and certain subsidiaries over a specified threshold. The BGE credit facility also contains usual and customary cross-default provisions that apply to defaults on debt by BGE over a specified threshold. The indenture pursuant to which BGE has issued and outstanding mortgage bonds provides that a default under any debt instrument issued under the indenture may cause a default of all debt outstanding under such indenture.

Constellation Energy also provides credit support to Calvert Cliffs, Ginna, and Nine Mile Point to ensure these plants have funds to meet expenses and obligations to safely operate and maintain the plants.

Maturities of Long-Term Debt Our long-term borrowings mature on the following schedule:

Constellation Nonregulated Year Energy Businesses BGE (In millions) 2007

$ 600.0

$ 20.5 121.4 2008 6.5 294.6 2009 500.0 1.2 11.5 2010 22.3 2011 36.5 22.0 Thereafter 1,942.9 260.4 1,267.2 Total long-term debt at December 31, 2006

$3,042.9

$347.4

$1,716.7 At December 31, 2006, we had long-term loans totaling

$384.3 million that mature after 2006, which contain certain put options under which lenders could potentially require us to repay the debt prior to maturity, or which are periodically remarketed 104

and could require repayment following any unsuccessful remarketing. As a result of these provisions, at December 31, 2006, $136.9 million is classified as current portion of long-term debt at BGE.

Weighted-Average Interest Rates for Variable Rate Debt Our weighted-average interest rates for variable rate debt were:

At December31, Nonregulated Businesses (including Constellation Energy)

Loans under credit agreements Tax-exempt debt Fixed-rate debt converted to floating*

BGE 2006 2005 Preference Stock Each series of BGE preference stock has no voting power, except for the following:

+ the preference stock has one vote per share on any charter amendment which would create or authorize any shares of stock ranking prior to or on a parity with the preference stock as to either dividends or distribution of assets, or which would substantially adversely affect the contract rights, as expressly set forth in BGE's charter, of the preference stock, each of which requires the affirmative vote of two-thirds of all the shares of preference stock outstanding; and

+ whenever BGE fails to pay full dividends on the preference stock and such failure continues for one year, the preference stock shall have one vote per share on all matters, until and unless such dividends shall have been paid in full. Upon liquidation, the holders of the preference stock of each series outstanding are entitled to receive the par amount of their shares and an amount equal to the unpaid accrued dividends.

3.69% 4.71%

3.63% 2.77%

6.26% 4.72%

Remarketed floating rate series mortgage bonds 3.14%

• As discussed in Note 13, we have entered into interest rate swaps relating to $450.0 million of our fixed-rate debt.

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10 Taxes The components of income tax expense are as follows:

Year Ended December 31, 2006 2005 2004 (Dollar amounts in millions)

Income Taxes Current Federal

$246.3

$ 14.3

$ (4.5)

State 37.2 32.7 20.5 Current taxes charged to expense 283.5 47.0 16.0 Deferred Federal 50.7 107.9 85.4 State 23.7 16.1 24.2 Deferred taxes charged to expense 74.4 124.0 109.6 Investment tax credit adjustments (6.9)

(7.1)

(7.2)

Income taxes per Consolidated Statements of Income

$351.0

$163.9

$118.4 Certain prior year amounts have been reclassified to conform to the current year presentation ofdiscontinued operations.

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 BGE preference stock dividends)

$1,112.8

$ 713.0

$ 630.0 Statutory federal income tax rate 35%

35%

35%

Income taxes computed at statutory federal rate 389.5 249.5 220.5 Increases (decreases) in.income taxes due to Depreciation differences not normalized on regulated activities 3.6 3.8 4.0 Amortization of deferred investment tax credits (6.9)

(7.1)

(7.2)

Synthetic fuel tax credits flowed through to income*

(120.2)

(114.9)

(123.2)

Estimated synthetic fuel tax credit phase-out 44.3 State income taxes, net of federal income tax benefit 42.6 31.5 28.2 Merger-related transaction costs (5.3) 5.3 Other 3.4 (4.2)

(3.9)

Total income taxes 351.0

$ 163.9

$ 118.4 Effective income tax rate 31.5%

23.0%

18.8%

Certain prior year amounts have been reclassified to conform to the current year's presentation ofdiscontinued operations.

• 2004 includes credits associated with 2003 production at our South Carolinafacility that were recognized in the second quarter of 2004 upon receipt ofa favorable Private Letter Ruling from the IRS.

BGE's effective tax rate was 37.5% in 2006, 38.8% in 2005, and 38.1% in 2004. The difference between BGE's effective tax rate and the 35% statutory federal income tax rate is primarily related to Maryland corporate income taxes at an effective rate of 4.6%, which is net of the related federal income tax benefit. In 2006, this is partially offset by deducting merger-related costs incurred in 2005 as a result of the termination of the merger with FPL Group (0.5%) and the taking of an employee savings plan dividend deduction (0.5%).

106

The major components of our net deferred income tax liability are as follows:

Constellation Energy BGE At December31, 2006 2005 2006 2005 (In millions)

Deferred Income Taxes Deferred tax liabilities Net property, plant and equipment

$1,539.1

$1,539.3

$524.2

$526.7 Qualified nuclear decommissioning trust funds 339.5 332.8 Regulatory assets, net 203.3 85.5 203.3 85.5 Mark-to-market energy assets and liabilities, net 154.7 141.2 Other 145.6 112.7 72.7 61.3 Total deferred tax liabilities 2,382.2 2,211.5 800.2 673.5 Deferred tax assets Asset retirement obligation 384.6 353.6 Defined benefit obligations 351.1 243.8 39.8 41.4 Financial investments and hedging instruments 757.2 144.7 Deferred investment tax credits 22.1 24.2 4.7 5.3 Reduction of.investments 7.3 7.4 Other 98.4 105.6 10.6 8.3 Total deferred tax assets 1,620.7 879.3 55.1 55.0 Total deferred tax liability, net 761.5 1,332.2 745.1 618.5 Less: Current portion of deferred tax (asset)/liability (674.3) 151.4 47.4 9.6 Long-term portion of deferred tax liability, net

$1,435.8

$1,180.8

$697.7

$608.9 Certain prior year amounts have been reclassified to conform to the current year's presentation.

Synthetic Fuel Tax Credits Our merchant energy business has investments in facilities that manufacture solid synthetic fuel produced from coal as defined under the Internal Revenue Code (IRC) for which we can claim tax credits on our Federal income tax return through 2007. We recognize the tax benefit of these credits in our Consolidated Statements of Income when we believe it is highly probable that the credits will be sustained. The synthetic fuel process involves combining coal material with a chemical reagent to create a significant chemical change. A taxpayer may request a private letter ruling from the IRS to support its position that the synthetic fuel produced undergoes a significant chemical change and thus qualifies for synthetic fuel tax credits.

We own a minority ownership in four synthetic fuel facilities located in Virginia and West Virginia. These facilities have received private letter rulings from the IRS. In 2004, the IRS concluded its examination of the partnership that owns these facilities for the tax years 1998 through 2001 and the IRS did not disallow any of the previously recognized synthetic fuel credits.

In 2003, we purchased 99% ownership in a South Carolina facility that produces synthetic fuel. We did not recognize in our Consolidated Statements of Income the tax benefit of $35.9 million for credits claimed on our South Carolina facility in 2003 pending receipt of a favorable private letter ruling. In 2004, we received a favorable private letter ruling. We believe receipt of the private letter ruling provides reasonable assurance that it is highly probable that the credits will be sustained. Therefore, we recognized the tax benefit of

$35.9 million in our Consolidated Statements of Income during 2004. In 2006, the IRS concluded its examination of the partnership that owns the South Carolina facility for the 2003 and 2004 tax years and the IRS did not disallow any of the previously recognized synthetic fuel credits.

The IRC provides for a phase-out of synthetic fuel tax credits if average annual wellhead oil prices increase above certain levels. To determine the amount of the phase-out, we are required to compare average annual wellhead oil prices per barrel as published by the IRS (reference price) to a Gross National Product inflation adjusted oil price for the year, also published by the IRS. The reference price is determined based on wellhead prices for all domestic oil production as published by the Energy Information Administration (EIA). For 2006, we estimate the tax credit reduction would begin if the reference price exceeds approximately $55 per barrel and would be fully phased out if the reference price exceeds approximately

$68 per barrel.

Based on monthly EIA published wellhead oil prices for the ten months ended October 31, 2006 and November and December NYMEX prices for light, sweet, crude oil (adjusted for the 2006 difference between EIA and NYMEX prices), we estimate a 38% tax credit phase-out in 2006. We recorded the effect of this phase-out estimate as a reduction in tax credits of

$44.3 million during 2006.

Based on forward market prices and volatilities as of February 22, 2007, we estimate a 21% tax credit phase-out for the year 2007. The expected amount of synthetic fuel tax credits phased-out may change materially from period to period as a result of continued changes in oil prices.

While we believe the production and sale of synthetic fuel from all of our synthetic fuel facilities meet the conditions to qualify for tax credits under the IRC, we cannot predict the timing or outcome of any future challenge by the IRS, legislative or regulatory action, or the ultimate impact of such events on the synthetic fuel tax credits that we have claimed to date, but the impact could be material to our financial results.

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Income Tax Audits Our consolidated federal income tax returns for the for the tax years 2002 through 2004 are currently under examination by the IRS. Our consolidated federal income tax returns for the 2001 and prior tax years are closed under the statute of limitations. Income tax returns filed in other jurisdictions are also subject to audit for additional tax periods. Although the final outcome of current and future tax audits is uncertain, we believe that adequate provisions for income taxes have been made for potential liabilities resulting from such matters.

11I Leases There are two types of leases--operating and capital. Capital leases qualifyi as sales or purchases of property and are reported in our Consolidated Balance Sheets. Our capital leases are not material in amount. All other leases are operating leases and are reported in our Consolidated Statements of Income. We expense all lease payments associated with our regulared business. Lease expense and future minimum payments for long-term, noncancelable, operating leases are not material to BGE's financial results. We present information about our operating leases below.

Outgoing Lease Payments We, as lessee, lease some facilities and equipment. The lease agreements expire on various dates and have various renewal options. We also enter into certain power purchase agreements which are accounted for as operating leases. Under these agreements, we are required to make fixed capacity payments, as well as variable payments based on actual output of the plants. We record these payments as "Fuel and purchased energy expenses" in our Consolidated Statements of Income.

We exclude from our future minimum lease payments table the variable payments related to the output of the plant due to the contingency associated with these payments.

We recognized expense related to our operating leases as follows:

Fuel and purchased energy Operating expenses expenses Total (In millions) 2006

$162.6

$24.7

$187.3 2005 103.2 24.8 128.0 2004 11.0 23.1 34.1 At December 31, 2006, we owed future minimum payments for long-term, noncancelable, operating leases as follows:

Power Purchase Yea r Agreements Other Total (In millions) 2007

$162.0

$ 24.0

$186.0 2008 121.5 19.6 141.1 2009 62.3 18.9 81.2 2010 59.4 17.8 77.2 2011 59.3 16.9 76.2 Thereafter 317.8 73.8 391.6 Total future minimum lease payments

$782.3

$171.0

$953.3 1 2Commitments, Guarantees, and Contingencies Commitments We have made substantial commitments in connection with our merchant energy, regulated electric and gas, and other nonregulated businesses. These commitments relate to:

• purchase of electric generating capacity and energy,

• procurement and delivery of fuels,

• the capacity and transmission and transportation rights for the physical delivery of energy to meet our obligations to our customers, and

• long-term service agreements, capital for construction programs, and other.

Our merchant energy business enters into various long-term contracts for the procurement and delivery of fuels to supply our generating plant requirements. In most cases, our contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. These contracts expire in various years between 2007 and 2020. In addition, our merchant energy business enters into long-term contracts for the capacity and transmission rights for the delivery of energy to meet our physical obligations to our customers. These contracts expire in various years between 2007 and 2019.

Our merchant energy business also has committed to long-term service agreements and other purchase commitments for our plants.

Our regulated electric business enters into various long-term contracts for the procurement of electricity. These contracts expire between 2007 and 2009. As discussed in Note 1, the cost of power under these contracts is fully recoverable, and therefore is excluded from the table on the next page.

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Our regulated gas business enters into various long-term contracts for the procurement, transportation, and storage of gas. Our regulated gas business has gas transportation and storage contracts that expire between 2007 and 2028. These contracts are recoverable under BGE's gas cost adjustment clause discussed in Note 1, and therefore are excluded from the table below.

Our other nonregulated businesses have committed to gas purchases and to contributions of additional capital for construction programs and joint ventures in which they have an interest.

We have also committed to long-term service agreements and other obligations related to our information technology systems.

At December 31, 2006, we estimate our future obligations to be as follows:

Payments 2008-2010-2007 2009 2011 Thereafter Total (In millions)

Merchant Energy:

Purchased capacity and energy

$ 367.1

$ 755.5 $271.8 526.0

$1,920.4 Fuel and transportation 2,866.5 1,867.3 475.9 894.4 6,104.1 Long-term service agreements, capital, and other 15.8 10.1 5.5 23.9 55.3 Total merchant energy 3,249.4 2,632.9 753.2 1,444.3 8,079.8 Corporate and Other:

Long-term service agreements, capital, and other 33.0 17.0 4.1 54.1 Regulated:

Purchase obligations and other 54.4 40.9 2.2 97.5 Total future obligations

$3,336.8

$2,690.8

$757.3

$1,446.5

$8,231.4 Termination ofMerger Agreement with FPL Group, Inc.

In connection with the termination of the merger agreement with FPL Group, there are certain contingencies relating to potential cash payments. We discuss these contingencies in Note 15.

Long-Term Power Sales Contracts We enter into long-term power sales contracts in connection with our load-serving activities. We also enter into long-term power sales contracts associated with certain of our power plants. Our load-serving power sales contracts extend for terms through 2019 and provide for the sale of energy to electricity distribution utilities and certain retail customers. Our power sales contracts associated with our power plants extend for terms into 2014 and provide for the sale of all or a portion of the actual output of certain of our power plants. All long-term contracts were executed at pricing that approximated market rates, including profit margin, at the time of execution.

Guarantees Our guarantees do not represent incremental Constellation Energy Group obligations; rather they primarily represent parental guarantees of subsidiary obligations. The following table summarizes the maximum exposure based on the stated limit of our outstanding guarantees at December 31, 2006:

At December 31, 2006 Stated Limit (In millions)

Competitive supply guarantees

$10,001.8 Nuclear guarantees 917.8 BGE guarantees 263.3 Other non-regulated guarantees 75.2 Power project guarantees 19.2 Total guarantees

$11,277.3 At December 31, 2006, Constellation Energy had a total of $11,277.3 million in guarantees in outstanding related to loans, credit facilities, and contractual performance of certain of its subsidiaries as described below.

• Constellation Energy guaranteed $10,001.8 million on behalf of our subsidiaries for competitive supply activities. These guarantees are put into place in order to allow our subsidiaries the flexibility needed to conduct business with counterparties without having to post other forms of collateral. While the face amount of these guarantees is $10,001.8 million, our calculated fair value of obligations for commercial transactions covered by these guarantees was $2,190.6 million at December 31, 2006. If the parent company was required to fund these subsidiary obligations, the total amount based on December 31, 2006 market prices would be $2,190.6 million. For those guarantees related to our mark-to-market energy or risk management liabilities, the fair value of the obligation is recorded in our Consolidated Balance Sheets.

• Constellation Energy guaranteed $917.8 million primarily on behalf of our nuclear generating facilities mostly due to nuclear insurance and for credit support to ensure these plants have funds to meet expenses and obligations to safely operate and maintain the plants.

• BGE guaranteed the Trust Preferred Securities of

$250.0 million of BGE Trust II, an unconsolidated investment, as discussed in Note 9.

+ BGE guaranteed two-thirds of certain debt of Safe Harbor Water Power Corporation, an unconsolidated investment. At December 31, 2006, Safe Harbor Water Power Corporation had outstanding debt of

$20.0 million. The maximum amount of BGE's guarantee is $13.3 million.

• Constellation Energy guaranteed $62.7 million on behalf of our other nonregulated businesses primarily for loans and performance bonds of which

$25.0 million was recorded in our Consolidated Balance Sheets at December 31, 2006.

• Our other nonregulated business guaranteed

$12.5 million primarily for performance bonds.

• Our merchant energy business guaranteed

$19.2 million for loans and other performance guarantees related to certain power projects in which we have an investment.

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We believe it is unlikely that we would be required to perform or incur any losses associated with guarantees of our subsidiaries' obligations.

Contingenies Revenue Sufficiency Guarantee Costs In April 2006, the FERC issued an order requiring the Midwest Independent System Operator (MISO) to retroactively re-allocate revenue sufficiency guarantee costs (RSGs) for the period April 2005 to present based on the FERC's finding that MISO violated its tariff and incorrectly allocated RSGs among market participants. The re-allocation of RSGs would result in some participants recognizing additional expense and others receiving refunds.

In May 2006, the MISO filed a motion with FERC seeking a stay of the FERC order. The motion was granted by FERC delaying the implementation of the original order until after the issuance of an order on rehearing. In May 2006, we and other market participants filed requests for rehearing with FERC.

In October 2006, FERC issued an order on rehearing that reversed the original retroactive re-allocation of RSGs. Based on this order we estimate the impact of the RSG re-allocation, if any, to be immaterial to our financial results. However, further requests for rehearing and appeals have been submitted and we cannot predict the ultimate timing or outcome of any such action.

Environmental Matters Solid and Hazardous Waste The Environmental Protection Agency (EPA) and several state agencies have notified us that we are considered a potentially responsible party with respect to the clean-up of certain environmentally contaminated sites. We cannot estimate the final clean-up costs for all of these sites, but the current estimated costs for, and current status of, each site is described in more detail below.

68th Street Dum=

In 1999, the EPA proposed to add the 68th Street Dump in Baltimore, Maryland to the Superfund National Priorities List, which is its list of sites targeted for clean-up and enforcement, and sent a general notice letter to BGE and 19 other parties identifying them as potentially liable parties at the site. In March 2004, we and other potentially responsible parties formed the 68th Street Coalition and entered into consent order negotiations with the EPA to investigate clean-up options for the site under the Superfund Alternative Sites Program. In May 2006, a settlement among the EPA and 19 of the potentially responsible parties, including BGE, with respect to investigation of the site became effective. The settlement requires the potentially responsible parties, over the course of several years, to identify contamination at the site and recommend clean-up options. BGE is fully indemnified by a wholly-owned affiliate of Constellation Energy for costs related to this settlement, as well as any clean-up costs. The clean-up costs will not be known until the investigation is closer to completion. However, those costs could have a material effect on our financial results.

Kane and Lombard The EPA issued its record of decision for the Kane and Lombard Drum site located in Baltimore, Maryland on September 30, 2003, which specified the clean-up plan for the site, consisting of enhanced reductive dechlorination, a soil management plan, and institutional controls. An EPA order requiring cleanup of the site by 18 parties, including Constellation Energy, became effective in November 2006.

The EPA estimates that total clean-up costs will be approximately $7 million. Our share of site-related costs will be 11.1% of the total. We recorded a liability in our Consolidated Balance Sheets for our share of the clean-up costs that we believe is probable.

Spring Gardens In December 1996, BGE signed a consent order with the Maryland Department of the Environment that requires it to implement remedial action plans for contamination at and around the Spring Gardens site, located in Baltimore, Maryland. The Spring Gardens site was once used to manufacture gas from coal and oil. Based on remedial action plans and cost modeling performed in late 2006, BGE estimates its probable clean-up costs will total $43 million.

BGE has recorded these costs as a liability in its Consolidated Balance Sheets and has deferred these costs, net of accumulated amortization and amounts it recovered from insurance companies, as a regulatory asset. Based on the results of studies at this site, it is reasonably possible that additional costs could exceed the amount BGE has recognized by approximately

$3 million. Through December 31, 2006, BGE has spent approximately $40 million for remediation at this site.

BGE also has investigated other small sites where gas was manufactured in the past. We do not expect the clean-up costs of the remaining smaller sites to have a material effect on our financial results.

Air Quality In late July 2005, we received two Notices of Violation (NOVs) from the Placer County Air Pollution Control District, Placer County California (District) alleging that the Rio Bravo Rocklin facility located in Lincoln, California had violated certain District air emission regulations. We have a combined 50% ownership interest in the partnership which owns the Rio Bravo Rocklin facility. The NOVs allege a total of 38 violations between January 2003 and March 2005 of either the facility's air permit or federal, state, and county air emission standards related to nitrogen oxide, carbon monoxide, and particulate emissions, as well as violations of certain monitoring and reporting requirements during that time period. The maximum civil penalties for the alleged violations range from $10,000 to $40,000 per violation. Management of the Rio Bravo Rocklin facility is currently discussing the allegations in the NOVs with District representatives. It is not possible to determine the actual liability, if any, of the partnership that owns the Rio Bravo Rocklin facility.

Litigation In the normal course of business, we are involved in various legal proceedings. We discuss the significant matters below.

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Western Power Markets City of Tacoma v. AEP, et al,-The City of Tacoma, on June 7, 2004, in the U.S. District Court, Western District of Washington, filed a complaint against over 60 companies, including Constellation Energy Commodities Group, Inc.

(CCG). The complaint alleges that the defendants engaged in manipulation of electricity markets resulting in prices for power in the western power markets that were substantially above what market prices would have been in the absence of the alleged unlawful contracts, combinations and conspiracy in violation of Section 1 of the Sherman Act. The complaint further alleges that the total amount of damages is unknown, but is estimated to exceed $175 million. On February 11, 2005, the Court granted the defendants' motion to dismiss the action based on the Court's lack of jurisdiction over the claims in question. The plaintiff has appealed the dismissal of the action to the Ninth Circuit Court of Appeals. We believe that we have meritorious defenses to this action and intend to defend against it vigorously. However, we cannot predict the timing, or outcome, of this case, or its possible effect on our financial results.

Mercury Since September 2002, BGE, Constellation Energy, and several other defendants have been involved in numerous actions filed in the Circuit Court for Baltimore City, Maryland alleging mercury poisoning from several sources, including coal plants formerly owned by BGE. The plants are now owned by a subsidiary of Constellation Energy. In addition to BGE and Constellation Energy, approximately 11 other defendants, consisting of pharmaceutical companies, manufacturers of vaccines, and manufacturers of Thimerosal have been sued.

Approximately 70 cases, involving claims related to approximately 132 children, have been filed to date, with each claimant seeking $20 million in compensatory damages, plus punitive damages, from us.

I In rulings applicable to all but six of the cases, involving claims related to approximately 50 children, the Circuit Court for Baltimore City dismissed with prejudice all claims against BGE and Constellation Energy. Plaintiffs may attempt to pursue appeals of the rulings in favor of BGE and Constellation Energy once the cases are finally concluded as to all defendants.

We believe that we have meritorious defenses and intend to defend the remaining actions vigorously. However, we cannot predict the timing, or outcome, of these cases, or their possible effect on our, or BGE's, financial results.

Asbestos Since 1993, BGE and certain Constellation Energy subsidiaries have been involved in several actions concerning asbestos. The actions are based upon the theory of "premises liability,"

alleging that BGE and Constellation Energy knew of and exposed individuals to an asbestos hazard. In addition to BGE and Constellation Energy, numerous other parties are defendants in these cases.

Approximately 522 individuals who were never employees of BGE or Constellation Energy have pending claims each seeking several million dollars in compensatory and punitive damages. Cross-claims and third-party claims brought by other defendants may also be filed against BGE and Constellation Energy in these actions. To date, most asbestos claims against us have been dismissed or resolved without any payment and a small minority have been resolved for amounts that were not material to our financial results. The remaining claims are currently pending in state courts in Maryland and Pennsylvania.

BGE and Constellation Energy do not know the specific facts necessary to estimate its potential liability for these claims.

The specific facts we do not know include:

+ the identity of the facilities at which the plaintiffs allegedly worked as contractors,

• the names of the plaintiffs' employers,

+ the dates on which and the places where the exposure allegedly occurred, and

• the facts and circumstances relating to the alleged exposure.

Until the relevant facts are determined, we are unable to estimate what our, or BGE's, liability might be.

Although insurance and hold harmless agreements from contractors who employed the plaintiffs may cover a portion of any awards in the actions, the potential effect on our, or BGE's, financial results could be material.

Storage of Spent Nuclear Fuel The Nuclear Waste Policy Act of 1982 (NWPA) required the federal government through the Department of Energy (DOE),

to develop a repository for, and disposal of, spent nuclear fuel and high-level radioactive waste. The NWPA and our contracts with the DOE required the DOE to begin taking possession of spent nuclear fuel generated by nuclear generating units no later than January 31, 1998. The DOE has stated that it will not meet that obligation until 2017 at the earliest.

This delay has required that we undertake additional actions related to on-site fuel storage at Calvert Cliffs and Nine Mile Point, including the installation of on-site dry fuel storage capacity at Calvert Cliffs. In January 2004, we filed a complaint against the federal government in the United States Court of Federal Claims seeking to recover damages caused by the DOE's failure to meet its contractual obligation to begin disposing of spent nuclear fuel by January 31, 1998. The case is currently stayed, pending litigation in other related cases.

In connection with our purchase of Ginna, all of Rochester Gas & Electric Corporation's (RG&E) rights and obligations related to recovery of damages for DOE's failure to meet its contractual obligations were assigned to us. However, we have an obligation to reimburse RG&E for up to

$10 million in recovered damages for such claims.

Nuclear Insurance We maintain nuclear insurance coverage for Calvert Cliffs, Nine Mile Point, and Ginna in four program areas: liability, worker radiation, property, and accidental outage. These policies contain certain industry standard exclusions, including, but not limited to, ordinary wear and tear, and war.

In November 2002, the President signed into law the Terrorism Risk Insurance Act ("TRIA") of 2002, which was extended by the Terrorism Risk Insurance Extension Act of 2005. Under the TRIA, property and casualty insurance companies are required to offer insurance for losses resulting 111

from Certified acts of terrorism. Certified acts of terrorism are determined by the Secretary of the Treasury, in concurrence with the Secretary of State and Attorney General, and primarily are based upon the occurrence of significant acts of international terrorism. Our nuclear liability, nuclear property and accidental outage insurance programs, as discussed later in this section, provide coverage for Certified acts of terrorism.

If there were an accident or an extended outage at any unit of Calvert Cliffs, Nine Mile Point or Ginna, it could have a substantial adverse impact on our Financial results.

Nuclear Liability Insurance Pursuant to the Price-Anderson Act, we are required to insure against public liability claims resulting from nuclear incidents to the full limit of public liability. This limit of liability consists of the maximum available commercial insurance of

$300 million and mandatory participation in an industry-wide retrospective premium assessment program. The retrospective premium assessment is $100.6 million per reactor, increasing the total amount of insurance for public liability to approximately $10.8 billion. Under the retrospective assessment program, we can be assessed up to $503 million per incident at any commercial reactor in the country, payable at no more than $75 million per incident per year. This assessment also applies in excess of our worker radiation claims insurance and is subject to inflation and state premium taxes.

Claims resulting from non-certified acts of terrorism are limited to the commercial insurance discussed above, regardless of the number of nuclear plants affected. In addition, the U.S.

Congress could impose additional revenue-raising measures to pay claims..

Worker Radiation Claims Insurance We participate in the American Nuclear Insurers Master Worker Program that provides coverage for worker tort claims filed for radiation injuries. Effective January 1, 1998, this program was modified to provide coverage to all workers whose nuclear-related employment began on or after the commencement date of reactor operations. Waiving the right to make additional claims under the old policy was a condition for coverage under the new policy. We describe the old and new policies below:

• All nuclear worker claims reported on or after January 1, 1998 are covered by a new insurance policy.

The new policy provides a single industry aggregate limit of $200 million for occurrences of radiation injury claims against all those insured by this policy prior to January 1, 2003 and $300 million for occurrences of radiation injury claims against all those insured by this policy on or after January 1, 2003.

• All nuclear worker claims reported prior to January 1, 1998 are still covered by the old policy. Insureds under the old policies, with no current operations, are not required to purchase the new policy described above, and may still make claims against the old policies through 2007. If radiation injury claims under these old policies exceed the policy reserves, all policyholders could be retroactively assessed, with our share being up to $6.3 million.

The sellers of Nine Mile Point retain the liabilities for existing and potential claims that occurred prior to November 7, 2001. In addition, the Long Island Power Authority, which continues to own 18% of Unit 2 at Nine Mile Point, is obligated to assume its pro rata. share of any liabilities for retrospective premiums and other premium assessments. RC&E, the seller of Ginna, retains the liabilities for existing and potential claims that occurred prior to June 10, 2004. If claims under these policies exceed the coverage limits, the provisions of the Price-Anderson Act would apply.

Nuclear Property Insurance Our policies provide $500 million in primary coverage at each nuclear plant-Calvert Cliffs, Nine Mile Point, and Ginna. In addition, we maintain $1.77 billion of excess coverage at Ginna and $2.25 billion in excess coverage under a blanket excess program offered by the industry mutual insurer at both Calvert Cliffs and Nine Mile Point. Under the blanket excess policy, Calvert Cliffs and Nine Mile Point share $1.0 billion of the total $2.25 billion of excess property coverage. Therefore, in the unlikely event of two full limit property damage losses at Calvert Cliffs and Nine Mile Point, we would recover

$4.5 billion instead of $5.5 billion. This coverage currently is purchased through the industry mutual insurance company. If accidents at plants insured by the mutual insurance company cause a shortfall of funds, all policyholders could be assessed, with our share being up to $92.6 million.

Losses resulting from non-certified acts of terrorism are covered as a common occurrence, meaning that if non-certified terrorist acts occur against one or more commercial nuclear power plants insured by our nuclear property insurance company within a 12-month period, they would be treated as one event and the owners of the plants where the acts occurred would share one fuall limit of liability (currently $3.24 billion).

Accidental Nuclear Outag Insurance Our policies provide indemnification on a weekly basis for losses resulting from an accidental outage of a nuclear unit.

Coverage begins after a 12-week deductible period and continues at 100% of the weekly indemnity limit for 52 weeks and then 80% of the weekly indemnity limit for the next 1 10 weeks. Our coverage is up to $490.0 million per unit at Calvert Cliffs and Ginna, $420.0 million for Unit 1 of Nine Mile Point, and $401.8 million for Unit 2 of Nine Mile Point.

This amount can be reduced by up to $98.0 million per unit at Calvert Cliffs and $84.0 million for Nine Mile Point if an outage of more than one unit is caused by a single insured physical damage loss.

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Non-Nuclear Property Insurance Our conventional property insurance provides coverage of

$1.0 billion per occurrence for Certified acts of terrorism as defined under TRIA and Terrorism Risk Insurance Extension Act of 2005. Certified acts of terrorism are determined by the Secretary of the Treasury, in concurrence with the Secretary of State and Attorney General, and primarily are based upon the occurrence of significant acts of international terrorism. Our conventional property insurance program also provides coverage for non-certified acts of terrorism up to an annual aggregate limit of $1.0 billion. If a terrorist act occurs at any of our facilities, it could have a significant adverse impact on our financial results.

13 Hedging Activities and Fair Value of Financial Instruments SFAS No. 133 Hedging Activities We are exposed to market risk, including changes in interest rates and the impact of market fluctuations in the price and transportation costs of electricity, natural gas, and other commodities.

Commodity Prices Merchant Energy Business Our merchant energy business uses a variety of derivative and non-derivative instruments to manage the commodity price risk of our competitive supply activities and our electric generation facilities, including power sales, fuel and energy purchases, gas purchased for resale, emission credits, weather risk, and the market risk of outages. In order to manage these risks, we may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from forecasted sales of energy and purchases of fuel and energy. The objectives for entering into such hedges include:

• fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return on our electric generation operations,

• fixing the price of a portion of anticipated fuel purchases for the operation of our power plants,

• fixing the price for a portion of anticipated energy purchases to supply our load-serving customers, and

+ fixing the price for a portion of anticipated sales of natural gas to customers.

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

At December 31, 2006, our merchant energy business had designated certain fixed-price forward contracts as cash-flow hedges of forecasted sales of energy and forecasted purchases of fuel and energy for the years 2007 through 2015 under SFAS No. 133. Our merchant energy business had net unrealized pre-tax losses on these cash-flow hedges recorded in "Accumulated other comprehensive income" of $2,227.1 million at December 31, 2006 and $517.1 million at December 31, 2005.

We expect to reclassify $1,522.1 million of net pre-tax losses on cash-flow hedges from "Accumulated other comprehensive income" into earnings during the next twelve months based on the market prices at December 31, 2006.

However, the actual amount reclassified into earnings could vary from the amounts recorded at December 31, 2006, due to future changes in market prices. Additionally, for cash-flow hedges settled by physical delivery of the underlying commodity, "Reclassification of net gains on hedging instruments from OCI to net income" represents the fair value of those derivatives, which is realized through gross settlement at the contract price.

We recognized into earnings $13.4 million pre-tax gain in 2006 and $19.4 million pre-tax loss in 2005 related to cash-flow hedge ineffectiveness.

In addition, during 2006, we de-designated contracts previously designated as cash-flow hedges for which the forecasted transaction originally hedged is probable of not occurring, and as a result we recognized a pre-tax loss of

$35.3 million. The majority of the pre-tax loss associated with de-designated contracts in 2006 resulted from the initial public offering of CEP and the sale of our gas-fired plants. During 2005, we terminated a contract previously designated as a cash-flow hedge. The forecasted transaction originally hedged was probable of not occurring and as a result we recognized a pre-tax loss of $6.1 million.

Our merchant energy business also enters into natural gas storage contracts under which the gas in storage qualifies for fair value hedge accounting treatment under SFAS No. 133. We recognized a $27.7 million pre-tax net gain for 2006 and

$2.2 million pre-tax net loss for 2005 due to hedge ineffectiveness. In addition, we recognized an $8.9 million pre-tax gain related to the change in value for the portion of our fair value hedges excluded from ineffectiveness testing. We record changes in fair value of these hedges related to our retail competitive supply operations as a component of "Fuel and purchased energy expenses" in our Consolidated Statements of Income. We record changes in fair value of these hedges related to our wholesale competitive supply operations as a component of"Nonregulated revenues" in our Consolidated Statements of Income.

Regulated Gas Business BGE uses basis swaps in the winter months (November through March) to hedge its price risk associated with natural gas purchases under its market-based rates incentive mechanism and under its off-system gas sales program. BGE also uses fixed-to-floating and floating-to-fixed swaps to hedge its price risk associated with its off-system gas sales. The fixed portion represents a specific dollar amount that BGE will pay or receive, and the floating portion represents a fluctuating amount based on a published index that BGE will receive or pay. BGE's regulated gas business internal guidelines do not permit the use of swap agreements for any purpose other than to hedge price risk. The impact of these swaps on our, and BGE's, financial results is immaterial.

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Reyeulated Electric Business BGE uses basis swaps to hedge its price risk associated with electricity purchases. BGE's regulated electric business internal guidelines do not permit the use of swap agreements for any purpose other than to hedge price risk. The impact of these swaps on our, and BGE's, financial results is immaterial.

Interest Rates We use interest rate swaps to manage our interest rate exposures associated with new debt issuances, to manage our exposure to fluctuations in interest rates on variable rate debt, and to optimize the mix of fixed and floating-tate debt. The swaps used to manage our exposure prior to the issuance of new debt and to manage the exposure to fluctuations in interest rates on variable rate debt are designated as cash-flow hedges under SFAS No. 133, with the effective portion of gains and losses, net of associated deferred income tax effects, recorded in "Accumulated other comprehensive income" in our Consolidated Statements of Common Shareholders' Equity and Comprehensive Income and Consolidated Statements of Capitalization, in anticipation of planned financing transactions. We reclassify gains and losses on the hedges from "Accumulated other comprehensive income" into "Interest expense" in our Consolidated Statements of Income during the periods in which the interest payments being hedged occur.

The swaps used to optimize the mix of fixed and floating-rate debt are designated as fair value hedges under SEAS No. 133. We record any gains or losses on swaps that qualify, for fair value hedge accounting treatment, as well as changes in the fair value of the debt being hedged, in "Interest expense," and we record any changes in fair value of the swaps and the debt in "Risk management assets and liabilities" and "Long-term debt" in our Consolidated Balance Sheets. In addition, we record the difference between interest on hedged fixed-rate debt and floating-rate swaps in "Interest expense" in the periods that the swaps settle.

"Accumulated other comprehensive income" includes net unrealized pre-tax gains on interest rate cash-flow hedges terminated upon debt issuance totaling $12.5 million at December 31, 2006 and $15.4 million at December 31, 2005.

We expect to reclassify $0.6 million of pre-tax net gains on these cash-flow hedges from "Accumulated other comprehensive income" into "Interest expense" during the next twelve months.

We had no hedge ineffectiveness on these swaps.

During 2006, in order to manage the exposure to fluctuations in interest rates on variable rate debt, CEP entered into a pay fixed-rate and receive floating-rate swap relating to

$16.5 million of its outstanding debt. "Accumulated other comprehensive income" includes net unrealized pre-tax gains on interest rate cash-flow hedges totaling $0.1 million at December 31, 2006. We had no hedge ineffectiveness on these swaps.

During 2004, to optimize the mix of fixed and floating-rate debt, we entered into interest rate swaps qualifying as fair value hedges relating to $450 million of our fixed-rate debt maturing in 2012 and 2015, and converted this notional amount of debt to floating-rate. The fair value of these hedges was an unrealized loss of $7.1 million at December 31, 2006 and $0.9 million at December 31, 2005 and was recorded as an increase in our "Risk management liabilities" and a decrease in our "Long-term debt."

We had no hedge ineffectiveness on these interest rate swaps.

Fair Value of Financial Instruments The fair value of a financial instrument represents the amount at which the instrument could be exchanged in a current transaction between willing parties, other than in a forced sale or liquidation. Significant differences can occur between the fair value and carrying amount of financial instruments that are recorded at historical amounts. We use the following methods and assumptions for estimating fair value disclosures for financial instruments:

• cash and cash equivalents, net accounts receivable, other current assets, certain current liabilities, short-term borrowings, current portion of long-term debt, and certain deferred credits and other liabilities: because of their short-term nature, the amounts reported in our Consolidated Balance Sheets approximate fair value,

• investments and other assets: the fair value is based on quoted market prices where available, and

• long-term debt: the fair value is based on quoted market prices where available or by discounting remaining cash flows at current market rates.

We show the carrying amounts and fair values of financial instruments included in our Consolidated Balance Sheets in the following table.

Ar December 31, 2006 2005 Carrying Fair Carrying Fair Amount Value Amount Value-(In millions)

Investments and other assets-Constellation Energy Fixed-rate long-term debt:

Constellation Energy BCE Variable-rate long-term debt:

Constellation Energy BGE

$1,468.8

$1,469.3

$1,362.1

$1,362.3 4,383.8 4,513.8 4,169.3 4,379.3 1,716.7 1,712.6 1,364.6 1,376.4 723.2 723.2 699.3 699.3 97.4 97.4 114

4 Stock-Based Compensation Under our long-term incentive plans, we granted stock options, performance and service-based restricted stock, performance-based units, and equity to officers, key employees, and members of the Board of Directors. Under the plans, we can grant up to a total of 18,000,000 shares. At December 31, 2006, we had stock options, restricted stock, performance unit and equity grants outstanding as discussed below. We may issue new shares, reuse forfeited shares, or buy shares in the market in order to deliver shares to employees for our equity grants. BGE officers and key employees participate in our stock-based compensation plans.

The expense recognized by BGE in 2006, 2005, and 2004 was not material to BGE's financial results.

Non-Qualified Stock Options Options are granted with an exercise price equal to the market value of the common stock at the date of grant, become vested over a period up to three years (expense recognized in tranches),

and expire ten years from the date of grant. The fair value of our stock-based awards were estimated as of the date of grant using the Black-Scholes option pricing model based on the following weighted-average assumptions:

During 2006, no stock options were granted to employees in anticipation of the proposed merger with FPL Group, which was terminated in October 2006. We discuss the termination of the merger in more detail in Note 15.

We use the historical data related to stock option exercises in order to estimate the expected life of our stock options. We also use historical data in order to estimate the volatility factor (measured on a daily basis) for a period equal to the duration of the expected life of option awards. We believe that the use of historical data to estimate these factors provides a reasonable basis for our assumptions. The risk-free interest rate for the periods within the expected life of the option is based on the U.S Treasury yield curve in effect and the expected dividend yield is based on our current estimate for dividend payout at the time of grant. 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:

2006 2005 2004 Risk-free interest rate 4.10% 3.15%

Expected life (in years) 2.9*

5.0 Expected market price volatility factor 21.3% 23.7%

Expected dividend yield 3.0%

3.0%

• Includes 2. 0 million fully vested options granted in December 2005, which would have been cancelled upon a change in control if our proposed merger with FPL Group would have been consummated and for which an expected life of one year was used to value the grant. Excluding this grant, we used a weighted-average expected life assumption of5years for 2005grants.

2006 2005 2004 Weighted-Weighted-Weighted-Average Average Average Shares Exercise Price Shares Exercise Price Shares Exercise Price (Shares in thousands)

Outstanding, beginning ofyear 7,172

$45.24 7,365

$31.62 7,117

$29.53 Granted with exercise prices at fair market value 3,840 54.94 1,640 39.60 Exercised (1,050) 33.77 (3,935) 29.32 (834) 28.49 Forfeited/expired (71) 45.22 (98) 42.19 (558) 33.09 Outstanding, end of year 6,051

$47.23 7,172

$45.24 7,365

$31.62 Exercisable, end of year 4,401

$46.94 4,022

$45.31 3,844

$29.99 Weighted-average fair value per share of options granted with exercise prices at fair market value

$ 7.13

$ 7.22 115

The following table summarizes additional information about stock options during 2006, 2005 and 2004:

We recorded compensation expense related to our restricted stock awards of $24.5 million in 2006, $28.2 million in 2005, and $17.0 million in 2004. Summarized share information for 04 our restricted stock awards is as follows:

Stock Option Expense Recognized Stock Options Exercised:

Cash Received for Exercise Price Intrinsic Value Realized by Employee Realized Tax Benefit Fair Value of Shares that Vested 2006 2005 (In millions)

$ 6.7

$ 14.4

$ 1.0 35.5 35.3 23.7 27.6 109.8 10.9 43.4 82.6 232.0 10.5 4.2 59.0 As of December 31, 2006, we had $2.8 million of unrecognized compensation cost related to the unvested portion of outstanding stock option awards, of which $2.5 million is expected to be recognized during 2007.

The following table summarizes additional information about stock options outstanding at December 31, 2006 (stock options in thousands):

Weighted-Outstanding Exercisable Average Range of Aggregate Aggregate Remaining Exercise Stock Intrinsic Stock Intrinsic Contractual Prices Options Value Options Value Life (In millions)

(In millions)

(In years)

$20.00 - $30.00 621

$ 24.8 621

$24.8 6.2

$30.00 - $40.00 1,655 52.6 1,209 39.6 6.5

$40.00 - $50.00 57 1.6 35 1.0 7.4

$50.00 - $60.00 3,718 50.4 2,536 30.0 6.7 6,051

$129.4 4,401

$95.4 Restricted Stock Awards In addition to stock options, we issue common stock based on meeting certain service goals. This stock vests to participants at various times ranging from one to five years if the service goals are met. In accordance with SFAS No. 123R, we account for our service-based awards as equity awards, whereby we recognize the value of the market price of the underlying stock on the date of grant to compensation expense over the service period either ratably or in tranches (depending if the award has cliff or graded vesting).

2006 2005 2004 (Shares in thousands)

Outstanding, beginning of year 1,272 1,223 752 Granted 511 485 1,002 Released to participants (502)

(359)

(467)

Canceled (74)

(77)

(64)

Outstanding, end of year 1,207 1,272 1,223 Weighted-average fair value of restricted stock granted (per share)

$58.68

$51.23

$38.83 Total fair value of shares for which restriction has lapsed (in millions)

$ 27.6

$ 19.0

$ 18.8 As of December 31, 2006, we had $16.2 million of unrecognized compensation cost related to the unvested portion of outstanding restricted stock awards expected to be recognized within a two-year period. At December 31, 2006, we have recorded in "Common shareholders' equity" approximately

$31.7 million and approximately $21 million at December 31, 2005 for the unvested portion of service-based restricted stock granted from 2001 until 2006 to officers and other employees that is contingently redeemable in cash upon a change in control.

Performance-Based Units In accordance with SFAS No. 123R, we recognize compensation expense ratably for our performance-based awards, which are classified as liability awards, for which the fair value of the award is remeasured at each reporting period. Each unit is equivalent to

$1 in value and cliffvests at the end of a three-year service and performance period. The level ofpayout is based on the achievement of certain performance goals at the end of the three-year period and will be settled in cash. We recorded compensation expense of $24.0 million in 2006, $7.0 million in 2005, and $2.9 million in 2004 for these awards. No awards were settled during the year, and as of December 31, 2006 we had $9.9 million of unrecognized compensation cost related to the unvested portion of outstanding performance-based unit awards expected to be recognized within a 14-month period.

Equity-Based Grants We recorded compensation expense of $0.6 million in 2006,

$0.5 million in 2005, and $0.5 million in 2004 related to equity-based grants to members of the Board of Directors.

116

I5 Merger and Acquisitions Termination of Merger Agreement with FPL Group, Inc.

On October 24, 2006, Constellation Energy and FPL Group agreed to terminate the Agreement and Plan of Merger the parties had entered into on December 18, 2005. In connection with the termination of the merger agreement, Constellation Energy acquired certain development rights from FPL Group relating to a wind power project in Western Maryland.

Pursuant to the terms of the termination agreement, if Constellation Energy announces its entry into certain types of transactions on or prior to September 30, 2007, including a merger or stock sale resulting in a third party owning 35% or more of the voting securities of Constellation Energy, it will be required to pay FPL Group a fee. The fee is $425 million if a transaction is announced on or prior to June 30, 2007 and $210 million if a transaction is announced between July 1,2007 and September 30, 2007.

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.

Acquisitions of Working Interests in Gas Producing Fields In the first quarter of 2006, we acquired working interests in gas and oil producing properties for approximately $100 million in cash. We purchased leases, producing wells, and related equipment. We have included the results of operations in our merchant energy business segment since the date of acquisition.

In June 2005, we acquired working interests in gas producing fields in Texas and Alabama for approximately

$211 million in cash and the assumption of below-market natural gas swaps and other liabilities totaling approximately

$18 million. The Texas asset acquisition was for approximately a 70% working interest and the Alabama asset acquisition was for a 100% working interest. We have included the results of operations for these working interests in our merchant energy business segment since the date of acquisition.

Acquisition of Cogenex In April 2005, we acquired Cogenex Corporation from Alliant Energy Corporation. We include Cogenex with our other nonregulated businesses and have included their results in our consolidated financial statements since the date of acquisition.

Cogenex is a North American energy services firm providing consulting and technology solutions to industrial, institutional, and governmental customers. We acquired 100% ownership of Cogenex for $34.9 million. We acquired cash of $14.4 million as part of the purchase.

Our final purchase price allocation for the net assets acquired is as follows:

At April 1, 2005 Cash Other Current Assets Total Current Assets Net Property, Plant and Equipment Other Assets Total Assets Acquired Current Liabilities Deferred Credits and Other Liabilities Net Assets Acquired (In millions)

$ 14.4 12.4 26.8 34.9 61.7 (8.0)

(18.8)

$ 34.9 We believe that the pro-forma impact of the Cogenex acquisition would not have been material to our results of operations in 2005.

I 6Related Party Transactions-BGE Income Statement BGE is obligated to provide market-based standard offer service to all of its electric customers for varying periods. Bidding to supply BGE's market-based standard offer service to electric customers will occur from time to time through a competitive bidding process approved by the Maryland PSC.

Our wholesale marketing, risk management, and trading operation will supply a substantial portion of BGE's market-based standard offer service obligation to residential electric customers through May 31, 2007, as well as a portion of BGE's market-based standard offer service obligations for all electric customers from June 1, 2007 through May 31, 2009.

The cost of BGE's purchased energy from nonregulated subsidiaries of Constellation Energy to meet its standard offer service obligation was as follows:

In addition, Constellation Energy charges BGE for the costs of certain corporate functions. Certain costs are directly assigned to BGE. We allocate other corporate function costs based on a total percentage of expected use by BGE. We believe this method of allocation is reasonable and approximates the cost BGE would have incurred as an unaffiliated entity.

The following table presents the costs Constellation Energy charged to BGE in each period.

Year ended December 31, 2006 2005 2004 (In millions)

$148.8

$130.3

$99.8 Charges to BGE Year Ended December 31, Electricity purchased for resale expenses 2006 2005 2004 (In millions)

$1,062.0

$805.9

$948.9 Balance Sheet BGE participates in a cash pool under a Master Demand Note agreement with Constellation Energy. Under this arrangement, participating subsidiaries may invest in or borrow from the pool at market interest rates. Constellation Energy administers the pool and invests excess cash in short-term investments or issues commercial paper to manage consolidated cash requirements.

Under this arrangement, BGE had invested $60.6 million at 117

December 31, 2006 and borrowed $3.2 million at December 31, Constellation Energy and its nonregulated affiliates for certain 2005.

services it provides them, and the participation of BGE's BGE's Consolidated Balance Sheets include intercompany employees in the Constellation Energy defined benefit plans.

amounts related to corporate functions performed at the We believe our allocation methods are reasonable and Constellation Energy holding company, BGE's purchases to approximate the costs that would be charged to unafflliated meet its standard offer service obligation, BGE's charges to entities.

1 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.

2006 Quarterly Data-Constellation Energy 2006 Quarterly Data-BGE Earnings Earnings Per Share Earnings Per Income Applicable from Share of Earnings Income from to Continuing Common Income Applicable from Continuing Common Operations-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 March31*

$ 4,859.2

$ 204.0

$101.6

$113.9

$0.56

$0.63 March31

$ 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 total for the year due to the effects of rounding and dilution as a result of issuing common shares during the year.

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, 4 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.

• Due to the reclassification of our High Desert facility to discontinued operations, we have reclassified certain amounts previously reported in our first, second, and third quarter Form 10-Qs. The following is a reconciliation of amounts previously reported to amounts currently presented for those items.

118

For the quarter ended March 31, 2006 Discontinued

\\s Reported Operations Reclassified As Re June 30, 200 Discontinue ported Operations millions, except per sA Revenues

$4,897.5

$(38.3)

$4,859.2

$4,421.9

$(43.1)

Income from Operations 222.5 (18.5) 204.0 208.7 (30.4)

Income from Continuing Operations 113.0 (11.4) 101.6 93.1 (19.1)

Earnings Per Share from Continuing Operations-Diluted 0.63 (0.07) 0.56 0.52 (0.11) 2005 Quarterly Data-Constellation Energy Earnings Per Share Income from from Continuing Continuing Operations Operations and Before and Before Cumulative Cumulative Earnings Effects of Earnings P1 Effects of Applicable Changes in Share of Income Changes in to Accounting Common from Accounting Common Principles-Stock-Revenues Operations Principles Stock Diluted Diluted (In millions, except per share amounts) 06 September 30, 2006 ed Discontinued Reclassified As Reported Operations Reclassified

'are amounts)

$4,378.8

$5,433.7

$ (40.3)

$5,393.4 178.3 559.9 (29.0) 530.9 74.0 324.4 (18.0) 306.4 0.41 1.79 (0.10) 1.69 2005 Quarterly Data-BGE er Earnings Income Applicable from to Common Revenues Ooerations Stock i(In million*

(In millions)

Quarter Ended Quarter Ended March 31"

$ 3,532.6

$ 193.8

$ 100.8

$120.7

$0.57

$0.68 March 31

$ 857.3

$ 143.7

$ 71.0 June 30*

3,438.0 183.0 101.1 121.7 0.57 0.68 June 30 610.3 64.4 23.6 September 30*

4,879.9 287.4 165.5 185.5 0.92 1.03 September 30 742.7 94.9 42.4 December 31 5,117.8 280.3 168.5 195.2 0.94 1.09 December 31 799.0 93.5 38.8 Year Ended Year Ended December 31

$ 16,968.3

$944.5

$535.9

$623.1

$2.98

$3.47 December 31

$3,009.3

$396.5

$ 175.8 The sum of the quarterly earnings per share amounts may not equal the total for the year due to the effects of rounding and dilution as a result of issuing common shares during the year.

First quarter results include:

• a $17.8 million gain after-tax for the discontinued operations of our High Desert facility,

• a $1.7 million gain after-tax for the discontinued operations related to our other nonregulated international investments, and

• a $0.4 million gain after-tax for the discontinued operations related to our Oleander facility.

Second quarter results include:

+ a $16.7 million gain after-tax for the discontinued operations of our High Desert facility,

• a $2.6 million gain after-tax for the discontinued operations related to our Oleander facility, and

+ a $1.3 million gain after-tax income for discontinued operations related to our other nonregulated international investments.

Third quarter results include:

• an $18.6 million gain after-tax for the discontinued operations of our High Desert facility,

• workforce reduction costs totaling $2.3 million after-tax, and

+ a $1.4 million gain after-tax for discontinued operations related to our other nonregulated international investments.

Fourth quarter results include:

• a $17.7 million gain after-tax for the discontinued operations of our High Desert facility,

• a $16.2 million gain after-tax for discontinued operations related to our other nonregulated international investments,

• merger-related costs totaling $15.6 million after-tax, of which BGE recorded $5.0 million after-tax,

• a $7.4 million after-tax loss for the cumulative effect of adopting FIN 47,

+ workforce reduction costs totaling $0.3 million after-tax, and

• a $0.2 million after-tax gain for the cumulative effect of adopting SFAS No. 123R.

We discuss these items in Note 2.

• Due to the reclassification of our High Desert facility to discontinued operations, we have reclassified certain amounts previously reported in our first, second, and third quarter Form 1O-Qs. The following is a reconciliation of amounts previously reported to amounts currently presented for those items.

119

For the quarter ended March 31, 2005 June 30, 2005 September 30, 2005 As Discontinued Discontinued Discontinued Reported Operations Reclassified As Reported Operations Reclassified As Reported Operations Reclassified (In millions, except per share amounts)

$ 3,572.0

$ (39.4)

$ 3,532.6

$ 3,478.5

$ (40.5)

$ 3,438.0

$4,922.4

$ (42.5)

$ 4,879.9 221.9 (28.1) 193.8 209.8 (26.8) 183.0 317.0 (29.6) 287.4 Revenues Income from Operations Income from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles Earnings Per Share from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles-Diluted 118.6 (17.8) 0.67 (0.10) 100.8 117.8 (16.7) 101.1 184.1 (18.6) 165.5 0.92 0.57 0.66 (0.09) 0.57 1.02 (0.10) 120

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None.

Item 9A. 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, 2006 (the "Evaluation Date"). Based on such evaluation, such officers have concluded that, as of the Evaluation Date, Constellation Energy's and BGE's disclosure controls and procedures are effective.

Internal Control Over Financial Reporting Constellation Energy maintains a system of internal control over financial reporting as defined in Exchange Act Rule 13a-15(0.

Constellation Energy's Management Report on Internal Control Over Financial Reporting is included in Item 8. Financial Statements and Supplementary Data included in this report. As BGE is not an accelerated filer as defined in Exchange Act Rule 12b-2, it is not required to provide a report of management on the effectiveness of its internal control over financial reporting as of December 31, 2006, but will be required to do so as of December 31, 2007.

Changes in Internal Control During the quarter ended December 31, 2006, 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(o 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.

121

PART III BGE meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K for a reduced disclosure format. Accordingly, all items in this section related to BGE are not presented.

Item 10. Directors and Executive Officers of the Registrant The information required by this item with respect to directors will be set forth under Election of Directors in the Proxy Statement and incorporated herein by reference.

The information required by this item with respect to executive officers of Constellation Energy Group, pursuant to instruction 3 of paragraph (b) of Item 401 of Regulation S-K, is set forth following Item 4 of Part I of this Form 10-K under Executive Officers of the Registrant.

Item 11. Executive Compensation The information required by this item will be set forth under Executive and Director Compensation and Report of Compensation Committee in the Proxy Statement and incorporated herein by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters The additional information required by this item will be set forth 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, 2006:

(a)

Number of securities to be issued upon exercise of outstanding options, (b)

Weighted-average exercise price of outstanding options, (c)

Number of securities remaining available for future issuance under equity compensation 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 4,414

$49.72 2,847 Equity compensation plans not approved by security holders 1,637

$40.53 892 Total 6,051

$47.23 3,739 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. 10(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 was effective May 24, 2002. Grants under the plan may be made to employees who are officers of Constellation Energy.or hold senior management level or key employee positions with Constellation Energy or its subsidiaries. Under the plan, the Board of Constellation Energy has authorized the issuance of up to 4,000,000 shares of Constellation Energy common stock in connection with the grant of stock options, performance and service-based restricted stock and restricted stock units, performance units, stock appreciation rights, dividend equivalents and other equity awards. Any shares covered by an award that is forfeited or canceled, expires or is settled in cash, including the settlement of tax withholding obligations using shares, will become available for issuance under the plan. Shares delivered under the plan may be authorized and unissued shares or shares purchased on the open market in accordance with the applicable securities laws. Restricted stock, restricted stock unit, and performance unit award payouts will be accelerated and stock options and stock appreciation rights gains will be paid in cash in the event of a change in control, as defined in the plan. The plan is administered by Constellation Energy's Chief Executive Officer.

122

Management Long-Term Incentive Plan The Management Long-Term Incentive Plan was effective February 1, 1998. Grants under the plan may be made to employees of Constellation Energy who hold a management level position and other employees of Constellation Energy and its subsidiaries as may be designated by Constellation Energy's Chief Executive Officer. Under the plan, the Board of Constellation Energy has authorized the issuance of up to 3,000,000 shares of Constellation Energy common stock in connection with the grant of stock options, performance and service-based restricted stock and restricted stock units, performance units, stock appreciation rights and dividend equivalents. The number of shares available for issuance under the plan includes shares subject to awards that have lapsed or terminated. Shares delivered under the plan may be authorized and unissued shares or shares purchased on the open marketin accordance with applicable securities laws. Restricted stock, restricted stock unit, 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 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 ofAppointment ofPricewaterhouseCoopers LLP as Independent Registered Public Accounting Firm for 2007 in the Proxy Statement and incorporated herein by reference.

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, 2007 of PricewaterhouseCoopers LLP Consolidated Statements of Income-Constellation Energy Group for three years ended December 31, 2006 Consolidated Balance Sheets-Constellation Energy Group at December 31, 2006 and December 31, 2005 Consolidated Statements of Cash Flows-Constellation Energy Group for three years ended December 31, 2006 Consolidated Statements of Common Shareholders' Equity and Comprehensive Income-Constellation Energy Group for three years ended December 31, 2006 Consolidated Statements of Capitalization-Constellation Energy Group at December 31, 2006 and December 31, 2005 Consolidated Statements of Income-Baltimore Gas and Electric Company for three years ended December 31, 2006 Consolidated Statements of Comprehensive Income-Baltimore Gas and Electric Company for three years ended December 31, 2006 Consolidated Balance Sheets-Baltimore Gas and Electric Company at December 31, 2006 and December 31, 2005 Consolidated Statements of Cash Flows-Baltimore Gas and Electric Company for three years ended December 31, 2006 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.

123

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-Qfor 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 1-19 10.)

• 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-Qfor 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 Constellation Energy Group, Inc., as amended to October 20, 2006. (Designated as Exhibit 3(a) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2006, File Nos. 1-12869 and 1-1910.)

• 3(g)

Bylaws of BGE, as amended to October 16, 1998. (Designated as Exhibit No. 3 to the Quarterly Report on Form 10-Qfor the quarter ended September 30, 1998, File No. 1-1910.)

• 4(a)

Indenture between Constellation Energy Group, Inc. and the Bank of New York, Trustee dated as of March 24, 1999. (Designated as Exhibit No. 4(a) to the Registration Statement on Form S-3 dated March 29, 1999, File No. 333-75217.)

• 4 (b)

First Supplemental Indenture between Constellation Energy Group, Inc. and the Bank of New York, Trustee dated as of January 24, 2003. (Designated as Exhibit No. 4(b) to the Registration Statement on Form S-3 dated January 24, 2003, File No. 333-102723.)

• 4(c)

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 I0-Q for the quarter ended June 30, 1995, File No. 1-1910); as supplemented by Supplemental Indentures dated as ofJune 15, 1996 (Designated as Exhibit No. 4 to the Quarterly Report on Form 10-Qfor the quarter ended June 30, 1996,) and as of June 26, 2000 (filed herewith).

124

• 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(0 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.)

• 4(1)

First Supplemental Indenture between Baltimore Gas and Electric Company and Deutsche Bank Trust Company Americas, as trustee, dated as of October 13, 2006. (Designated as Exhibit 4(a) to the Quarterly Report on Form 10-Qfor the quarter ended September 30, 2006, File Nos. 1-12869 and 1-1910.)

• 4(m) -

Registration Rights Agreement dated October 13, 2006 among Baltimore Gas and Electric Company and the parties named therein relating to 5.90% Notes due 2016. (Designated as Exhibit 4(b) to the Quarterly Report on Form IO-Q for the quarter ended September 30, 2006, File Nos. 1-12869 and 1-1910.)

• 4(n)

Registration Rights Agreement dated October 13, 2006 among Baltimore Gas and Electric Company and the parties named therein relating to 6.35% Notes due 2036. (Designated as Exhibit 4(c) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2006, File Nos. 1-12869 and 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.)

125

• 10(e)

Compensation agreements between Constellation Energy Group, Inc. and E. Follin Smith (Attachment 1-Employment Agreement; Attachment 2-Severance Agreement (Attachment 2 superseded by amended and restated change in control severance agreement filed as Exhibit lO(y) to the Annual Report on Form 10-K for the year ended December 31, 2005.)(Designated as Exhibit 10(c) to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, File Nos. 1-12869 and 1-1910.)

• 10(f)

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(g)

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(h)

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 1-19 10.)

• 10(i)

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(j)

Constellation Energy Group, Inc. Benefits Restoration Plan, as amended and restated. (Designated as Exhibit No. 10(m) to the Annual Report on Form IO-K for the year ended December 31, 2001, File Nos. 1-12869 and 1-1910.)

• 10(k)

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(1)

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(m) -

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(n)

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(o)

Constellation Energy Group, Inc. 2002 Executive Annual Incentive Plan, as amended and restated.

• 10(p)

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.)

• 1O(q)

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 1-19 10.)

• 10(r)

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 IO-K for the year ended December 31, 2004, File Nos. 1-12869 and 1-1910.)

• 10(s)

Amended and restated change in control severance agreement between Constellation Energy Group, Inc.

and E. Follin Smith. (Designated as Exhibit 10(o) to the Annual Report on Form 10-K for the year ended December 31, 2005.)

10(t)

Constellation Energy Group, Inc. 2007 Long-Term Incentive Plan.

12 (a). -

Constellation Energy Group, Inc. and Subsidiaries Computation of Ratio of Earnings to Fixed Charges.

126

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, Chief Executive Officer and President of Constellation Energy Group, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31 (b)

Certification of Executive Vice President, Chief Financial Officer and Chief Administrative 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, Chief Executive Officer and President 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.

127

CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES AND BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES SCHEDULE Il-VALUATION AND QUALIFYING ACCOUNTS Column A Column B Balance at beginning of period Column C Column D Additions Charged Charged to to costs Other and Accounts-(Deductions)-

expenses Describe Describe (In millions)

Description Reserves deducted in the Balance Sheet from the assets to which they apply:

Constellation Energy Accumulated Provision for Uncollectibles 2006 2005 2004 Valuation Allowance Net unrealized (gain) loss on available for sale securities 2006 2005 2004 Net unrealized (gain) loss on nuclear decommissioning trust funds 2006 2005 2004 Column E Balance at end of period

$ 48.9 47.4 43.1

$ 47.4 43.1 51.7 0.6 0.1 (110.3)

(73.3)

(13.7)

$29.7 30.9 22.2

$ (28.2)(A)

(26.6)(A)

(30.8)(A)

(19.1)(B) 0.5(B) 0.1(B)

(95.8)(B)

(37.0)(B)

(59.6)(B)

(18.5) 0.6 0.1 (206.1)

(110.3)

(73.3)

BGE Accumulated Provision for Uncollectibles 2006 13.0 18.1 2005 13.0 14.1 2004 10.7 16.3 (A) Represents principally net amounts charged off as uncollectible.

(B)

Represents amounts recorded in or reclassified from accumulated other comprehensive income.

(15.0)(A)

(14.1)(A)

(14.0)(A) 16.1 13.0 13.0 128

SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Constellation Energy Group, Inc., the Registrant, has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.

CONSTELLATION ENERGY GROUP, INC.

(REGISTRANT)

Date: February 27, 2007 By /s/

MAYO A. SHATTUCK III Mayo A. Shattuck III Chairman of the Board, Chief Executive Officer and President 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 Principal executive officer and director:

By Is!

M. A. Shattuck III M. A. Shattuck III Principal financial and accounting officer:

By /s/

E. F. Smith E. F. Smith Directors:

/s/

Y. C. de Balmann Y. C. de Balmann

/s/

D. L. Becker D. L. Becker

/s/

J. T. Brady J. T. Brady

/s/

J. R. Curtiss J. R Curtiss

/s/

F. A. Hrabowski, III F. A. Hrabowski, III

/s/

N. Lampton N. Lampton

/s/

R. J. Lawless R. J. Lawless

/s/

M. D. Sullivan M. D. Sullivan Title Date Chairman of the Board, Chief Executive Officer, President and Director February 27, 2007 Executive Vice President, Chief Financial Officer, and Chief Administrative Officer Director Director Director Director Director Director Director Director February 27, 2007 February 27, 2007 February 27, 2007 February 27, 2007 February 27, 2007 February 27, 2007 February 27, 2007 February 27, 2007 February 27, 2007 129

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Baltimore Gas and Electric Company, the Registrant, has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.

BALTIMORE GAS AND ELECTRIC COMPANY (REGISTRANT)

February 27, 2007 By Is/

KENNETH W. DEFONTES, JR.

Kenneth W. DeFontes, Jr.

President and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of Baltimore Gas and Electric Company, the Registrant, and in the capacities and on the dates indicated.

Signature Title Date Principal executive officer and director:

By /s/

K. W. DeFontes, Jr.

K. W. DeFontes, Jr.

Principal financial and accounting officer and director:

President, Chief Executive Officer, and Director February 27, 2007 By /s/

E. F. Smith E. F. Smith Senior Vice President, Chief Financial Officer, and Director February 27, 2007 Directors:

/s/

M. A. Shattuck III M. A. Shattuck III Director February 27, 2007 130

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-Qfor 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 Constellation Energy Group, Inc., as amended to October 20, 2006. (Designated as Exhibit 3(a) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2006, File Nos. 1-12869 and 1-1910.)

• 3(g)

Bylaws of BGE, as amended to October 16, 1998. (Designated as Exhibit No. 3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 1998, File No. 1-1910.)

• 4 (a)

Indenture between Constellation Energy Group, Inc. and the Bank of New York, Trustee dated as of March 24, 1999. (Designated as Exhibit No. 4(a) to the Registration Statement on Form S-3 dated March 29, 1999, File No. 333-75217.)

• 4(b)

First Supplemental Indenture between Constellation Energy Group, Inc. and the Bank of New York, Trustee dated as of January 24, 2003. (Designated as Exhibit No. 4(b) to the Registration Statement on Form S-3 dated January 24, 2003, File No. 333-102723.)

• 4(c)

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 IO-Q for the quarter ended June 30, 1996,) and as of June 26, 2000 (filed herewith).

131

• 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. 333-10768 1.)

• 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.)

• 4(1)

First Supplemental Indenture between Baltimore Gas and Electric Company and Deutsche Bank Trust Company Americas, as trustee, dated as of October 13, 2006. (Designated as Exhibit 4(a) to the Quarterly Report on Form 10-Qfor the quarter ended September 30, 2006, File Nos. 1-12869 and 1-1910.)

• 4(m) -

Registration Rights Agreement dated October 13, 2006 among Baltimore Gas and Electric Company and the parties named therein relating to 5.90% Notes due 2016. (Designated as Exhibit 4(b) to the Quarterly Report on Form 10-Qfor the quarter ended September 30, 2006, File Nos. 1-12869 and 1-1910.)

• 4(n) -

Registration Rights Agreement dated October 13, 2006 among Baltimore Gas and Electric Company and the parties named therein relating to 6.35% Notes due 2036. (Designated as Exhibit 4(c) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2006, File Nos. 1-12869 and 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.)

132

• 10(e)

Compensation agreements between Constellation Energy Group, Inc. and E. Follin Smith (Attachment 1-Employment Agreement; Attachment 2-Severance Agreement (Attachment 2 superseded by amended and restated change in control severance agreement filed as Exhibit 10(y) to the Annual Report on Form 10-K for the year ended December 31, 2005.)(Designated as Exhibit 10(c) to the Quarterly Report on Form IO-Q for the quarter ended June 30, 2004, File Nos. 1-12869 and 1-1910.)

• 10(0 Amended and restated change in control severance agreement between Constellation Energy Group, Inc.

and Thomas V. Brooks. (Designated as Exhibit 1 0(f) to the Annual Report on Form 10-K for the year ended December 31, 2005.)

• 10(g)

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(h)

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(i)

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(j)

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(k) -

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(1)

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(m) -

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(n)

Constellation Energy Group, Inc. Executive Long-Term Incentive Plan, as amended and restated.

(Designated as Exhibit 10(b) to the Quarterly Report on Form IO-Q for the quarter ended September 30, 2006, File Nos. 1-12869 and 1-1910.)

10(o)

Constellation Energy Group, Inc. 2002 Executive Annual Incentive Plan, as amended and restated.

• 10(p) -

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.)

• 1O(q)

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.)

• 10(r)

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(s)

Amended and restated change in control severance agreement between Constellation Energy Group, Inc.

and E. Follin Smith. (Designated as Exhibit 10(o to the Annual Report on Form 10-K for the year ended December 31, 2005.)

10(t)

Constellation Energy Group, Inc. 2007 Long-Term Incentive Plan.

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.

133

21 Subsidiaries of the Registrant.

23 Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm.

31 (a)

Certification of Chairman of the Board, Chief Executive Officer and President of Constellation Energy Group, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31(b)

Certification of Executive Vice President, Chief Financial Officer and Chief Administrative 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, Chief Executive Officer and President 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.

134

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 nor 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.

B~asedl 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-1 5(e) and 15d-I 5(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-I 5(0) and 15d-1 50O 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, 2007

/s/ MAYO A. SHATTUCK III Chairman of the Board, President and Chief Executive Officer

Exhibit 31(b)

CONSTELLATION ENERGY GROUP, INC.

CERTIFICATION I, E. Follin Smith, certify that:

1.

I 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, 2007

/s/!E. FOLLIN SMITH Executive Vice President, Chief Financial Officer and Chief Administrative Officer

Exhibit 31 (c)

BALTIMORE GAS AND ELECTRIC COMPANY CERTIFICATION I, Kenneth W. DeFontes, Jr., certify that:

1.

I 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 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)) 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)

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 (c)

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, 2007 Is/ KENNETH W. DEFONTES, JR.

President and Chief Executive Officer

Exhibit 31 (d)

BALTIMORE GAS AND ELECTRIC COMPANY CERTIFICATION I, E. Follin Smith, certify that:

1.

I 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 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)) 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)

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 (c)

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, 2007

/s/ E. FOLLIN SMITH 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, 2006 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. SHATFUCK III Mayo A. Shattuck III Chairman of the Board, President and Chief Executive Officer Date: February 27, 2007

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, E. Follin Smith, Executive Vice President, Chief Financial Officer, and Chief Administrative 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, 2006 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.

/s/ E. FOLLIN SMITH E. Follin Smith Executive Vice President, Chief Financial Officer and Chief Administrative Officer Date: February 27, 2007

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, 2006 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/ KENNETH W. DEFONTES, JR.

Kenneth W. DeFontes, Jr.

President and Chief Executive Officer Date: February 27, 2007

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, E. Follin Smith, 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, 2006 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/ E. FOLLIN SMITH E. Follin Smith Senior Vice President and Chief Financial Officer Date: February 27, 2007