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 R.E. Ginna Nuclear Power Plant, LLC Site Vice President 1503 Lake Road Ontario, New York 14519-9364 585.771.5200 585.771.3943 Fax maria.korsnick@costellation.com 0 Generation 0Constellation Group Energy May 23, 2007 U. S. Nuclear Regulatory Commission Washington, DC 20555 ATTENTION: Document Control Desk

SUBJECT:

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.

global markets energy policy balance , . dependability ffdc,

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inty invoem dem*and value wise investments customized sol 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

$3.61 $19.3

$17.0

$2.89

$2.43

$12.1

'04 '05 '06 '04 '05 '06 ADJUSTED EARNINGS PER SHARE REVENUES (In hilliomnofdal]La)

Our adjusted earnings per share grew to a record Continuing our record performance, total revenues increased

$3.61, up 25 percent from 2005. to $19.3 billion in 2006. Our growing scale, extensive industry knowledge, and disciplined risk management approach give us Note: See Financial Hlighlights, including the GAAP reconciliation, on the inside from cover for more details. Also, cerLain prior year amounts a strong competitive edge.

have been reclassified to conform to current year's presentation.

$1.74

-$1704180

$1.51 -$157-162

$1.34 555

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'04 '05 '06 '07 DIVIDEND GROWTH PRODUCTIVITY GAINS (Assassalamountsper share)

(IN millions ofdol.,)

Our commitment to shareholders has included increasing Since announcing our long-term productivity initiatives dividends approximately in line with our earnings growth. in 2003, we've achieved $97 million in pre-tax savings, and Since 2004, our annual dividend payments have increased we expect to deliver up to $83 million in additional permanent by monre than 52 percent. productivity gains over the next two years.

PERFORMANCE MATTERS

$130 N CONSTELLATION ENERGY a S&P500 5123.21 S&.500.ELECTrIC

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$120

$115.79

$110

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$90 ' i 12/31/05 - Q1 '06 Q2 '06 Q3 Wo 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.

$300

$250

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$150

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'01 '02 '03 '04 '05 '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 Mayo A. Shattuck Ill wise Investments cistornized solutions Cbairman,President & CEO DEAR FELLOW SHAREHOLDERS:

2006 was an extraordinary year for our company on many fronts, and sheet, aid the remainder of the proceeds provides finds for tIs to invest we delivered exceptional results. We generated $19.3 billion in revenues in more strategically aligned opportunities.

and grew adjusted earnings by 25 percent to a record $3.61 per share.

The strong execution of our business strategy translated into superior RETURNING TO REGULATORY STABILITY IN MARYLAND returns for our investors. Including stock price appreciation and divi- Volatile power and gas prices, the end of a six-year freeze on residential dends, we achieved total shareholder return of nearly 23 percent in 2006, electric rates, and election-year politics made 2006 a challenging and following a 35 percent return in 2005. difficult year for our regulated transnmission and distribution utility, These results continue our long track record of success. Our current Baltimore Gas asd Electric Company (BGE), and its customers.

management team has met or exceeded our earnings targets and the guidance My expectation is that 2007 will see a return to a more stable regula-we gave Wall Street for more than five years. And since November 2001- tory climate in Maryland. There is widespread support for Maryland's suc-the expansion of our competitive strategy-our shares have appreciated cessful market structure, and the Maryland Public Service Commission 208 percent, three times greater than the S&P 500 Electric Utilities Index already has initiated proceedings designed to identify and implement and six times greater than the S&P 500. improvements in the wholesale energy auction process. The improve-Our success also has allowed us to grow dividends approximately ments should help reduce the likelihood of sudden and severe price in line with our earnings growth. In January 2007, we announced a spikes for residential customers.

quarterly dividend increase of 15 percent-from 37.75 cents per share to We remain committed to doing everything we can to help customers 43.5 cents per share-equivalent to a new annual dividend of $1.74. manage rising power prices. An important focus is introducing new options for our customers to better manage their usage and lower their EXECUTING ON ALL FRONTS bills. The options include new demand response and advanced metering Our continued success is due in large part to our integrated, yet diversi- programs, which BGE will launch to test groups later this year. We fied, business model. Each business excels in its market artid contributes believe these types of energy management and conservation programs to our overall performance. will become a way of life for BGE and its customers.

Constellation Energy Commodities Group, our competitive energy wholesale business, is a global leader in energy portfolio management, the DEFINING A STRONG INDEPENDENT COURSE largest power marketer in the country, and the fifth largest gas marketer. Last year at this time, it was our expectation that our proposed merger We continue to grow our power business profitably, and we're making with FPL Group would have closed by now. However, last October, given significant gains in natural gas and coal markets in the United States the considerable regulatory and political uncertainty in Maryland, we and abroad. In addition, the successful initial public offering (lPO) of reached a mutual and amicable agreement to terminate it.

Constellation Energy Partners LI.C last November was an important The reaction from investors was favorable. Reaffirming our independ-milestone and will help us realize more value from our expanding port- ent course and promising future, our stock reached a new all-time high folio of natural gas properties. in 2006. This tells tLsthree things: investors understand fully why we On the retail side, both Constellation NewEnergy and Constellation entered-and why we exited-the proposed merger; they have full confi-NewEnergy-Gas performed very well. We've steadily grown sales volumes dence in our strengths and capabilities as a stand-alone company; and they and margins, and our high renewal rates for power and gas provide stabil- believe we're returning to a period of greater stability in energy markets.

ity in our customer base. More importantly, the future growth picture for The proposed merger would have enabled us to meet an important these businesses is strong. strategic goal and rapidly grow the scale of our company. However, it fell Constellation Energy Generation Group also had a busy and victim to events beyond the control of either company.

productive year. We increased generating capacity by 17 percent at our I look back on our outstanding performance during this challenging R.E. Ginna Nuclear Power Plant, and we completed a refueling outage period with great pride. Despite the distractions, we continued to live up at our Nine Mile Point Nuclear Station in record time. to the commitment of meeting and exceeding our financial promises Our generation team also completed the successful sale of six of to investors.

our gas-fired merchant plants for $1.6 billion. Market conditions were advantageous, and the attractive price we received provided us with a sig- THINKING STRATEGICALLY ABOUT THE FUTURE nificant return on our investments in the plants. We've used a portion of I strongly believe that competitive markets are the future of the energy the proceeds to pay down debt and strengthen our already strong balance industry. They're good for customers, for the economy, and for companies

alff.3, J ab i rt f1,-Ifl f environment growth strategy "O"I~ler reliabilityfil utsncr cvice is r1Tnn-~~h~5rt~I ~ -i Lt--- ____

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like ours that value efficiency and being the best at meeting customers' We'll achieve this growth by continuing to do what we do best.

needs. Competitive markets provide incentive for companies to contimn- We'll deploy capital wisely and identify and execute on opportunities that ously work toward better and more efficient ways to meet our nation's can drive long-term growth. We'll leverage the scale and capabilities of energy needs. That incentive drives our success. our competitive platform by further integrating our merchant organiza-Energy markets that are open to competition are working. tion. And we'll continue to identify and empower the best and brightest Competition has done what it is supposed to do-it has improved effi- minds in our industry.

ciency and lowered costs. Power plants are operating more efficiently in In 2007, a major element of our growth story is investment. We're competitive markets, and wholesale power price increases are consistently spending more to earn more. In the years ahead, we'll invest more in lower than increases in fuel prices-a clear sign there is downward prcs- BGE, more in our gas portfolio, and considerably more to upgrade our sure on costs in the marketplace. Maryland plants to meet the requirements of the state's healthy air act.

It's a trend that I believe will only grow. As a leading advocate and Our generation fleet is among the cleanest in the industry, and we're the No. 1 provider of electricity in competitive markets, we'll continue fully committed to maintaining and broadening the scope of our envi-to speak out in Washington, D.C., and in states that have opened their ronmental efforts. Over the next three years, we're planning to invest markets to competition or are dealing with deregulation issues. approximately $1.1 billion to produce cleaner energy. We'll also continue Other important energy matters-the cost of energy, the global to invest in the option for new nuclear power through UniStar Nuclear, events that control supply and demand, the need for more clean energy, our joint enterprise with AREVA.

and the growing strain on the existing energy infrastructure-are becom-ing the topic of frank discussions in households and statehouses across THE BEST IN THE BUSINESS North America. More than ever before, people are becoming aware of One of our best stories in 2006 was our people. During our United the importance of energy to everything around them-and are thinking Way pledge drive, our employees responded by doing even more to help strategically about energy solutions. the communities we serve. We boosted our pledge total by 20 percent Most of us can agree on the elements of our nation's energy future: and raised close to $5 million-making us the No. 1 contributor in greater conservation and energy management programs; a commitment Central Maryland and a leading contributor in other markets where we to reducing greenhouse gases and making greater use of renewable do business.

energy; and a more constructive partnership between energy suppliers, This speaks to the type of employees we have at Constellation customers, regulators, and lawmakers. Energy. We're committed to delivering value to our shareholders-and For the second consecutive year, the Dow Jones Sustainability North we're committed to every community we serve.

America Index has included Constellation Energy on its list of companies I feel very confident about our future. We're the established leader that operate in a socially responsible and sustainable way. Customers turn in the competitive energy sector and a respected nuclear fleet operator.

to our energy supply companies for renewable energy options. We're also BGE continues to be a top-performing utility: Our emerging businesses an industry leader in providing emission-free nuclear power, and we've in the United States and abroad are performing well. We just completed established effective waste recycling and pollution prevention programs. our fifth consecutive year of record growth. And the forecast for 2007 As a leader in corporate responsibility, we believe a solution must be devel- and beyond is promising.

oped to slow, then stop, and eventually reverse greenhouse gas emissions. Constellation Energy has distinguished itself as a remarkable com-The pathway to a greener, more cost-effective energy future is com- pany with a very bright future. Thank you for being part of it.

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 Mayo A. Shattuck III market conditions. We believe there is more to come. We expect to deliver Chairman, President,and CEO compound annual earnings growth of 22 percent to 26 percent from 2005 to 2008. March 26, 2007 3

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I SC e 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 SERVING THE WORLD'S LEADING COMPANIES Managing energy costs and usage, and the associated risks, is chal- Our customers include more than two-thirds of the FORTUNE 100, lenging. Done well, it can provide a company with a significant as well as many of the world's most respected brands, including competitive advantage. Our innovative solutions and superior risk Harley-Davidson, Kimberly-Clark, Lowe's, Raytheon, and others.

management help customers effectively manage their unique energy Since 2001, we've provided Raytheon with energy and energy-needs so they can focus on what matters most to them-running their related services at its facilities in Maryland and Massachusetts. Energy businesses successfuly). is central to its core business-developing some of the most advanced We serve as an intermediary between suppliers and consumers defense technologies in the world. Using those technologies is the of energy. We help producers manage the risk associated with selling DDG 1000 (pictured left), the country's newest naval destroyer.

their output, and we help businesses manage the price risk associ- Raytheon's Integrated Defense Systems business is designing the ated with buying it. Our pricing is competitive, and our specialized electronic and combat systems for this revolutionary warship, which energy-management products, services, and resources help customers is scheduled to be delivered to the U.S. Navy in 2012.

achieve cost-effective solutions. By going beyond excellent customer care, we become a true We've built North America's leading retail and wholesale com- extension of our customers' energy procurement functions. According petitive energy businesses by being the best at what we do. Our to a recent independent study, 94 percent of our commercial and broad scale, extensive industry knowledge, superior customer service, industrial customers said they were happy they chose us and Would and disciplined risk management make us the provider of choice for choose us again, and 93 percent said they would recommend us to intensive energy users. others. That tells Lis we're doing it right.

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, ltdlýý, %,J I _d4-Cr 1,k_1L U t 111 KEVIN HADLOCK Vice President, Investor Relations DELIVERING VALUE.

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 MANAGING OUR BUSINESS WITH DISCIPLINE We're proud of the value we create for our shareholders. In 2006, our We're taking the right steps to support our future growth. The profit-adjusted earnings per share were a record $3.61 -a 25 percent increase able sale of our gas-fired generation plants has enabled us to further over 2005. Including stock price appreciation and dividends, our strengthen our already strong balance sheet. We used a portion of the total shareholder return for 2006 was nearly 23 percent. proceeds to repay approximately $700 million of debt that matured A $100 investment made in our company on December 31,2001, in early 2007. The remaining proceeds give us available capital to with dividends reinvested, was worth $299.56 on December 31,2006. redeploy in smart investments in competitive supply, power genera-Over the same time, a $100 investment in the S&P 500 was worth tion, and transmission and distribution.

$135.02, and a $100 investment in the S&P 500 Electric Utilities We also continue to focus on implementing productivity initiatives Index was worth $193.06. that result in permanent savings. Since we began our productivity push We've achieved this success by remaining sharply focused on in 2003, we've achieved pre-tax cost savings that add $97 million delivering results and consistently executing our business plan. We've annually to our bottom line. The productivity gains resulted from gained market share, increased productivity, made wise investments, streamlining our processes and increasing the output of 0ur generat-and improved return on invested capital. ing plants. During 2006, we optimized our nuclear workforce and Our successful track record makes us optimistic about our increased our generating capacity by 17 percent at our R.E. Ginna future-we believe our compound annual earnings growth will range Nuclear Power Plant, laying the groundwork to achieve our 2007 from 22 percent to 26 percent from 2005 to 2008. 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 renewa . e enei Pictured left to right: Nine Mile Point Nuclear Station, Pinedale Anticline gas producing property, and Soda Lake Geothermal Power Plant LEVERAGING WHAT WE'VE BUILT POWERING THE FUTURE Over the last five years, we've built one of the industry's top-performing Through UniStar Nuclear-our joint enterprise with AREVA-we're wholesale and retail energy supply, risk management, and generation at the forefront of next-generation nuclear power. UniStar provides a businesses. We did it by honing our core capabilities, focusing on strong business framework for the development and deployment of advanced, customer relationships, and improving productivity. standardized nuclear power plants. With the cost benefits and proven Now we're realigning these successful businesses to further inte- safe performance that come from having a standardized design, this grate our merchant organization, enabling us to better leverage our approach can help meet our nation's growing demand for electricity scale, expertise, and technology. This realignment provides us with with emission-free power.

opportunities to improve our operating efficiency and drive long- We're also exploring innovative ways to expand out use of green term growth, and we're going after both. energy options to meet our customers' growing demands for clean We're also applying our experience and industry knowledge to power. More than 60 percent of our generating output is comprised grow our natural gas business. In 2006, we completed a successful of sources that produce zero emissions, including hydro, geothermal, IPO of Constellation Energy Partners LLC, a company focused on nuclear, and solar. Over the next few years, we'll be looking at adding the acquisition, development, and exploitation of oil and natural gas wind and other renewable sources to our portfolio.

properties. The proceeds from the IPO provide us with capital to At BGE, we're implementing demand response and advanced invest in natural gas production when we see attractive opportunities metering technology pilot programs that could eventually provide our that fit with our strategy. 1.2 million electric and 640,000 natural gas customers with information Leveraging our scale to invest in high-quality generation assets to better manage when and how they use energy. This is an important and managing them to achieve optimal returns are things we've done step in encouraging energy conservation, helping customers deal with well and will continue to do. 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 IMPROVING THE QUALITY OF LIFE FOR ALL In 2006, we donated nearly $12 million to organizations working to Our efforts center on enhancing the quality of life for all. Our sup-improve the quality of life in our communities. But our goal is to do port for the environment includes substantial investment in the lat-more than contribute financially. Our strategy is to drive meaningful, est environmental equipment at our plants and ongoing support for long-term change for the better. leading ecological preservation and restoration organizations.

We make it a priority to give of ourselves. Our leaders serve on We support economic-development related organizations, and charitable and educational boards and foundations. Our employees we're the title sponsor for the Constellation Energy Classic. In addi-volunteer through our company-wide Power of Caring program, and tion to raising $2.2 million for Maryland-based non-profits, this also serve as coaches, mentors, and leaders for more than 300 non- PGA TOUR Champions Tour golf tournament has generated a sig-profit organizations. We constantly measure the progress and effec- nificant economic impact for Maryland.

tiveness of our community programs and support. As a community While our community involvement touches the lives of people leader-and as a leader in business-we must constantly innovate and from many walks of life, a significant focus is helping disadvantaged drive for results. youth realize their potential and achieve their dreams. We accomplish To achieve maximum results, we concentrate on four key seg- this through our support of the Living Classrooms Foundation, Big ments related to the energy business and the needs of the communi- Brothers Big Sisters, and other well respected organizations.

ties we serve. These include education, the environment, economic We know that the rising cost of energy creates a serious strain for development, and energy assistance for those less fortunate. many families we serve and have committed $26 million to provide Each month, through our sponsorship of the b4students Foundation, the neediest with financial support and energy conservation pro-a group of high school students from the Baltimore City Public grams. The BGE Crisis Assistance Fund makes grants available to the School system visits our headquarters as part of a long-term mentor- Fuel Fund of Maryland, the Salvation Army, and other non-profit ing program with our employees. We're very proud of our ongoing organizations. Our goal is to help meet immediate energy assistance sponsorship of this effort because it illustrates the philosophy behind needs and promote self-reliance.

our support of innovative education programs, which also includes Our company has a 190-year tradition of substantial community the CollegeBound Foundation, Fund for Educational Excellence, support, and it's a responsibility we take very seriously. We're proud Junior Achievement, Maryland Mentoring Partnership, and Teach of the generosity shown by our nearly 9,700 employees. As a com-for America. Our efforts encourage students to graduate from high pany and as individuals, we're determined to do what's right and to school and college to prepare for their future. 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 2 2 Moved up to No. 125 on the FORTUNE 500 list

• Received a 2006 EPA C P 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 Renewable & Alternative - 4%

~Coal, Gas Nuclear & Oil -35%

- 61%

OPERATING A STRATEGIC GENERATION FLEET (Fcludes gas-firod planussold 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 Providing customer-centric, energy-focused solutions for Residential and small commercial customers in Maryland A competitive provider of energy-related products heating, air conditioning, plumbing, electrical, and indoor and services air quality needs, as well as window replacements and the sale of natural gas to the residential market 13

BOARD OF DIRECTORS MAYO A. SHATTUCK III YVES C. DE BALMANN DOUGLAS L. BECKER Chairman, President,and CEO Co-Chairman Chairmanand CEO Constellation Energy Bregal Investments LP Laureate Education, Inc.

Director since 1999 Director since 2003 Director since 1998 Age 52 Age 60 Age 41 JAMES T. BRADY EDWARD A. CROOKE JAMES R. CURTISS, ESQ.

ManagingDirector, Mlid-Atlantic Retired Vice Chairman Partner Ballantrae International, Ltd. Constellation Energy Winston & Strawn LLP Director since 1999 Director since 1988 Director since 1994 Age 66 Age 68 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 NANCY LAMPTON ROBERT J. lAWI.ESS President Chairmanand CEO Chairmanand CEO University of Maryland, Baltimore County American Life and Accident Insurance McCormick & Company, Inc.

Director since 1994 Company of Kentucky and Hardscuffle, Inc. Director since 2002 Age 56 Director since 1994 Age 60 Age646 LYNN M. MARTIN MICHAEL D. SULLIVAN President Chairman The Martin Hall Group LLC Life Source, Inc. and Director since 2003 ADVANCARE HealthCare, LLC Age 67 Director since 1992 Age 67 COMMITTEES OF THE BOARD Executive Committee Compensation Committee Nominating and Corporate Governance Committee Mayo A. Shattuck III, Chairman Robert J. Lawless, Chairman Michael D. Sullivan, Chairman Edward A. Crooke Douglas L. Becker Douglas L. Becker Robert J. Lawless Dr. Freeman A. Hrabowski III Dr. Freeman A. Hrabowski III Lynn M. Martin Robert J. Lawless Audit Committee Michael D. Sullivan Lynn M. Martin James']. Brady, Chairman Yves C. de Balmann Committee on Nuclear Power Edward A. Crooke James R. Curtiss, Chairman All committee menbesrs are audit cormmittee Edward A. Crooke financial experts as defined by SF.Crides. Nancy Lampton Lynn M. Martin 15

EXECUTIVE TEAM MAYO A. SHATTUCK Ilt THOMAS F. BRADY THOMAS V. BROOKS (f/,aitrraat, frident, and 1..'E Iecutive VicePreaident lceecotrce Vice Ptraidestr Mayo, 52, is the Chairman, Preident. and Chief Executive Officer itrn. 57. is resptonsible ForConstellation Newknetgy and the retail Tlrm. 44, heads the merchant organization. He is retponsible of Constellarien Energy[Prior to joining Constellation Energy, he bmuinesses, as well as corptrate strategy, mergers and acquisitions, forr tur retail and wholesale competitive energy cotmpanics and was Chairman orf the Board at Deuttsche Banc Alem. Brown. He also corptrate communications, branding, and government affairs. -le non-nuclear power generation, as well as for the strategy and served at Clobal [lead of leit-ment Banhing and Global Head of is also Chairman tof Baltimore Gas and Electric. Tom has served execution of merchant acquisitions ana dicestitures and tlte devel-Private Banking at D)eursche Bank, Vice Chairman at Bankers irtrx, as Chief Accounting Officer at Baltimtrore (as and Electric, at well at opment of non-onclear assres. Previtredy, 'Iem was Preeident and andl[esident at Alex. Brown & Sins. in a variety tf executive adtal management poitions. 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 MICHAELJ. WALLACE IRVING B. YOSKOWIT1 I&'e,rtire Vice Pridctr Chief inrancial Office, F-recttire VicePresident FeecutriveVicePresident and General C0aoe1 and O-cer QjhiefAdmitnitraatie Preident and f.'/f. fCooeellaeton EnergeyGeneration Gftrp Irv, 61. is tesponsihie for corporate governance and compliance, Follin. 47, is responsible for finance, informnaion technology human Mike, 59. is responsible for or nuclear potver generation bhsiness. mergers and acquisitions. litigation, and bhsiens nirtlegal orvincs.

resources, legal, ardit, risk management, investor relations, ard Prior to joining Constclaritoi Energy, he was Co-Founder anrd Prior to joining Constellation Energy, li served as Senior Partner business perforarrrce improvement. Prior to joining Cofnstellation Managing Director of hattiongton Energy Partrnes, 1LC. Mike also of Global 'Tecloilogy Partners, 1,C. Senior Counsel at Crowell &

Energy, Follin wasSenior Vice President and Chief Financial Officer was Chicf Nuckar Officer ard served in various ececouivepositions Moring, L,-C,and Senior Consultant at ChiarlecRiver Associates, ofAertstrong Holdings, Inc. She also has served it various financial at Unicort/ComEd. Irvalso wasF,-soctrive Vice President and General Counsel at United erecutive positions ar General Motors Corp. 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 JOHN R. COLLINS FELIXJ. DAWSON Setnior Vice President,CorporateA_#Lcirs Senior Vice President andC(eic/isk Offlcer .anior Vice Presidenr Paul, 55, is responsible for external affairs, government and John. 49, is responsiblefiarass.ssing and managing risk.He alsosenrve CAs-la-ceident and (OeGhiia'EcecutiveOfficer, regulatory relations, and environmental policy. prior to joining on the Board of Managers (if Constellation Energy Partners LIC. Canectaeltion Energ ComoaraitiesGrottp Constellarin Eoergy, Paul was Senior Vice l'residenr and Group Previously. he was Managing Director (afFinance and 'Aieasutre of Felix, 39, is responsible for wholeale energy; coartolity -rrices, Head at Ogilvy Public Relations. He also was a senior staff mem- Constellation lPower Source Holdings and Consrellation Energy and risk management for electricity, coal. natural gas, and related ber at the Natural Resources Defense Council, Prom Secretary for Conmnodities Group. lie also has served itt various leadership pose- commodiries. He also serven as Presidentanal CEO of Constellarion Senator Christopher l)Dold (l)-Coon.), and Foreign News Falitr rtons at Constellation Fnergy Cosnrtiodities Group and Baltimore Energy Partters (IC. Previously, he was Co-Chief Commercial and Eadior of Morning Edirion at National Pudlic Radio. Gas and Electric. Prirtmtojoining Baltinmre Gas and Electric, Officer, Constellation Energy Commoditie Group and served in lte hetl various financial management positions at Bell Atlantic svriottsleadership Posritonsin originationand portfolio management.

Corporation and Perdtcu Farms, Inc. lIe also hasheld a variety of positions at Goldman, Sachs& Co.

KENNETH W. DEFONTFS, JR. BETH S, PERLMAN GEORGE E. PERSKY Senior VicePreridant Senior 14cePresidentand C'rueflafttrrtetion /fficer Senior 1lce President lreaaiientand ChO. Baltimore G(as and Elctrtc leath,46. is responsible for inafow*ariontechnology initiatives that Ce-President and (7-05si E-vecrao5e(ffcer, Ken. 56, is responsible forour regulated electric and natural gas support husiness transfomationt sodenrble growtlh,Prior to joining iotelhltrion EnergyCoanoediriesGrotp distribution utility in Cental Maryland. Peviously, Kentwas Vice Constellation Energy, asiewasVice Psesidetntof Wholesale Trading Ccorge, 37, is responsible for swholesale energy,commodity services, President, Electric Tratstnission and IDistribttion, and also has fcclAhnology and served it, various athertchttolagy and operations and risk management for electricity, coal, natural gas,and relstcd served itt various executive and nataagctcnt positions at [altienore matnagemettlpositions at Eaneont. Shte also held various financial cotntodities. Poniously, he ,as Co-Chief Commercial Officer, Gas and Electric. and technoologymanagement positiets at I,ehl an Brothers, b-c.. Consaellation Energy Contrtoditias Group and served in variioma Kidder, Peabody & Co., andJPMorgan. leadership positions in origination and portfolio management, He also has held a vatietyof positions at Coldotan. Sachs & Co.

MARC L. UGOL Setior Vie I/sideat, HaamanReaeaaeeee Marc, 48. is preponsible forstaffing, organization effectivetess, labor relationa, com.pensation, and haecfits. Prior to joining Constellation Energy,laena 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 specialsection is intended to be a guide. Youeanfind more derailsaboti all these tens inou Form 10-K, which follows this special section.

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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 specialsection is intended to be a guide. Youcan find more derail abomtallthesetents in otr Form 10-K,which follows this specialsection.

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 Workforce W 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 specialsection is intended to be a guide. Youcan find more details about allthese items in our Form 10-K, which followsthis specialsecion.

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. Trhisspecialsection is intended to be a guide. Youcan find more derails about all these items in our Form 10-K, which Followsthis specialsection.

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

SHAREHOLDER INFORMATION DIVIDENDS SHAREHOLDER INVESTMENT PLAN The Board of Directors sets the record and payment dates for quar- Our Shareholder Investment Plan provides shareholders with an easy, terly dividends. In January 2007, we raised our quarterly dividend to economical way to acquire additional shares. In addition, accounts can 43.5 cents per share-a 15 percent increase over the previous quarterly be used to sell, deposit, and transfer shares. To participate, or for more dividend and equivalent to an annual dividend of $ 1.74 per share. We information, please contact our Stock Transfer Agent and Registrar.

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 E-MAIL ALERTS June 11, September 10, and December 10. Projected payment dates To automatically receive e-mail alerts about our financial informa-are July 2, October 1, and January 2. tion-including notification of SEC filings, financial reports, presen-Detailed information about our dividend policy, as well as our tations, and press releases-go to our E-mail Alerts page on the Inves-dividend payments and stock price ranges for the last two years, is tor Relations section of our Web site at www.constellation.com and available on page 27 of our 2006 Form 10-K included within this register your preferences. You can also make changes in your notifica-annual report. tion options or unsubscribe from the service.

CERTIFICATIONS FORM 10-K As required by the Sarbanes-Oxley Act of 2002, we have filed the Our 2006 Form 10-K is included as part of this annual report. Our Chief Executive Officer and Chief Financial Officer certifications in 2006 Form 10-K and our other SEC filings are available on our Web our 2006 Form 10-K. Additionally, our Chief Executive Officer pro- site at www.constellation.com. We will also provide additional cop-vided an annual certification in December 2006 with respect to our ies upon request. Send requests to Constellation Energy Shareholder compliance with the New York Stock Exchange corporate governance Services, 750 East Pratt Street, Baltimore, MD 21202.

listing standards.

STOCK TRADING INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM Constellation Energy common stock trades under the ticker symbol PricewaterhouseCoopers LLP CEG on the New York and Chicago stock exchanges.

STOCK TRANSFER AGENT AND REGISTRAR FORWARD-LOOKING STATEMENTS American Stock Transfer & Trust Company We make statements in this annual report that are considered forward-Shareholder Services looking within the meaning of the Securities and Exchange Act 59 Maiden Lane of 1934. These statements are not guarantees of our future results New York, NY 10038 and are subject to risks, uncertainties, and other important factors-(800) 258-0499 including those in the Forward-Looking Statements and Risk Factors www.amstock.com sections of our 2006 Form 10-K included within this annual report-that could cause our actual results to differ.

SHAREHOLDER ASSISTANCE For general inquiries, or for assistance with lost or stolen stock certifi- @ This report was printed on recycled paper.

cates or dividend checks, name or address changes, stock transfers, or the Shareholder Investment Plan, please contact our Stock Transfer Agent and Registrar.

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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. YeslHI 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

• the effectiveness of Constellation Energy's and We make statements in this report that are considered BGE's risk management policies and procedures forward looking statements within the meaning of the and the ability and willingness of our Securities Exchange Act of 1934. Sometimes these counterparries to satisfy their financial and statements will contain words such as "believes," performance commitments, "1anticipates," "expects," "in tends," "Plans," and other

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

• the timing and extent of changes in commodity beyond our control, prices and volatilities for energy and energy

• the actual outcome of uncertainties associated related products including coal, natural gas, oil, with assumptions and estimates using judgment electricity, nuclear fuel, freight, and emission when applying critical accounting policies and allowances, preparing financial statements, including factors

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

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

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

• the timing and extent of deregulation of, and

• changes in accounting principles or practices, competition in, the energy markets, and the

• losses on the sale or write down of assets due to rules and regulations adopted on a transitional impairment events or changes in management basis in those markets, intent with regard to either holding or selling

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

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

• regulatory or legislative developments that affect and deregulation, transmission or distribution rates

• cost and other effects of legal and administrative and revenues, demand for energy, or increases in proceedings that may not be covered by costs, including costs related to nuclear power insurance, including environmental liabilities.

plants, safety, or environmental compliance, Given these uncertainties, you should nor place

• the inability of Baltimore Gas and Electric undue reliance on these forward looking statements.

Company (BGE) to recover all its costs Please see the other sections of this report and our other associated with providing customers service, periodic reports filed with the Securities and Exchange

• the conditions of the capital markets, interest Commission (SEC) for more information on these rates, availability of credit, liquidity, and general factors. These forward looking statements represent our economic conditions, as well as Constellation estimates and assumptions only as of the date of this Energy Group's (Constellation Energy) and report.

BGE's ability to maintain their current credit Changes may occur after that date, and neither ratings, Constellation Energy nor BGE assume responsibility to update these forward looking statements.

1

PART I On October 24, 2006, Constellation Energy and Item 1. Business FPL Group, Inc. (FPL Group) agreed to terminate the Agreement and Plan of Merger the parties entered into Overview on December 18, 2005. For additional information Constellation Energy is an energy company that related to the merger termination, see Note 15 to includes a merchant energy business and BGE, a ConsolidatedFinancialStatements. For a discussion of regulated electric and gas public utility in central other recent events that have impacted us, our strategy, Maryland. and the seasonality of our business, please refer to Item 7.

Constellation Energy was incorporated in Management's Discussion andAnalysis section.

Maryland on September 25, 1995. On April 30, 1999, Constellation Energy maintains a website at Constellation Energy became the holding company for constellation.corn where copies of our annual reports on BGE and its subsidiaries. References in this report to Form 10-K, quarterly reports on Form 10-Q, current "we" and "our" are to Constellation Energy and its reports on Form 8-K, and any amendments may be subsidiaries, collectively. References in this report to the obtained free of charge. These reports are posted on our "regulated business(es)" are to BGE. website the same day they are filed with the SEC. The Our merchant energy business is a competitive SEC maintains a website (sec.gov), where copies of our provider of energy solutions for a variety of customers. It filings may be obtained free of charge. The website has electric generation assets located in various regions address for BGE is bge.com. These website addresses are of the United States and provides energy solutions to inactive textual references, and the contents of these meet customers' needs. Our merchant energy business websites are not part of this Form 10-K.

focuses on serving the energy and capacity requirements In addition, the website for Constellation Energy (load-serving) of, and providing other energy products includes copies of our Corporate Governance and risk management services, for various customers. Guidelines, Principles of Business Integrity, Corporate Our merchant energy business includes: Compliance Program and Insider Trading Policy, and

+ a generation operation that owns, operates, and the charters of the Audit, Compensation and maintains fossil, nuclear, and hydroelectric Nominating, and Corporate Governance Committees of generating facilities and holds interests in the Board of Directors. Copies of each of these qualifying facilities, fuel processing facilities and documents may be printed from our website or may be power projects in the United States, obtained from Constellation Energy upon written

+ a wholesale marketing, risk management, and request to the Corporate Secretary.

trading operation that primarily provides energy The Principles of Business Integrity is a code of products and services to distribution utilities, ethics that applies to all of our directors, officers, and power generators, and other wholesale employees, including the chief executive officer, chief customers, financial officer, and chief accounting officer. We will

+ an electric and natural gas retail operation that post any amendments to, or waivers from, the Principles provides energy products and services to of Business Integrity applicable to our chief executive commercial, industrial, and governmental officer, chief financial officer, or chief accounting officer customers, and on our website.

+ a generation operations and maintenance services operation.

Operating Segments BGE is a regulated electric transmission and The percentages of revenues, net income, and assets distribution utility company and a regulated gas attributable to our operating segments are shown in the distribution utility company with a service territory that tables below. We present information about our covers the City of Baltimore and all or part often operating segments, including certain other items, in counties in central Maryland. BGE was incorporated in Note 3 to ConsolidatedFinancialStatements.

Maryland in 1906.

Unaffiliated Revenues Our other nonregulated businesses:

Merchant Regulated Regulated Other

• design, construct, and operate heating, cooling, Energy Electric Gas Nonregulated and cogeneration facilities, and provide various 2006 83% 11% 5% 1%

energy-related services, including energy 2005 81 12 6 1 consulting, for commercial, industrial, and 2004 76 16 6 2 governmental customers throughout North Net Income America, and Merchant Regulated Regulated Other

• provide home improvements, service heating, Energy Electric Gas Nonregulated air conditioning, plumbing, electrical, and 2006 77% 16% 5% 2%

indoor air quality systems, and provide natural 2005 67 28 5 -

gas to residential customers in central Maryland. 2004 72 26 5 (3) 2

Total Assets

• managed approximately 8,680 MW of Merchant Reulated Regulated Other Energy aectric Gas Nonregulated generation capacity as of December 31, 2006.

2006 75% 17% 6% 2% We analyze the results of our merchant energy 2005 77 16 6 1 business as follows:

2004 71 20 7 2

• Mid-Atlantic Region--our fossil, nuclear, and hydroelectric generating facilities and Certain prior-yearamounts have been reclassifiedto load-serving activities in the PJM conform with the currentyear's presentation.

Interconnection (PJM) region. This also (1) Excludes incomefrom discontinuedoperationsin includes active portfolio management of 2006,2005 and 2004 and cumulative effects of generating assets and other physical and changes in accountingprinciples in 2005 as discussed financial contractual arrangements, as well as in more detail in Item 8. FinancialStatements and other PJM competitive supply activities. In Supplementary Data. addition, due to the expiration of its power Merchant Energy Business purchase agreement, beginning in June 2006 Introduction until its sale in December 2006, the results of Our merchant energy business integrates electric our University Park generating facility are generation assets with the marketing and risk included with the Mid-Atlantic Region.

management of energy and energy-related commodities, University Park was previously included in allowing us to manage energy price risk over geographic Plants with Power Purchase Agreements.

regions and time.

• Plants with Power Purchase Agreements-our Constellation Energy Commodities Group, our generating facilities outside the Mid-Atlantic wholesale marketing, risk management, and trading Region with long-term power purchase operation, dispatches the energy from our generating agreements. As discussed in Note 2 to facilities and from some facilities with which we have ConsolidatedFinancialStatements, the sale of the power purchase agreements, manages the risks associated High Desert facility resulted in a reclassification with selling the output and purchasing non-nuclear of its results to discontinued operations.

fuels, and enters into transactions to meet customers'

• Wholesale Competitive Supply-our energy and risk management requirements. This marketing, risk management, and trading operation also trades energy and energy-related operation that provides energy products and commodities and deploys risk capital in the services primarily to distribution utilities, power management of our portfolio in order to earn additional generators, and other wholesale customers. We returns. Constellation NewEnergy, our electric and gas also provide global energy and related services retail operation, provides electricity, natural gas, and upstream and downstream natural gas transportation, and other energy services to commercial, services.

industrial, and governmental customers.

• Retail Competitive Supply--our operation that Constellation Generation Group, our merchant provides electric and natural gas energy products generation operation, oversees the ownership, and services to commercial, industrial, and operations, maintenance, and performance of our fossil, governmental customers.

nuclear and renewable generation and fuel processing

• Other-our investments in qualifying facilities facilities. Our generation capacity supports our and domestic power projects and our generation wholesale and retail operations by providing a source of operations and maintenance services.

reliable power supply. Constellation Generation Group In December 2006, we completed the sale of the also owns and operates a generation operations and following gas-fired plants owned by our merchant maintenance services organization. energy business:

Our merchant energy business:

• provided approximately 34,650 megawatts Capacity Facility (MW) Unit Type Location (MW) of peak load in the aggregate to distribution utilities, municipalities, High Desert... 830 Combined Cycle California commercial, industrial, and governmental Rio Nogales... 800 Combined Cycle Texas customers during 2006, Holland ...... 665 Combined Cycle Illinois

• provided approximately 355,000 million British University Park 300 Peaking Illinois Thermal Units (mmBTUs) of natural gas to Big Sandy .... 300 Peaking West Virginia commercial, industrial, and governmental Wolf Hills .... 250 Peaking Virginia 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 3

We discuss the sale of these gas-fired generating predetermined price is compared to the market price for facilities in Note 2 to ConsolidatedFinancialStatements. electricity. If the market price exceeds the strike price, We present details about our generating properties then 80% of this excess amount is shared with the in Item 2. Properties. former owners of the plant. The average strike price for the first year of the revenue sharing agreement is $40.75 Mid-Atlantic Region per MvWH. The strike price increases two percent We own 6,305 MW of fossil, nuclear, and hydroelectric annually beginning in the second year of the revenue generation capacity in the Mid-Atlantic Region. The sharing agreement. The revenue sharing agreement is output of these plants is managed by our wholesale unit contingent and is based on the operation of the marketing, risk management, and trading operation and unit.

is hedged through a combination of power sales to We exclusively operate Unit 2 under an operating wholesale and retail market participants. Our merchant agreement with the Long Island Power Authority. The energy business meets the load-serving requirements of Long Island Power Authority is responsible for 18% of various contracts using the output from the the operating costs (and decommissioning costs) of Unit Mid-Atlantic Region and from purchases in the 2 and has representation on the Nine Mile Point Unit 2 wholesale market. management committee which provides certain BGE transferred all of these facilities to our oversight and review functions.

merchant energy generation subsidiaries on July 1, 2000 In October 2006, we received Nuclear Regulatory as a result of the implementation of electric customer Commission (NRC) approval for license extension for choice and competition among suppliers in Maryland, both units at our Nine Mile Point nuclear facility. With except for the Handsome Lake facility that commenced the renewed licenses, we can continue to operate Unit 1 operations in mid-2001. The assets transferred from until 2029 and Unit 2 until 2046.

BGE are subject to the lien of BGE's mortgage. We own 100% of the Ginna nuclear facility.

Our merchant energy business supplies BGE with Ginna consists of a 581 MW reactor that entered service a portion of its market-based standard offer service in 1970 and is licensed to operate until 2029. We sell up obligation. For 2006, the peak load supplied to BGE to 90% of the plant's output and capacity to the former was approximately 3,490 MW. owners for 10 years at an average price of $44.00 per MWH under a long term unit contingent power Plants with Power Purchase Agreements purchase agreement. The remaining output is managed We own 2,134 MW of nuclear generation capacity with by our wholesale marketing, risk management, and power purchase agreements for a significant portion of trading operation and sold into the wholesale market.

their output. Our facilities with power purchase During the fourth quarter of 2006, we completed a agreements are the Nine Mile Point Nuclear Station planned outage at our Ginna nuclear facility, which (Nine Mile Point) and the R.E. Ginna Nuclear Plant included increasing the capacity of the plant from 498 (Ginna). MW to the current 581 MW. Based on the new We own 100% of Nine Mile Point Unit 1 capacity, beginning in 2007, we will sell approximately (620 MW) and 82% of Unit 2 (933 MW). The 80% of Ginna's output to the former owners.

remaining interest in Nine Mile Point Unit 2 is owned by the Long Island Power Authority. Unit 1 entered Competitive Supply service in 1969 and Unit 2 in 1988. Nine Mile Point is We are a leading supplier of energy products and located within the New York Independent System services to wholesale customers and retail commercial, Operator (NYISO) region. industrial, and governmental customers. In 2006, our We sell 90% of our share of Nine Mile Point's wholesale marketing, risk management, and trading output to the former owners of the plant at an average operation provided approximately 17,950 peak MWs of price of nearly $35 per megawatt-hour (MWH) under wholesale full requirements load-serving products.

agreements that terminate between 2009 and 2011. The During 2006, our retail competitive supply activities agreements are unit contingent (if the output is not served approximately 16,700 MW of peak load and available because the plant is not operating, there is no approximately 355,000 mmBTUs of natural gas.

requirement to provide output from other sources). The remaining 10% of Nine Mile Point's output is managed Wholesale and RetailLoad-ServingActiities by our wholesale marketing, risk management, and Our wholesale marketing, risk management, and trading trading operation and sold into the wholesale market. operation structures transactions that serve the full After termination of the power purchase energy and capacity requirements of various customers agreements, a revenue sharing agreement with the outside the PJM region such as distribution utilities, former owners of the plant will begin and continue municipalities, cooperatives, and retail aggregators that through 2021. Under this agreement, which applies do not own sufficient generating capacity or in-house only to our ownership percentage of Unit 2, a supply functions to meet their own load requirements.

4

Our retail competitive supply operation structures a material impact on our financial results. We discuss transactions to supply full energy and capacity the impact of our trading activities and value at risk in requirements and provide natural gas, transportation, more detail in Item 7. Management's Discussion and and other energy products and services to retail, Analysis.

commercial, industrial, and governmental customers. These activities involve the use of a variety of Contracts with these customers generally extend instruments, including:

from one to ten years, but some can be longer. To meet

• forward contracts (which commit us to purchase our customers' load-serving requirements, our merchant or sell energy commodities in the future),

energy business obtains energy from various sources,

• swap agreements (which require payments to or including: from counterparties based upon the difference

• bilateral power and natural gas purchase between two prices for a predetermined agreements with third parties, contractual (notional) quantity),

• unit contingent purchases from generation

• option contracts (which convey the right to buy companies, or sell a commodity, financial instrument, or

• our generation assets, index at a predetermined price), and

• regional power pools,

• futures contracts (which are exchange traded

• tolling contracts with generation companies, standardized commitments to purchase or sell a which provide us the right, but not the commodity or financial instrument, or make a obligation, to purchase power at a price linked cash settlement, at a specified price and future to the variable cost of production, including date).

fuel, with terms that generally extend from Active portfolio management allows our wholesale several months to several years, but can be marketing, risk management, and trading operation to:

longer, and

• manage and hedge its fixed-price energy

+ exchange traded electricity and natural gas purchase and sale commitments, contracts.

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

• reduce exposure to the volatility of market We continue to identify and pursue opportunities which Prices, and can generate additional returns through portfolio

• hedge fuel requirements at our non-nuclear management and trading activities within our business. generation facilities.

These opportunities have increased due to the significant growth in scale of our competitive supply Coal and International Services operations. In managing our portfolio, we may Our wholesale marketing, risk management, and trading terminate, restructure, or acquire contracts. Such operation participates in global coal sourcing activities transactions are within the normal course of managing by providing coal and coal-related logistical services, for our portfolio and may materially impact the timing of the variable or fixed supply needs of global customers. In our recognition of revenues, fuel and purchased energy 2006, we delivered 26.0 million tons of c~oal to global expenses, and cash flows. customers and to our own fleet. Additionally, we Our wholesale marketing, risk management, and entered into power, natural gas, freight, and emissions trading operation actively uses energy and energy-related transactions outside of the United States. We also commodities in order to manage our portfolio of energy include in our coal services the results from our purchases and sales to customers through structured synthetic fuel processing facility in South Carolina.

transactions. We use both derivative and nonderivative We will continue to evaluate new international contracts in managing our portfolio of energy sales and opportunities, including expanding our coal sourcing, purchase contracts. Generally, we expect to use both freight, and power, natural gas and emissions activities derivative and nonderivative contracts to hedge a outside of the United States.

majority of our portfolio over a three-year period in order to reduce volatility in our results. Although a Natural Gas Services substantial portion of our portfolio is hedged, we are Our wholesale marketing, risk management, and trading able to identify opportunities to deploy risk capital to operation includes upstream (exploration and increase the value of our accrual positions, which we production) and downstream (transportation and characterize as portfolio management. storage) natural gas operations. Our upstream activities We trade energy and energy-related commodities include the acquisition, development, and exploitation and deploy risk capital in the management of our of natural gas properties. Our downstream activities portfolio in order to earn additional returns. These include providing natural gas to various customers, activities are managed through daily value at risk and including large utilities, industrial customers, power stop loss limits and liquidity guidelines, and could have generators, wholesale marketers, and retail aggregators.

5

In 2006 and 2005, we acquired working interests Fuel Sources in gas producing fields. We discuss these acquisitions in Our power plants use diverse fuel sources. Our fuel mix more detail in Note 15 to ConsolidatedFinancial based on capacity owned at December 31, 2006 and our Statements. generation based on actual output by fuel type in 2006 In November 2006, we completed the initial were as follows:

public offering of Constellation Energy Partners LLC Fuel Capacity Owned Generation*

(CEP), a limited liability company that we formed. CEP Nuclear .......... 45% 52%

is principally engaged in the acquisition, development, Coal ............ 32 30 and exploitation of natural gas properties. CEP's existing Natural Gas ...... 7 15 property is located in the Robinson's Bend Field in the 8 -

O il .............

Black Warrior Basin of Alabama. We continue to own Renewable and 54% of CEP and as a result, we continue to consolidate Alternative ') ... 5 3 CEP. We discuss the impact of this initial public Dual * . . . . . . . . . . 3 offering on our financial results in more detail in Note 2

• Includes outputfrom gas-firedplantsuntil sale in to ConsolidatedFinancialStatements.

December 2006 (1) Includes solar, geothermal,hydro, waste coal and Other biomass.

We hold up to a 50% voting interest in 24 operating (2) Switches between naturalgas and oil.

energy projects that consist of electric generation (primarily relying on alternative fuel sources), fuel We discuss our risks associated with fuel in more processing, or fuel handling facilities. These generating detail in Item 7. Managements Discussion and projects are considered qualifying facilities under the Analysis-Market Risk.

Public Utility Regulatory Policies Act of 1978. Each electric generating plant sells its output to a local utility Nuclear under long-term contracts. The output at our nuclear facilities over the past five We also provide operation and maintenance years (including periods prior to our acquisition of services, including testing and start-up, to owners of Ginna in June 2004) is presented in the following table:

electric generating facilities.

Calvert Cliffs Nine Mile Point Ginna Capacity Capacity Capacity UniStar Nuclear MWH Factor MWVH* Factor MWH Factor In 2005, we formed UniStar Nuclear, LLC (UniStar), a (MWH in millions) joint enterprise with AREVA NP, Inc., to develop the 2006 13.8 90% 12.8 93% 4.1 93%

business model for a standardized fleet of nuclear power 2005 14.7 97 12.7 93 4.0 93 plants based on an advanced design called the U.S. 2004 14.5 96 12.1 89 4.3 100 Evolutionary Power Reactor (U.S. EPR). UniStar 2003 13.7 93 12.2 90 3.9 90 2002 12.1 82 11.7 87 3.8 89 provides the framework through which we can work

• represents ourproportionateownership interest with AREVA NP, Inc. to obtain design certification and all necessary approvals from the NRC to license, The supply of fuel for nuclear generating stations construct, own, and operate U.S. EPR plants. includes the:

UniStar also offers the business framework that

• purchase of uranium (concentrates and uranium could enable the development of future joint ventures hexafluoride),

with Constellation Energy, other energy companies, and

• conversion of uranium concentrates to uranium interested parties. Those future joint ventures, in turn, hexafluoride, would license, construct, own, and operate nuclear

• enrichment of uranium hexafluoride, and power plants as part of a standardized fleet. However,

• fabrication of nuclear fuel assemblies.

prior to identifying specific projects or committing to ordering new nuclear power plants, our financial Uranium and We have commitments for sufficient commitment will be limited to the formation of the Conversion quantities of uranium (concentrates business platform and business development activities, and uranium hexafluoride) to meet including licensing and permit activities and securing 100% of our total requirements access to long-lead materials such as heavy forgings through 2010. Additionally, we have needed for reactor pressure vessels and steam generators commitments covering approximately or turbine and generator parts. 95% of our requirements in 2011.

6

Enrichment We have commitments that provide In connection with our purchase of Ginna, all of 100% of our uranium enrichment the former owner's rights and obligations related to requirements through 2010 and 75% recovery of damages for DOE's failure to meet its of these requirements in 2011 and contractual obligations were assigned to us. However, 2012. We have commitments that we have an obligation to reimburse the former owner for provide 50% of our uranium up to $10 million of any recovered damages for such claims.

enrichment requirements from 2013 through 2020. Storafe ofSpent Nuclear Fuel-On-Site Facilities Fuel Assembly We have commitments for the Calvert Cliffs has a license from the NRC to operate an Fabrication fabrication of fuel assemblies for on-site independent spent fuel storage installation that reloads required through 2013 for expires in 2012. We have storage capacity at Calvert Nine Mile Point and Calvert Cliffs Cliffs that will accommodate spent fuel from operations Nuclear Power Plant, Inc. (Calvert through 2011. In addition, we can expand our Cliffs), and through 2017 for Ginna. temporary storage capacity at Calvert Cliffs to meet future requirements until approximately 2025. Nine The nuclear fuel markets are competitive, and Mile Point and Ginna are beginning initial planning although prices for uranium and conversion are studies for the potential development of independent increasing, we do not anticipate any significant spent fuel storage capacity. Nine Mile Point's Unit 1 has problems in meeting our future requirements. sufficient storage capacity within the plant until 2011.

Nine Mile Point's Unit 2 has sufficient storage capacity Storage of Spent Nuclear Fuel-FederalFacilities within the plant until 2012. Ginna has sufficient storage One of the issues associated with the operation and capacity within the plant until 2010.

decommissioning of nuclear generating facilities is Costfor Decommissioning Uranium Enrichment Facilities disposal of spent nuclear fuel. There are no facilities for The Energy Policy Act of 1992 requires domestic the reprocessing or permanent disposal of spent nuclear nuclear utilities to contribute to a fund for fuel currently in operation in the United States, and the decommissioning and decontaminating uranium NRC has not licensed any such facilities. The Nuclear enrichment facilities that had been operated by DOE.

Waste Policy Act of 1982 (NWPA) required the federal These contributions are generally payable over a 15-year government, through the Department of Energy period with escalation for inflation and are based upon (DOE), to develop a repository for the disposal of spent the amount of uranium enriched by DOE for each nuclear fuel and high-level radioactive waste. utility through 1992. The 1992 Act provides that these As required by the NWPA, we are a party to costs are recoverable through utility service rates. BGE is solely responsible for these costs as they relate to Calvert contracts with the DOE to provide for disposal of spent nuclear fuel from our nuclear generating plants. The Cliffs and made the last payment in 2006. The sellers of the Nine Mile Point plant and the Long Island Power NWPA and our contracts with the DOE require Authority are responsible for the costs relating to the payments to the DOE of one tenth of one cent (one Nine Mile Point plant. The seller of Ginna is mill) per kilowatt hour on nuclear electricity generated responsible for the costs related to that facility.

and sold to pay for the cost of long-term nuclear fuel storage and disposal. We continue to pay those fees into Cost for Decommissionin' We are obligated to decommission our nuclear plants at the DOE's Nuclear Waste Fund for our Calvert Cliffs, the time these plants cease operation. Every two years, Ginna, and Nine Mile Point facilities. The NWPA and the NRC requires us to demonstrate reasonable our contracts with the DOE required the DOE to begin assurance that funds will be available to decommission taking possession of spent nuclear fuel generated by the sites. When BGE transferred all of its nuclear nuclear generating units no later than January 31, 1998. generating assets to our merchant energy business, it also The DOE has stated that it may not meet that transferred the trust fund established to pay for obligation until 2017 at the earliest. This delay has decommissioning Calvert Cliffs. At December 31, 2006, required that we undertake additional actions to provide the Calvert Cliffs trust fund assets were $420.6 million.

on-site fuel storage at Calvert Cliffs, Ginna, and Nine Under the Maryland Public Service Commission's Mile Point, including the installation of on-site dry fuel (Maryland PSC) order regarding the deregulation of storage capacity at Calvert Cliffs, as described in more electric generation, BGE ratepayers must pay a total of detail below. In 2004, complaints were filed against the $520 million, in 1993 dollars adjusted for inflation, to federal government in the United States Court of decommission Calvert Cliffs through fixed annual Federal Claims seeking to recover damages caused by the collections. In 2006, BGE received approval from the DOE's failure to meet its contractual obligation to begin Maryland PSC to continue annual customer collections disposing of spent nuclear fuel by January 31, 1998. of approximately $18.7 million through December 31, These cases are currently stayed, pending litigation in 2016. BGE will be required to submit a filing to other related cases. determine the level of customer contributions after December 31, 2016.

7

BGE is collecting this amount on behalf of Calvert Coal deliveries to these facilities are made by rail Cliffs. Any costs to decommission Calvert Cliffs in and barge. Over the past few years, we expanded our excess of this $520 million must be paid by Calvert coal sources including restructuring our rail contracts, Cliffs. If BGE ratepayers have paid more than this increasing the range of coals we can consume, adding amount at the time of decommissioning, Calvert Cliffs synthetic fuel as an alternate source, and finding must refund the excess. If the cost to decommission potential other coal supply sources including shipments Calvert Cliffs is less than the $520 million BGE's from various international sources. While we primarily ratepayers are obligated to pay, Calvert Cliffs may keep use coal produced from mines located in central and the difference. northern Appalachia, we are capable of switching to As discussed in Baltimore Gas and Electric imported coals to manage our coal supply. The timely Company--Provider ofLast Resort section, Senate Bill 1, delivery of coal together with the maintenance of which was enacted in June 2006, requires BGE to appropriate levels of inventory is necessary to allow for provide credits to residential electric customers equal to continued, reliable generation from these facilities.

the amount collected for decommissioning annually for All of the Conemaugh and Keystone plants' annual 10 years beginning January 1, 2007. Under the coal requirements are purchased by the plant operators provisions of Senate Bill I we are required to apply the from regional suppliers on the open market. The sulfur collection of the nuclear decommissioning trust funds restrictions on coal are approximately 2.3% for the over the ten year period beginning January 1, 2007 Keystone plant and approximately 5.3% for the toward the fulfillment of the decommissioning Conemaugh plant.

obligations of BGE ratepayers. The annual coal requirements for the ACE, The sellers of Nine Mile Point transferred a Jasmin, and Poso plants, which are located in California,

$441.7 million decommissioning trust fund to us at the are supplied under contracts with mining operators. The time of sale. In return, we assumed all liability for the Jasmin and Poso plants are restricted to coal with sulfur costs to decommission Unit 1 and 82% of the costs to content less than 4.0% and ACE is restricted to less than decommission Unit 2. We believe that this amount is 2.0%.

adequate to cover our responsibility for All of our coal requirements reflect historical levels.

decommissioning Nine Mile Point to a greenfield status The actual fuel quantities required can vary substantially (restoration of the site so that it substantially matches from historical levels depending upon the relationship the natural state of the surrounding properties and the between energy prices and fuel costs, weather site's intended use). At December 31, 2006, the Nine conditions, and operating requirements.

Mile Point trust fund assets were $572.8 million.

The seller of Ginna transferred $200.8 million in Gas decommissioning funds to us. In return, we assumed all We purchase natural gas, storage capacity, and liability for the costs to decommission the unit. We transportation, as necessary, for electric generation at believe that this amount will be sufficient to cover our certain plants. Some of our gas-fired units can use responsibility for decommissioning Ginna to a residual fuel oil or distillates instead of gas. Gas is greenfield status. At December 31, 2006, the Ginna purchased under contracts with suppliers on the spot trust fund assets were $246.7 million. market and forward markets, including financial Coal exchanges and bilateral agreements. The actual fuel We purchase the majority of our coal for electric quantities required can vary substantially from year to generation under supply contracts with mining year depending upon the relationship between energy operators, and we acquire the remainder in the spot or prices and fuel costs, weather conditions, and operating forward coal markets. We believe that we will be able to requirements. However, we believe that we will be able renew supply contracts as they expire or enter into to obtain adequate quantities of gas to meet our contracts with other coal suppliers. Our primary coal requirements.

burning facilities have the following requirements:

Approximate Oil Annual Coal Under normal burn practices, our requirements for Requirement Special Coal (tons) Restrictions residual fuel oil (No. 6) amount to approximately Brandon Shores 3,500,000 Sulfur content less 1.5 million to 2.0 million barrels of low-sulfur oil per Units 1 and 2 than 1.20 lbs per year. Deliveries of residual fuel oil are made from the (combined) mmBTU suppliers' Baltimore Harbor and Philadelphia marine C. P. Crane 850,000 Low ash melting terminals for distribution to the various generating plant Units 1 and 2 temperature locations. Also, based on normal burn practices, we (combined) require approximately 8.0 million to 11.0 million H. A. Wagner 1,100,000 Sulfur content no gallons of distillates (No. 2 oil and kerosene) annually, Units 2 and 3 more than 1%

(combined) but these requirements can vary substantially from year 8

to year depending upon the relationship between energy States are considering different types of regulatory prices and fuel costs, weather conditions, and operating initiatives concerning competition in the power requirements. Distillates are purchased from the industry, which makes a competitive assessment suppliers' Baltimore truck terminals for distribution to difficult. Increased competition that resulted from some the various generating plant locations. We have of these initiatives in several states contributed in some contracts with various suppliers to purchase oil at spot instances to a reduction in electricity prices and put prices, and for future delivery, to meet our pressure on electric utilities to lower their costs, requirements. including the cost of purchased electricity. While many states continue to support retail competition and Competition industry restructuring, other states that were considering Market developments over the past several years have deregulation have slowed their plans or postponed changed the nature of competition in the merchant consideration of deregulation. In addition, other states energy business. Certain companies within the merchant are reconsidering deregulation.

energy sector have curtailed their activities or withdrawn We believe there is adequate growth potential in completely from the business. However, new the current deregulated market and that further market competitors (e.g., financial investors, banks and changes could provide additional opportunities for our investment banks) have entered the market. We merchant energy business. In addition, our wholesale encounter competition from companies of various sizes, marketing, risk management, and trading operation having varying levels of experience, financial and human participates in global coal sourcing activities by resources, and differing strategies. providing coal for the variable or fixed supply needs of We face competition in the market for energy, North American and international power generators. In capacity, and ancillary services. In our merchant energy addition, our wholesale marketing, risk management, business, we compete with international, national, and and trading operation includes upstream (exploitation regional full service energy providers, merchants, and and production) and downstream (transportation and producers to obtain competitively priced supplies from a storage) natural gas operations.

variety of sources and locations, and to utilize efficient As the market for commercial, industrial, and transmission, transportation, or storage. We principally governmental supply continues to grow, we have compete on the basis of price, customer service, experienced increased competition on a regional basis in reliability, and availability of our products. our retail competitive supply activities. The increase in With respect to power generation, we compete in retail competition and the impact of wholesale power the operation of energy-producing projects, and our prices compared to the rates charged by local utilities competitors in this business are both domestic and has, in certain circumstances, reduced the margins that international organizations, including various utilities, we realize from our customers. However, we believe that industrial companies and independent power producers our experience and expertise in assessing and managing (including affiliates of utilities, financial investors, banks risk and our strong focus on customer service will help and investment banks), some of which have greater us to remain competitive during volatile or otherwise financial resources. 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 outputfrom gas-firedplantsuntil sale in December 2006.

Operatingstatistics do not reflect the elimination of intercompany transactions.

Certainprior-yearamounts have been reclassifiedto conform with the currentyear' presentation. The reclassifications primarily relate to operationsthat have been reflected as discontinuedin the currentyear.

9

Baltimore Gas and Electric Company Maryland PSC. Successful bidders, which may include BGE is an electric transmission and distribution utility subsidiaries of Constellation Energy, will execute company and a gas distribution utility company with a contracts with BGE for varying terms.

service territory that covers the City of Baltimore and all or part often counties in central Maryland. BGE is Commercialand Industrial Customers regulated by the Maryland PSC and Federal Energy BGE is obligated to provide market-based standard Regulatory Commission (FERC) with respect to rates offer service to commercial and industrial customers and other aspects of its business. for varying periods beyond June 30, 2004, depending BGE's electric service territory includes an area of on customer load.

approximately 2,300 square miles. There are no In August 2006, the Maryland PSC issued an municipal or cooperative wholesale customers within order indefinitely extending the obligation of BGE's service territory. BGE's gas service territory Maryland utilities to provide POLR service for those includes an area of approximately 800 square miles. commercial and industrial customers for which BGE's electric and gas revenues come from many market-based standard offer service was scheduled to customers-residential, commercial, and industrial. expire at the end of May 2007. The extended service will be provided on substantially the same terms as Electric Business under the existing service, except that wholesale ElectricRegulatoryMatters and Competition bidding for service to some customers will be conducted more frequently.

Deregulation BGE's obligation to provide market-based Effective July 1, 2000, electric customer choice and standard offer service to its largest commercial and competition among electric suppliers was implemented industrial customers expired on May 31, 2005. BGE in Maryland. As a result of the deregulation of electric continues to provide an hourly-priced market-based generation, all customers can choose their electric standard offer service to those customers.

energy supplier. While BGE does not sell electric commodity to all customers in its service territory, Residential Customers BGE continues to deliver electricity to all customers As a result of the November 1999 Maryland PSC and provides meter reading, billing, emergency order regarding the deregulation of electric generation response, and regular maintenance.

in Maryland, BGE's residential electric base rates were frozen until July 2006. Subsequent orders of the StandardOffier Service Maryland PSC specified that BGE would procure the BGE provided fixed-price standard offer service to power to serve residential customers beginning commercial and industrial customers through either July 2006 via auctions to be conducted in late 2005 June 30, 2002 or June 30, 2004, depending on and early 2006. The procured power costs of these customer type, and for residential customers through auctions would have resulted in an average electric June 30, 2006.

residential customer bill increase of 72%. In Upon the expiration of fixed-price standard offer June 2006, Senate Bill 1 was enacted, which, among service, customers that continue to receive their other things:

electric supply from BGE are charged market-based

+ imposes rate stabilization measures that (i) cap standard offer service rates (Provider of Last Resort rate increases by BGE for residential POLR rates). We discuss Provider of Last Resort (POLR) service at 15% from July 1, 2006 to May 31, rates in more detail below.

2007, (ii) give residential POLR customers the option from June 1, 2007 until December 31, Providerof Last Resort 2007 of paying a full market rate or choosing a BGE is obligated to provide market-based standard short term rate stabilization plan in order to offer service to all of its electric customers for varying provide a smooth transition to market rates periods. The POLR rates charged recover BGE's without adversely affecting the wholesale power supply costs and include an creditworthiness of BGE, and (iii) provide for administrative fee. The administrative fee includes a full market rates for residential POLR service shareholder return component and an incremental cost starting January 1, 2008; component. As a result of Senate Bill 1, beginning

• allows BGE to recover the costs deferred from January 1, 2007, the shareholder return component of July 1, 2006 to May 31, 2007 from its the administrative charge for residential POLR service customers over a period not to exceed was suspended. We discuss Senate Bill 1 in detail in 10 years, on terms and conditions to be the ResidentialCustomers section.

determined by the Maryland PSC, including Bidding to supply BGE's market-based standard through the issuance of rate stabilization offer service will occur from time to time through a bonds that securitize the deferred costs; competitive bidding process approved by the 10

• directs the Maryland PSC to investigate which will be determined in April 2007 via auctions.

measures to mitigate the impact of residential Customers who choose to defer would repay the rate increases on BGE customers, including by deferred amounts over a two-year period starting investigating the prior determination of and January 1, 2008, at which time these customers would allowances for stranded costs that occurred transition to full market rates. The proposed plan when BGE transferred assets to its affiliates in remains subject to Maryland PSC approval.

2000 and by requiring the Maryland PSC to Because Senate Bill 1 requires additional provide funds to residential customers of BGE decisions and proceedings by the Maryland PSC and for mitigation of BGE's rate increases, other governmental authorities to implement and including any adjustment in favor of BGE's interpret many of its provisions, we cannot predict the customers to allowances for such stranded ultimate impact of the legislation on us, BGE, or the costs; and energy market in Maryland. The new legislation and

1. requires BGE to reduce residential electric its implementation through applicable regulatory rates by approximately $39 million per year proceedings could have a material adverse effect on for 10 years, beginning January 1, 2007, our, or BGE's, financial results. In addition, one or through suspension of the collection of the more parties may challenge in court one or more residential return component of the provisions of Senate Bill 1. The outcome of any administrative charge for POLR service and a challenges and the uncertainty that could result cannot credit equal to the amount collected from be predicted.

BGE ratepayers for the nuclear We discuss other aspects of Senate Bill 1 in decommissioning trust for Calvert Cliffs. We Item 7. Management's Discussion andAnalysis-Business provide further details in the Costfor Environment-Senate Bill I section. We discuss the Decommissioningsection. market risk of our regulated electric business in more In August 2006, the Maryland PSC began its detail in Item 7. Management's Discussion and investigation into the general regulatory structure, Analysis-Market Risk section.

agreements, orders, and other prior actions of the Maryland PSC under the Electric Customer Choice ElectricLoad Management and Competition Act of 1999, including the BGE has implemented various programs for use when determination of and allowances for stranded costs. system-operating conditions or market economics We cannot predict the outcome of the investigation, indicate that a reduction in load would be beneficial.

but it could have a material adverse effect on our, or We refer to these programs as active load management BGE's, financial results. programs. These programs include:

In December 2006, the Maryland PSC issued an

• two options for commercial and industrial order that allows BGE to securitize its costs relating to customers to voluntarily reduce their electric the residential rate deferral through the issuance of loads, bonds in an aggregate principal amount of

• air conditioning control for residential and approximately $630 million, subject to adjustment. commercial customers, and Also in December 2006, in connection with + residential water heater control.

implementing the $39 million in annual residential These programs generally take effect on summer electric rate reductions discussed above, BGE and days when demand and/or wholesale prices are Calvert Cliffs notified the Maryland PSC that they had relatively high and had the capability during the 2006 entered into a standstill agreement with the Attorney summer to reduce load up to approximately 233 MW.

General of the State of Maryland with respect to potential challenges to the provisions of Senate Bill 1 Transmission and DistributionFacilities relating to the reductions. BGE maintains approximately 250 substations and In January 2007, BGE filed a proposed plan with 1,300 circuit miles of transmission lines throughout the Maryland PSC that would allow residential electric central Maryland. BGE also maintains approximately customers to defer the transition to full market rates 23,900 circuit miles of distribution lines. The from June 1, 2007 to December 31, 2007. Under the transmission facilities are connected to those of proposed plan, electric rates for residential customers neighboring utility systems as part of PJM. Under the who elect this extended deferral would increase on PJM Tariff and various agreements, BGE and other June 1, 2007 by one-half of the total increase market participants can use regional transmission remaining to reach full market rates on January 1, facilities for energy, capacity, and ancillary services 2008. We estimate that electric rates for residential transactions including emergency assistance.

electric customers under this plan will be We discuss various FERC initiatives relating to approximately 20-25% higher on June 1, 2007 wholesale electric markets in more detail in Item 7.

compared to current residential electric rates. This Management's Discussion and Analysis-Federal estimate may differ from the actual increase on June 1, Regulation section.

2007 based on BGE's actual procured power cost, 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.

Operatingstatistics do not reflect the elimination ofintercompany transactions.

"Delivery service only" refers to BGE's delivery ofcommodity that was purchasedby the customerfrom an alternatesupplier.

12

Gas Business BGE purchases the natural gas it resells to The wholesale price of natural gas as a commodity is not customers directly from many producers and marketers.

subject to regulation. All BGE gas customers have the BGE has transportation and storage agreements that option to purchase gas from alternative suppliers, expire from 2007 to 2028.

including subsidiaries of Constellation Energy. BGE BGE's current pipeline firm transportation continues to deliver gas to all customers within its entitlements to serve BGE's firm loads are 313,053 service territory. This delivery service is regulated by the dekatherms (DTH) per day.

Maryland PSC. BGE's current maximum storage entitlements are BGE also provides customers with meter reading, 235,080 DTH per day. To supplement its gas supply at billing, emergency response, regular maintenance, and times of heavy winter demands and to be available in balancing services. temporary emergencies affecting gas supply, BGE has:

Approximately 50% of the gas delivered on BGE's

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

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

its'gas base rates. In December 2006, the Baltimore City BGE has under contract sufficient volumes of Circuit Court upheld the rate order. However, certain propane for the operation of the propane air facility and parties have filed an appeal with the Court of Special is capable of liquefying sufficient volumes of natural gas Appeals. We cannot provide assurance that the during the summer months for operations of its Maryland PSC's order will not be reversed in whole or liquefied natural gas facility during peak winter periods.

in part or that certain issues will not be remanded to the BGE historically has been able to arrange short-Maryland PSC for reconsideration. term contracts or exchange agreements with other gas For customers that buy their gas from BGE, there companies in the event of short-term disruptions to gas is a market-based rates incentive mechanism. Under this supplies or to meet additional demand.

market-based rates incentive mechanism, our actual cost BGE also participates in the interstate markets by of gas is compared to a market index (a measure of the releasing pipeline capacity or bundling pipeline capacity market price of gas in a given period). The difference with gas for off-system sales. Off-system gas sales are between our actual cost and the market index is shared low-margin direct sales of gas to wholesale suppliers of equally between shareholders and customers. BGE must natural gas. Earnings from these activities are shared secure fixed-price contracts for at least 10%, but not between shareholders and customers. BGE makes these more than 20%, of forecasted system supply sales as part of a program to balance our supply of, and requirements for the November through March period. cost of, natural gas.

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

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 Operatingstatistics do not reflect the elimination of intercompany transactions.

"Delivery service only" refers to BGE's delivery ofcommodity that was purchasedby the customerfrom an alternatesupplier.

14

Franchises We continuously monitor federal, state, and local BGE has nonexclusive electric and gas franchises to use environmental initiatives to determine potential impacts streets and other highways that are adequate and on our financial results. As new laws or regulations are sufficient to permit them to engage in their present promulgated, we assess their applicability and business. Conditions of the franchises are satisfactory. implement the necessary modifications to our facilities or their operation to maintain ongoing compliance. Our Other Nonregulated Businesses capital expenditures were approximately $100 million Energy Projects and Services during the five-year period 2002-2006 to comply with We offer energy projects and services designed primarily existing environmental standards and regulations. Our to provide energy solutions to large commercial and estimated environmental capital requirements for the industrial and governmental customers. These energy next three years are approximately $335 million in products and services include: 2007, $495 million in 2008, and $305 million in 2009.

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

• energy savings projects and performance Federal contracting, The Clean Air Act created the basic framework for the

• energy consulting and procurement services, federal and state regulation of air pollution.

• services to enhance the reliability of individual electric supply systems, and NationalAmbient Air Quality Standards (NAAQS)

• customized financing alternatives. The NAAQS are federal air quality standards authorized under the Clean Air Act that establish maximum Home Products and Gas Retail Marketing ambient air concentrations for the following specific We offer services to customers in Maryland including: pollutants: ozone (smog), carbon monoxide, lead,

• home improvements, particulates, sulfur dioxides (SO 2), and nitrogen dioxides

• the service of heating, air conditioning, (NO).

plumbing, electrical, and indoor air quality In order for states to achieve compliance with the systems, and NAAQS, the Environmental Protection Agency (EPA) 4 the sale of natural gas to residential customers. 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 Consolidated Capital Requirements and nitrogen oxide (NO.) emissions from fossil fuel-Our total capital requirements for 2006 were fired generating facilities located primarily in the

$1,149 million. Of this amount, $789 million was used Eastern United States.

in our nonregulated businesses and $360 million was In May 2005, the EPA adopted a stricter NAAQS used in our regulated business. We estimate our total for ozone and rescinded a requirement to impose fees on capital requirements will be $1,915 million in 2007.

emissions sources in certain areas, including certain of We continuously review and change our capital our generating facilities, for failure to achieve the expenditure programs, so actual expenditures may vary previous ozone standard. States will be required to from the estimate above. We discuss our capital submit plans to the EPA to meet the new standard by requirements further in Item 7. Management's Discussion 2007, at which time the standard will take effect. We andAnalysis-CapitalResources section.

are unable to determine the impact that complying with the stricter NAAQS for ozone will have on our financial Environmental Matters results until the states in which our generating facilities The development (involving site selection, are located adopt plans to meet the new standard.

environmental assessments, and permitting),

In December 2006, the United States Court of construction, acquisition, and operation of electric Appeals for the District of Columbia Circuit ruled that generating and distribution facilities are subject to the requirement to impose fees on emissions sources extensive federal, state, and local environmental and based on the previous ozone standard remained land use laws and regulations. From the beginning applicable retroactive to November 2005 and remanded phases of development to the ongoing operation of the issue to the EPA for reconsideration. At this time, existing or new electric generating and distribution we cannot predict what action the EPA will take in facilities, our activities involve compliance with diverse response to the Court's decision and whether the fees laws and regulations that address emissions and impacts will be retroactively assessed. The exact method of to air and water, protection of natural and cultural computing these fees has not been established and will resources, and chemical and waste handling depend in part on state implementation regulations that and disposal.

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 State that are ultimately assessed could have a material adverse Maryland has adopted the Healthy Air Act (l-AA) and affect on our financial results. the Clean Power Rule (CPR), which establish annual In September 2006, the EPA adopted a stricter SO,, NO., and mercury emission caps for specific coal-NAAQS for particulate matter. We are unable to fired units in Maryland, including units located at three determine the impact that complying with the stricter of our facilities. The requirements of the HAA and the NAAQS for particulate matter will have on our financial CPR for SO,, NO. and mercury emissions are more results until the states in which our generating facilities stringent and apply sooner than those under CAIR and are located adopt plans to meet the new standard. CAMR.

In addition, Pennsylvania has adopted regulations Hazardous Air Emissions requiring coal-fired generating facilities located in In March 2005, the EPA finalized the Clean Air Pennsylvania to reduce mercury emissions sooner and to Mercury Rule (CAMR) to reduce the emissions of a greater extent than required under CAMR.

mercury from coal-fired facilities through a Several other states in the northeastern U.S.

market-based cap and trade program. CAMR will affect continue to consider more stringent and earlier SO,,

all coal or waste coal fired boilers at our generating NO., and mercury emissions reductions than those facilities. required under CAIR or CAMR.

New Source Review Cap~ital Expenditure Estimates In connection with its enforcement of the Clean Air We expect to incur additional environmental capital Act's new source review requirements, in 2000, the EPA spending as a result of complying with the air quality requested information relating to modifications made to laws and regulations discussed above. Based on the our Brandon Shores, Crane, and Wagner plants located information currently available to us about CAIR, in Maryland. The EPA also sent similar, but narrower, CAMR, HAA, and CPR, we will install additional air information requests to two of our newer Pennsylvania emission control equipment at our coal-fired generating waste-coal burning plants in which we have an facilities in Maryland and at our co-owned coal-fired ownership interest. We responded to the EPA in 2001, facilities in Pennsylvania to meet air qualiry standards.

and as of the date of this report the EPA has taken no We include in our estimated environmental capital further action. requirements capital spending for these projects, which we expect will be approximately $320 million in 2007, Based on the level of emissions control that the EPA and states are seeking in these new source review $470 million in 2008, $290 million in 2009 and enforcement actions, we believe that material additional $40 million from 2010-2011.

costs and penalties could be incurred, and planned Our estimates are subject to significant capital expenditures could be accelerated, if the EPA was uncertainties including the timing of any additional successful in any future actions regarding our facilities. federal and/or state regulations or legislation, the In March 2006, the U.S. Court of Appeals for the implementation timetables for such regulation or District of Columbia annulled the equipment legislation, and the specific amount of emissions replacement rule adopted by the EPA in August 2003, reductions that will be required at our facilities. As a which established a threshold for determining when result, we cannot predict our capital spending or the major new source review requirements are triggered. We scope or timing of these projects with certainty, and the believe the Court decision, which was anticipated, actual expenditures, scope and timing could differ significantly from our estimates. In addition, CAMR is should have minimal effect on us as it maintains the existing rules for equipment replacement. However, we subject to legal challenges filed by the states and anticipate that the EPA will continue to examine the industry and environmental groups. We cannot predict existing equipment replacement rules and may again the timing or outcome of these challenges, or their propose new rules. In addition, the U.S. Supreme Court possible effect on our financial results.

has agreed to hear a case, not involving us, relating to We believe that the additional air emission control the new source review requirements. We cannot predict equipment we plan to install will meet the emission the timing or outcome of any future EPA regulatory reduction requirements under CAIR, CAMR, I-AA, action or the outcome of the U.S. Supreme Court and CPR. If additional emission reductions still are proceeding, or their possible effect on our financial required, we will assess our various compliance results. 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 decision. However, any such action could impact our Although uncertainty remains as to the nature and compliance approach, which could have a material effect timing of greenhouse gas emissions regulation, there is on our financial results.

an increasing likelihood that such regulation will occur at the federal and/or state level. In the event that Hazardous and Solid Waste greenhouse gas emissions reduction legislation or We discuss proceedings relating to compliance with the regulations are enacted, we will assess our various Comprehensive Environmental Response, compliance alternatives, which may include installation Compensation and Liability Act in Note 12 to of additional environmental controls, modification of ConsolidatedFinancialStatements.

operating schedules or the closure of one or more of our Our coal-fired generating facilities produce coal-fired generating facilities. Any compliance costs we approximately two and a half million tons of incur could have a material impact on our financial combustion by-products ("ash") each year. The EPA has results. announced its intention to develop national standards, The HAA requires that Maryland become a full currently scheduled to be proposed in May 2007, to participant in the Northeast Regional Greenhouse Gas regulate this material as a non-hazardous waste, and is Initiative (RGGI) by June 2007. Under RGGI, it is developing regulations governing the placement of ash expected that affected plants would participate in an in landfills, surface impoundments, and sand/gravel auction to obtain sufficient CO, allowances to support surface mines.

the level of emissions that result from plant operations. The EPA is also developing regulations for ash In addition, California has adopted regulations placement in coal mines, which are expected to be requiring our generating facilities in California to proposed in October 2007. Federal regulation has the submit greenhouse gas emissions data to the state, which potential to result in additional requirements.

the state intends to use to develop a plan to reduce Depending on the scope of any final requirements, our greenhouse gas emissions. compliance costs could be material.

We continue to evaluate the potential impact of As a result of these regulatory pr6posals, the the I-AA and California CO, emissions requirements remaining ash placement capacity at our current mine and RGGI participation on our financial results; reclamation site and our current ash generation however, our compliance costs could be material. projections, we are exploring our options for the placement of ash, including construction of an ash Water Quality placement facility. Over the next five years, we estimate The Clean Water Act established the basic framework that our capital expenditures for this project will be for federal and state regulation of water pollution approximately $75 million. Our estimates are subject to control and requires facilities that discharge waste or significant uncertainties including the timing of any storm water into the waters of the United States to regulatory change, its implementation timetable, and obtain permits. the scope of the Final requirements. As a result, we cannot predict our capital spending or the scope and Water Intake Regulations timing of this project with certainty, and the actual In July 2004, the EPA published final rules under the expenditures, scope and timing could differ significantly Clean Water Act that require cooling water intake from our estimates.

structures to reflect the best technology available for minimizing adverse environmental impacts. We Employees currently have six facilities affected by the regulation. Constellation Energy and its subsidiaries had The rule allows for a number of compliance options that approximately 9,645 employees at December 31, 2006.

will be assessed through 2007, following which we will At the Nine Mile Point facility, approximately 515 determine whether any action is required and what our employees are represented by the International most viable options are if any action is required. Until Brotherhood of Electrical Workers, Local 97. The labor we determine our most viable option under the final contract with this union expires in June 2011. We rules, we cannot estimate our compliance costs. believe that our relationship with this union is However, the costs associated with the final rules could satisfactory, but there can be no assurances that this will be material. continue to be the case.

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 17

Item IA. Risk Factors obtained for power produced from such fuel may not You should consider carefully the following risks, along change at the same rate as fuel costs. As a result, fuel with the other information contained in this Form 10-K. price increases may adversely affect our financial results.

The risks and uncertaintiesdescribed below are not the only Exposure to counterpartyperformance. Our ones that may affect us. Additional risks and uncertainties merchant energy business enters into trades and hedging also may adversely affect our business and operations transactions with numerous third parties (commonly including those discussed in Item 7. Management's referred to as "counterparties"). In such arrangements, Discussion and Analysis. If any of thefollowing events we are exposed to the credit risks of our counterparties actually occur, our business andfinancialresults could be and the risk that one or more counterparties may fail to materiallyadversely affected. perform their obligations to make payments or deliver fuel or power. These risks are enhanced during periods Our merchant energy business may incur of commodity price fluctuations, such as is currently substantial costs and liabilities and be exposed being experienced in the United States. Defaults by to price volatility and counterparty performance suppliers and other counterparties may adversely affect risk as a result of its participation in the our financial results.

wholesale energy markets.

We purchase and sell power and fuel in markets exposed The operation of power generation facilities, to significant risks, including price volatility for including nuclear facilities, involves significant electricity and fuel and the credit risks of counterparties risks that could adversely affect our financial with which we enter into trades. results.

We use various hedging strategies in an effort to We own and operate a number of power generation mitigate many of these risks. However, hedging facilities. The operation of power generation facilities transactions do not guard against all risks and are not involves many risks, including start up risks, breakdown always effective, as they are based upon predictions or failure of equipment, transmission lines, substations about future market conditions. The inability or failure or pipelines, use of new technology, the dependence on to effectively hedge assets or fuel or power positions a specific fuel source, including the transportation of against changes in commodity prices, interest rates, fuel, or the impact of unusual or adverse weather counterparty credit risk or other risk measures could conditions (including natural disasters such as significantly impair future financial results. hurricanes) or environmental compliance, as well as the Exposure to electricityprice volatility. We buy and risk of performance below expected or contracted levels sell electricity in both the wholesale bilateral markets of output or efficiency. This could result in lost and spot markets, which exposes us to the risks of rising revenues and/or increased expenses. Insurance, and falling prices in those markets, and our cash flows warranties, or performance guarantees may not cover may vary accordingly. At any given time, the wholesale any or all of the lost revenues or increased expenses, spot market price of electricity for each hour is generally including the cost of replacement power. A portion of determined by the cost of supplying the next unit of our generation facilities were constructed many years electricity to the market during that hour. This is highly ago. Older generating equipment may require dependent on the regional generation market. In many significant capital expenditures to keep it operating at cases, the next unit of electricity supplied would be peak efficiency. This equipment is also likely to require supplied from generating stations fueled by fossil fuels, periodic upgrading and improvement. Breakdown or primarily coal, natural gas and oil. Consequently, the failure of one of our operating facilities may prevent the open market wholesale price of electricity may reflect facility from performing under applicable power sales the cost of coal, natural gas or oil plus the cost to agreements which, in certain situations, could result in convert the fuel to electricity and an appropriate return termination of the agreement or incurring a liability for on capital. Therefore, changes in the supply and cost of liquidated damages.

coal, natural gas and oil may impact the open market wholesale price of electricity. We are subject to numerous environmental laws A portion of our power generation facilities and regulations that require capital expenditures, operates wholly or partially without long-term power increase our cost of operations and may expose purchase agreements. As a result, power from these us to environmental liabilities.

facilities is sold on the spot market or on a short-term We are subject to extensive federal, state, and local contractual basis, which if not fully hedged may affect environmental statutes, rules and regulations relating to the volatility of our financial results. air quality, water quality, waste management, wildlife Exposure to fuel cost volatility. Currently, our protection, the management of natural resources, and power generation facilities purchase a portion of their the protection of human health and safety that could, fuel through short-term contracts or on the spot market. among other things, require additional pollution control Fuel prices can be volatile, and the price that can be equipment, limit the use of certain fuels, restrict the 18

output of certain facilities, or otherwise increase costs.

• regulatory actions, including shut down of units Significant capital expenditures, operating and other because of public safety concerns, whether at costs are associated with compliance with environmental our plants or other nuclear operators; requirements, and these expenditures and costs could

• limitations on the amounts and types of become even more significant in the future as a result of insurance coverage commercially available; regulatory changes.

• uncertainties regarding both technological and For example, the State of Maryland has enacted financial aspects of decommissioning nuclear the Healthy Air Act and the Clean Power Rule, which generating facilities; and will require, among other things, more rapid emission

• environmental risks, including risks associated reductions by Maryland power generation facilities with changes in environmental legal (including those owned and operated by us) than is requirements.

required by current federal laws and regulations. Nuclear Accident Risks. In the event of a nuclear We are subject to liability under environmental accident, the cost of property damage and other laws for the costs of remediating environmental expenses incurred may exceed our insurance coverage contamination. Remediation activities include the available from both private sources and an industry cleanup of current facilities and former properties, retrospective payment plan. In addition, in the event of including manufactured gas plant operations and offsite an accident at one of our or another participating waste disposal facilities. The remediation costs could be insured party's nuclear plants, we could be assessed significantly higher than the liabilities recorded by us. retrospective insurance premiums (because all nuclear Also, our subsidiaries are currently involved in plant operators contribute to a nationwide catastrophic proceedings relating to sites where hazardous substances insurance fund). Uninsured losses or the payment of have been released and may be subject to additional retrospective insurance premiums could each have a proceedings in the future. material adverse effect on our financial results.

We are subject to legal proceedings by individuals alleging injury from exposure to hazardous substances We often rely on single suppliers and at times on and could incur liabilities that may be material to our single customers, exposing us to significant financial results. Additional proceedings could be filed financial risks if either should fail to perform against us in the future. their obligations.

We may also be required to assume environmental We often rely on a single supplier for the provision of liabilities in connection with future acquisitions. As a fuel, water, and other services required for operation of a result, we may be liable for significant environmental facility, and at times, we rely on a single customer or a remediation costs and other liabilities arising from the few customers to purchase all or a significant portion of operation of acquired facilities, which may adversely a facility's output, in some cases under long-term affect our financial results. agreements that provide the support for any project debt used to finance the facility. The failure of any one Our generation business may incur substantial customer or supplier to fulfill its contractual obligations costs and liabilities due to its ownership and could negatively impact our financial results.

operation of nuclear generating facilities. Consequently, our financial performance depends on We own and operate nuclear power plants. Ownership the continued performance by customers and suppliers and operation of these plants exposes us to risks in of their obligations under these long-term agreements.

addition to those that result from owning and operating non-nuclear power generation facilities. These risks Reduced liquidity in the markets in which we include normal operating risks for a nuclear facility and operate could impair our ability to appropriately the risks of a nuclear accident. manage the risks of our operations.

Nuclear OperatingRisks. The ownership and We are an active participant in energy markets through operation of nuclear generating facilities involve routine our competitive energy businesses. The liquidity of operating risks, including: regional energy markets is an important factor in our

• mechanical or structural problems; ability to manage risks in these operations. Over the past

• inadequacy or lapses in maintenance protocols; several years, several merchant energy businesses have

• impairment of reactor operation and safety ended or significantly reduced their activities as a result systems due to human or mechanical error; of several factors including government investigations,

• costs of storage, handling and disposal of changes in market design and deteriorating credit nuclear materials, including the availability or quality. As a result, several regional energy markets unavailability of a permanent repository for experienced a significant decline in liquidity. While spent nuclear fuel; 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, state and federal levels. These initiatives have had a competitive supply or other market positions significant impact on the nature of the electric and against changes in commodity prices, and our natural gas industries and the manner in which their hedging procedures may not work as planned. participants conduct their businesses. We have targeted To lower our financial exposure related to commodity the competitive segments of the electric and natural gas price fluctuations, we routinely enter into contracts to industries created by these initiatives.

hedge a portion of our purchase and sale commitments, Due to recent events in the energy markets, energy weather positions, fuel requirements, inventories of companies have been under increased scrutiny by state natural gas, coal and other commodities, and legislatures, regulatoty bodies, capital markets and credit competitive supply. As part of this strategy, we routinely rating agencies. This increased scrutiny could lead to utilize fixed-price forward physical purchase and sales substantial changes in laws and regulations affecting us, contracts, futures, financial swaps, and option contracts including modifications to the auction processes in traded in the over-the-counter markets or on exchanges. competitive markets and new accounting standards that However, we may not cover the entire exposure of our could change the way we are required to record assets or positions to market price volatility and the revenues, expenses, assets and liabilities. The Matyland coverage will vary over time. Fluctuating commodity energy legislation enacted in June 2006 is one example prices may negatively impact our financial results to the of how these laws can change. We cannot predict the extent we have unhedged positions. future development of regulation in these markets or the In addition, daily value at risk and stop loss limits ultimate effect that this changing reguldatoty and liquidity guidelines are based on historical price environment will have on our business.

movements. If prices significantly or persistently deviate If competitive restructuring of the electric and from historical prices, the limits may not protect us natural gas markets is reversed, discontinued, restricted from significant losses. or delayed, or if the recently enacted Matyland energy Our risk management policies and procedures may legislation is implemented or interpreted in a manner not always work as planned. As a result of these and adverse to us, our business prospects and financial other factors, we cannot predict with precision the results could be negatively impacted.

impact that risk management decisions may have on our financial results. Our financial results may be harmed if transportation and transmission availability is The use of derivative contracts by us in the limited or unreliable.

normal course of business could result in We have business operations throughout the financial losses that negatively impact our United States and internationally. As a result, we financial results. depend on transportation and transmission facilities We use derivative instruments, such as swaps, options, owned and operated by utilities and other energy futures and forwards, to manage our commodity and companies to deliver the electricity, coal, and natural gas financial market risks and to engage in trading activities. we sell to the wholesale and retail markets, as well as the We could recognize financial losses as a result of natural gas and coal we purchase to supply some of our volatility in the market values of these contracts or if a generating facilities. If transportation or transmission is counterparty fails to perform. disrupted, or transportation or transmission capacity is In the absence of actively quoted market prices inadequate, our ability to sell and deliver products may and pricing information from external sources, the be hindered. Such disruptions could also hinder our valuation of these derivative instruments involves ability to provide electricity or natural gas to our retail management's judgment or use of estimates. As a result, electric and gas customers and may materially adversely changes in the underlying assumptions or use of affect our financial results.

alternative valuation methods could affect the reported fair value of these contracts. Our merchant energy business has contractual obligations to certain customers to provide full We operate in deregulated segments of the requirements service, which makes it difficult to electric and gas industries created by federal predict and plan for load requirements and may and state restructuring initiatives. If competitive result in increased operating costs to our restructuring of the electric or gas industries is business.

reversed, discontinued, restricted or delayed, our Our merchant energy business has contractual business prospects and financial results could be obligations to certain customers to supply full materially adversely affected. requirements service to such customers to satisfy all or a The regulatoty environment applicable to the electric portion of their energy requirements. The uncertainty and natural gas industries has undergone substantial regarding the amount of load that our merchant energy changes as a result of restructuring initiatives at both the business must be prepared to supply to customers may 20

increase our operating costs. A significant under- or credit ratings are cash flows, liquidity, and the amount over-estimation of load requirements could result in our of debt as a component of total capitalization.

merchant energy business not having enough or having In addition, the ability of BGE to recover its costs too much power to cover its load obligation, in which of providing service and timing of BGE's recovery could case it would be required to buy or sell power from or to have a material adverse effect on the credit ratings of third parties at prevailing market prices. Those prices BGE and us.

may not be favorable and thus could increase our operating costs. We, and BGE in particular, are subject to extensive state and federal regulation that could Our financial results may fluctuate on a seasonal affect our operations and costs.

and quarterly basis or as a result of severe We are subject to regulation by federal and state weather. governmental entities, including the Federal Energy Our business is affected by weather conditions. Our Regulatory Commission, the Nuclear Regulatory overall operating results may fluctuate substantially on a Commission, the Maryland PSC and the utility seasonal basis, and the pattern of this fluctuation may commissions of other states in which we have change depending on the nature and location of any operations. In addition, changing governmental policies facility we acquire and the terms of any contract to and regulatory actions can have a significant impact on which we become a party. Weather conditions directly us. Regulations can affect, for example, allowed rates of influence the demand for electricity and natural gas and return, requirements for plant operations, recovery of affect the price of energy commodities. costs, limitations on dividend payments and the Generally, demand for electricity peaks in winter regulation or re-regulation of wholesale and retail and summer and demand for gas peaks in the winter. competition (including but not limited to retail choice Typically, when winters are warmer than expected and and transmission costs).

summers are cooler than expected, demand for energy is BGE's distribution rates are subject to regulation lower, resulting in less electric and gas consumption by the Maryland PSC, and such rates are effective until than forecasted. Depending on prevailing market prices new rates are approved. In addition, limited categories for electricity and gas, these and other unexpected of costs are recovered through adjustment charges that conditions may reduce our revenues and results of are periodically reset to reflect current and projected operations. First and third quarter financial results, in costs. Inability to recover material costs not included in particular, are substantially dependent on weather rates or adjustment clauses, including increases in conditions, and may make period comparisons less uncollectible customer accounts that may result from relevant. Severe weather can affect our results of higher gas or electric costs, could have an adverse effect operation. on our, or BGE's, cash flow and financial position.

Severe weather can be destructive, causing outages Energy legislation enacted in Maryland in and/or property damage. This could require us to incur June 2006 mandates rate stabilization that requires BGE additional costs. Catastrophic weather, such as to defer the recovery of a portion of its purchased power hurricanes, could impact our or our customers, costs and to phase in the recovery of these costs over a operating facilities, communication systems and period of years. In addition, the legislation mandates technology. Unfavorable weather conditions may have a that the Maryland PSC conduct a comprehensive review material adverse effect on our financial results. of Maryland's deregulated electricity market. Because this energy legislation is still in the process of being A downgrade in our credit ratings could implemented and interpreted, we do not know the final negatively affect our ability to access capital impact such legislation will have on our, or BGE's, and/or operate our wholesale and retail business.

competitive supply businesses. The regulatory process may restrict our ability to We rely on access to capital markets as a source of grow earnings in certain parts of our business, cause liquidity for capital requirements not satisfied by delays in or affect business planning and transactions operating cash flows. If any of our credit ratings were to and increase our, or BGE's, costs.

be downgraded, especially below investment grade, our ability to raise capital on favorable terms, including the Poor market performance will affect our benefit commercial paper markets, could be hindered, and our plan and nuclear decommissioning trust asset borrowing costs would increase. Additionally, the values, which may adversely affect our liquidity business prospects of our wholesale and retail and financial results.

competitive supply businesses, which in many cases rely Our qualified pension obligations have exceeded the fair on the creditworthiness of Constellation Energy, would value of our plan assets since 2001. At December 31, be negatively impacted. Some of the factors that affect 2006, our qualified pension obligations were approximately $405 million greater than the fair value 21

of our plan assets. The performance of the capital Our ability to successfully identify, complete and markets will affect the value of the assets that are held in integrate acquisitions is subject to significant trust to satisfy our future obligations under our qualified risks, including the effect of increased pension plans. A decline in the market value of those competition.

assets may increase our funding requirements for these We are likely to encounter significant competition for obligations, which may adversely affect our liquidity and acquisition opportunities that may become available. In financial results. addition, we may be unable to identify attractive We are required to maintain funded trusts to acquisition opportunities at favorable prices and to satisfy our future obligations to decommission our successfully and timely complete and integrate them.

nuclear power plants. A decline in the market value of those assets due to poor investment performance or Item 2. Properties other factors may increase our funding requirements for Constellation Energy's corporate offices occupy these obligations, which may have an adverse effect on approximately 106,000 square feet of leased office space our liquidity and financial results. in Baltimore, Maryland. The corporate offices for most of our merchant energy business occupy approximately War and threats of terrorism and catastrophic 268,000 square feet of leased office space in another events that could result from terrorism may building in Baltimore, Maryland. We describe our impact our results of operations in unpredictable electric generation properties on the next page. We also ways. have leases for other offices and services located in the We cannot predict the impact that any future terrorist Baltimore metropolitan region, and for various real attacks may have on the energy industry in general and property and facilities relating to our generation on our business in particular. In addition, any projects.

retaliatory military strikes or sustained military BGE owns its principal headquarters building campaign may affect our operations in unpredictable located in downtown Baltimore. In addition, BGE owns ways, such as changes in insurance markets and propane air and liquefied natural gas facilities as disruptions of fuel supplies and markets, particularly oil. discussed in Item 1. Business-GasBusiness section.

The possibility alone that infrastructure facilities, such BGE also has rights-of-way to maintain 26-inch as electric generation, electric and gas transmission and natural gas mains across certain Baltimore City-owned distribution facilities, would be direct targets of, or property (principally parks) which expired in 2004.

indirect casualties of, an act of terror may affect our BGE is in the process of renewing the rights-of-way operations. with Baltimore City for an additional 25 years. The Such activity may have an adverse effect on the expiration of the rights-of-way does not affect BGE's United States economy in general. A lower level of ability to use the rights-of-way during the renewal economic activity might result in a decline in energy process.

consumption, which may adversely affect our financial BGE has electric transmission and electric and gas results or restrict our future growth. Instability in the distribution lines located:

financial markets as a result of terrorism or war may

• in public streets and highways pursuant to affect our stock price and our ability to raise capital. franchises, and

• on rights-of-way secured for the most part by We are subject to employee workforce factors grants from owners of the property.

that could affect our businesses and financial All of BGE's property is subject to the lien of results. BGE's mortgage securing its mortgage bonds. The We are subject to employee workforce factors, including generation facilities transferred to our subsidiaries by loss or retirement of key executives or other employees, BGE on July 1, 2000, along with the stock we own in availability of qualified personnel, collective bargaining certain of our subsidiaries, are subject to the lien of agreements with union employees, and work BGE's mortgage.

stoppage that could affect our financial results. In We believe we have satisfactory title to our power particular, our competitive energy businesses are project facilities in accordance with standards generally dependent, in part, on recruiting and retaining accepted in the energy industry, subject to exceptions, personnel with experience in sophisticated energy which in our opinion, would not have a material adverse transactions and the functioning of complex wholesale effect on the use or value of the facilities.

markets. 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.

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The following table describes our generating facilities:

% Capacity Plant Location Capacity (M")') Owned Owned (MW) Primary Fuel (at December 31, 2006)

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

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

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:

COMMON SHARES CAST:

For Withheld Douglas L. Becker 119,241,432 14,048,574 Edward A. Crooke 122,520,333 10,769,673 Mayo A. Shattuck III 128,640,389 4,649,617 Michael D. Sullivan 119,327,025 13,962,981 All other directors whose term of office continued after the date of this meeting are:

James T. Brady Freeman A. Hrabowski, III James R. Curtiss Nancy Lampton Yves C. de Balmann 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 Other Offices or Positions Held Name Age Present Office During Past Five Years Mayo A. Shattuck III 52 Chairman of the Board of None.

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 Senior Vice President-Constellation January 2004), Chief Financial Energy.

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 President and Chief Executive Officer-Commodities Group, Inc. (since Constellation Energy Commodities August 2005); and Vice Chairman Group, Inc.

(since August 2005) and Executive Vice President (since January 2004) of Constellation Energy Michael J. Wallace 59 President (since January 2002) and None.

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

Thomas F. Brady 57 Executive Vice President, Corporate Senior Vice President, Corporate Strategy Strategy and Retail Competitive and Development-Constellation Supply of Constellation Energy Energy; and Vice President, Corporate (since January 2004) Strategy and Development-Constellation Energy.

Irving B. Yoskowitz 61 Executive Vice President and General Senior Counsel-Crowell & Moring (law Counsel of Constellation Energy firm); and Senior Partner-Global (since June 2005) Technology Partners, LLC (investment banking and consulting firm).

Felix J. Dawson 39 Senior Vice President of Constellation Co-Chief Commercial Officer-Energy (since October 2006); and Constellation Energy Commodities Co-President and Co-Chief Group, Inc.; and Managing Executive Officer of Constellation Director-Constellation Energy Energy Commodities Group, Inc. Commodities Group, Inc.

(since August 2005); President and Chief Executive Officer of Constellation Energy Partners LLC (since May 2006) 25

Other Offices or Positions Held Name Age Present Office During Past Five Years George E. Persky 37 Senior Vice President of Constellation Co-Chief Commercial Officer-Energy (since October 2006); and Constellation Energy Commodities Co-President and Co-Chief Group, Inc.; and Managing Executive Officer of Constellation Director-Constellation Energy Energy Commodities Group, Inc. Commodities Group, Inc.

(since August 2005)

Kenneth W. 56 President and Chief Executive Officer Vice President, Electric Transmission and DeFontes, Jr. of Baltimore Gas and Electric Distribution-BGE.

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

Paul J. Allen 55 Senior Vice President, Corporate Vice President, Corporate Affairs-Affairs of Constellation Energy Constellation Energy.

(since January 2004)

John R. Collins 49 Senior Vice President (since Vice President-Constellation Energy.

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)

Beth S. Perlman 46 Senior Vice President (since Vice President-Constellation Energy; January 2004) and Chief and Vice President, Technology-Information Officer of Enron Corporation.

Constellation Energy (since April 2002)

Marc L. Ugol 48 Senior Vice President, Human Vice President, Human Resources-Resources of Constellation Energy Constellation Energy; and Senior Vice (since January 2004) President, Human Resources and Administration-Tellabs, Inc.

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 payable April 2, 2007 to holders of record on March 12, Constellation Energy's common stock is traded under 2007. This is equivalent to an annual rate of $1.74 per the ticker symbol CEG. It is listed on the New York and share.

Chicago stock exchanges. Quarterly dividends were declared on our As of January 31, 2007, there were 41,680 common stock during 2006 and 2005 in the amounts common shareholders of record. set forth below.

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

are no contractual limitations on Constellation Energy + BGE elects to defer interest payments on the paying common stock dividends. 6.20% Deferrable Interest Subordinated Dividends have been paid continuously since 1910 Debentures due 2043, and any deferred interest on the common stock of Constellation Energy, BGE, remains unpaid; or and their predecessors. Future dividends depend upon

• any dividends (and any redemption payments) future earnings, our financial condition, and other due on BGE's preference stock have not been factors. paid.

In January 2007, we announced an increase in our quarterly dividend from $0.3775 to $0.435 per share Common Stock Dividends and Price Ranges 2006 2005 Dividend Price Dividend Price Declared High Low Declared High Low First Quarter ............................ $0.3775 $60.55 $54.01 $0.335 $53.55 $43.01 Second Quarter ......................... 0.3775 55.68 50.55 0.335 57.91 50.36 Third Quarter .......................... 0.3775 60.79 53.70 0.335 62.09 56.50 Fourth Q uarter .......................... 0.3775 70.20 59.00 0.335 62.60 50.40 T otal .................................. $ 1.51 $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 Maximum Number Purchased as of Shares that Part of Publicly May Yet Be Total Number Announced Purchased Under of Shares Average Price Plans or the Plans and Period Purchased Paid for Shares Programs Programs October 1 - October 31, 2006 565 $60.43 November 1 - November 30, 2006 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, exceptper 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 4.05 3.04 2.71 2.69 3.31 Book Value Per Share of Common Stock $ 25.54 $ 27.57 $ 26.81 $ 24.68 $ 23.44 Certainprior-yearamounts have been reclassifiedto conform with the currentyear'spresentation.

(1) Total revenuesfor theyear ended December 31, 2002 include $255.5 million ofgains recognized on the sale ofour outstandingshares 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 andAnalysis.

28

Baltimore Gas and Electric Company and Subsidiaries 2006 2005 2004 2003 2002 (In millions)

Summary of Operations Total Revenues $3,015.4 $3,009.3 $2,724.7 $2,647.6 $2,547.3 Total Expenses 2,646.3 2,612.8 2,353.3 2,262.6 2,181.0 Income From Operations 369.1 396.5 371.4 385.0 366.3 Other Income (Expense) 6.0 5.9 (6.4) (5.4) 10.7 Fixed Charges 102.6 93.5 96.2 111.2 140.6 Income Before Income Taxes 272.5 308.9 268.8 268.4 236.4 Income Taxes 102.2 119.9 102.5 105.2 93.3 Net Income 170.3 189.0 166.3 163.2 143.1 Preference Stock Dividends 13.2 13.2 13.2 13.2 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 3.60 4.22 3.75 3.36 2.66 Ratio of Earnings to Fixed Charges and Preferred and Preference Stock Dividends 2.99 3.45 3.08 2.82 2.31 29

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations Introduction and Overview Strategy Constellation Energy Group, Inc. (Constellation Energy) is an We are pursuing a strategy of providing energy and energy energy company that conducts its business through various related services through our competitive supply activities and subsidiaries including a merchant energy business and Baltimore BGE, our regulated utility located in Matyland. Our merchant Gas and Electric Company (BGE). We describe our operating energy business focuses on short-term and long-term purchases segments in Note 3. and sales of energy, capacity, and related products to various This report is a combined report of Constellation Energy customers, including distribution utilities, municipalities, and BGE. References in this report to "we" and "our" are to cooperatives, and industrial, commercial, and governmental Constellation Energy and its subsidiaries, collectively. References customers.

in this report to the "regulated business (es)" are to BGE. We We obtain this energy through both owned and contracted discuss our business in more detail in Item 1. Business section and supply resources. Our generation fleet is strategically located in the risk factors affecting our business in Item ]A. Risk Factors deregulated markets and includes various fuel types, such as section. nuclear, coal, gas, oil, and renewable sources. In addition to In this discussion and analysis, we will explain the general owning generating facilities, we contract for power from other financial condition and the results of operations for merchant providers, typically through power purchase Constellation Energy and BGE including: agreements. We intend to remain diversified between regulated

• factors which affect our businesses, transmission and distribution and competitive supply. We will

• our earnings and costs in the periods presented, use both our owned generation and our contracted generation to

• changes in earnings and costs between periods, support our competitive supply operations.

• sources of earnings, We are a leading national competitive supplier of energy. In

• impact of these factors on our overall financial our wholesale and commercial and industrial retail marketing condition, activities we are leveraging our recognized expertise in providing

• expected future expenditures for capital projects, and full requirements energy and energy-related services to enter

• expected sources of cash for future capital expenditures. markets, capture market share, and organically grow these As you read this discussion and analysis, refer to our businesses. Through the application of technology, intellectual Consolidated Statements of income, which present the results of capital, process improvement, and increased scale, we are seeking our operations for 2006, 2005, and 2004. We analyze and to reduce the cost of delivering full requirements energy and explain the differences between periods in the specific line items energy related services and managing risk.

of our Consolidated Statements of Income. . We are also responding proactively to customer needs by We have organized our discussion and analysis as follows: expanding the variety of products we offer. Our wholesale

• First, we discuss our strategy. competitive supply activities include a growing operation that

• We then describe the business environment in which we markets physical energy products and risk management and operate including how regulation, weather, and other logistics services to generators, distributors, producers of coal, factors affect our business. natural gas and fuel oil, and other consumers.

• Next, we discuss our critical accounting policies. These We trade energy and energy-related commodities and are the accounting policies that are most important to deploy risk capital in the management of our portfolio in order both the portrayal of our financial condition and results to earn additional returns. These activities are managed through of operations and require management's most difficult, daily value at risk and stop loss limits and liquidity guidelines.

subjective or complex judgment. Within our retail competitive supply activities, we are

• We highlight significant events that are important to marketing a broader array of products and expanding our understanding our results of operations and financial markets. Over time, we may consider integrating the sale of condition. electricity and natural gas to provide one energy procurement

• We then review our results of operations beginning with solution for our customers.

an overview of our total company results, followed by a Collectively, the integration of owned and contracted more detailed review of those results by operating electric generation assets with origination, fuel procurement, and segment. risk management expertise, allows our merchant energy business

• We review our financial condition addressing our sources to earn incremental margin and more effectively manage energy and uses of cash, security ratings, capital resources, and commodity price risk over geographic regions and over time.

capital requirements, commitments, and off-balance Our focus is on providing solutions to customers' energy needs, sheet arrangements. and our wholesale marketing, risk management, and trading

• We conclude with a discussion of our exposure to operation adds value to our owned and contracted generation various market risks. 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.

30

To achieve our strategic objectives, we expect to continue deregulation have slowed their plans or postponed consideration.

to pursue opportunities that expand our access to customers and In addition, other states are reconsidering deregulation.

to support our wholesale marketing, risk management, and All BGE electricity and gas customers have the option to trading operation with generation assets that have diversified purchase electricity and gas from alternate suppliers.

geographic, fuel, and dispatch characteristics. We also expect to We discuss merchant competition in more detail in Item 1.

grow through buying and selling a greater number of physical Business-Competition section.

energy products and services to large energy customers. We The impacts of electric deregulation on BGE in Maryland expect to achieve operating efficiencies within our competitive are discussed in Item 1. Business-ElectricRegulatory Matters and supply operation and our generation fleet by selling more Competition section.

products through our existing sales force, benefiting from efficiencies of scale, adding to the capacity of existing plants, and Regulation- Senate Bill I making our business processes more efficient. In June 2006, Senate Bill 1 was enacted, which, among other We expect BGE and our other retail energy service things:

businesses to grow through focused and disciplined expansion

• directs the Maryland PSC to conduct a comprehensive primarily from new customers. At BGE, we are also focused on review of Maryland's deregulated electricity market, enhancing reliability and customer satisfaction. including the implications of requiring or allowing Customer choice, regulatory change, and energy market utilities to construct, acquire, or lease power generating conditions significantly impact our business. In response, we facilities and alternative approaches to power regularly evaluate our strategies with these goals in mind: to procurement; improve our competitive position, to anticipate and adapt to the # expands the authority of the Maryland PSC to review business environment and regulatory changes, and to maintain a acquisitions, dispositions, and financings by public strong balance sheet and investment-grade credit quality. service companies operating in Maryland; and We are constantly reevaluating our strategies and might

• directs Maryland's taxing authority to consider whether consider: property tax valuation methodologies applied to power

• acquiring or developing additional generating facilities plants located in Maryland should be revised in light of and gas properties to support our merchant energy the values of those properties in a restructured electric business, industry.

• mergers or acquisitions of utility or non-utility businesses Because Senate Bill 1 requires additional decisions and or assets, and proceedings by the Maryland PSC and other governmental

• sale of assets or one or more businesses. authorities to implement and interpret many of its provisions, we cannot predict the ultimate impact of the legislation on us, BGE, Business Environment or the energy market in Maryland. The new legislation and its With the evolving regulatory environment surrounding customer implementation through applicable regulatory proceedings could choice, increasing competition, and the growth of our merchant have a material adverse effect on our, or BGE's, financial results.

energy business, various factors affect our financial results. We In addition, one or more parties may challenge in court one or discuss some of these factors in more detail in the Item 1. more provisions of Senate Bill 1. The outcome of any challenges Business--Competitionsection. We also discuss these various and the uncertainty that could result cannot be predicted.

factors in the ForwardLooking Statements and Item MA.Risk We discuss the provisions of Senate Bill 1 relating to Factors sections. residential electric customer rates in Item 1. Business-Electric Over the last several years, the energy markets have been Regulatory Matters and Competition section.

highly volatile with significant changes in natural gas, power, oil, coal, and emission allowance prices. The volatility of the energy Regulation by the Maryland PSC markets impacts our credit portfolio, and we continue to actively In addition to electric restructuring, which is discussed in Item 1.

manage our credit portfolio to attempt to reduce the impact of a Business-ElectricRegulatory Matters and Competition section, potential counterparty default. We discuss our customer regulation by the Maryland PSC significantly influences BGE's (counterparty) credit and other risks in more detail in the Market businesses. The Maryland PSC determines the rates that BGE Risk section. can charge customers of its electric distribution and gas In addition, the volatility of the energy markets impacts our businesses. The Maryland PSC incorporates into BGE's standard liquidity and collateral requirements. We discuss our liquidity in offer service rates the transmission rates determined by the the FinancialCondition section. Federal Energy Regulatory Commission (FERC). BGE's electric rates are unbundled in customer billings to show separate Competition components for delivery service (i.e. base rates), electric supply We face competition in the sale of electricity, natural gas, and (commodity charge), transmission, a universal service surcharge, coal in wholesale energy markets and to retail customers. and certain taxes. The rates for BGE's regulated gas business Various states have moved to restructure their electricity continue to consist of a delivery charge (base rate) and a markets. The pace of deregulation in these states varies based on commodity charge.

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 31

Base Rates oversight. Our merchant energy business participates in these Base rates are the rates the Maryland PSC allows BGE to charge regional energy markets. These markets are continuing to its customers for the cost of providing them delivery service, plus develop, and revisions to market structure are subject to review a profit. BGE has both electric base rates and gas base rates. and approval by FERC. We cannot predict the outcome of any Higher electric base rates apply during the summer when the reviews at this time. However, changes to the structure of these demand for electricity is higher. Gas base rates are not affected by markets could have a material effect on our financial results.

seasonal changes. Ongoing initiatives at FERC have included a review of its BGE may ask the Maryland PSC to increase base rates from methodology for the granting of market-based rate authority to time to time. The Maryland PSC historically has allowed BGE to sellers of electricity. FERC has announced interim tests that will increase base rates to recover its utility plant investment and be used to determine the extent to which companies may have operating costs, plus a profit. Generally, rate increases improve market power in certain regions. Where market power is found the earnings of our regulated business because they allow us to to exist, FERC may require companies to implement measures to collect more revenue. However, rate increases are normally mitigate the market power in order to maintain market-based granted based on historical data and those increases may not rate authority. In addition, FERC is reviewing other aspects of its always keep pace with increasing costs. Other parties may granting of market-based rate authority, including horizontal and petition the Maryland PSC to decrease base rates. vertical market power, affiliate abuse, and barriers to entry. We In December 2005, the Maryland PSC issued an order cannot determine the eventual outcome of FERC's efforts in this granting BGE a $35.6 million annual increase in its gas base regard and their impact on our financial results at this time.

rates. In December 2006, the Baltimore City Circuit Court In November 2004, FERC eliminated through and out upheld the rate order. However, certain parties have filed an transmission rates between the Midwest Independent System appeal with the Court of Special Appeals. We cannot provide Operator (MISO) and PJM and put in place Seams Elimination assurance that the Maryland PSC's order will not be reversed in Charge/Cost Adjustment/Assignment (SECA) transition rates, whole or part or that certain issues will not be remanded to the which are paid by the transmission customers of MISO and PJM Maryland PSC for reconsideration. and allocated among the various transmission owners in PJM and MISO. The SECA transition rates were in effect from Electric Commodity and Transmission Charges December 1, 2004 through March 31, 2006. FERC set for BGE electric commodity and transmission charges (standard hearing the various compliance filings that established the level offer service), including the enactment of Senate Bill 1 in of the SECA rates and has indicated that the SECA rates are Maryland, are discussed in Item 1. Business-ElectricRegulatory being recovered from the MISO and PJM transmission Matters and Competition section. customers subject to refund by the MISO and PJM transmission Gas Commodity Charge owners.

In addition, FERC provided transmission customers that BGE charges its gas customers separately for the natural gas they are charged the SECA rates with an opportunity to demonstrate purchase. The price BGE charges for the natural gas is based on a market-based rates incentive mechanism approved by the that such charges should be shifted to their wholesale power Maryland PSC. We discuss market-based rates in more detail in suppliers. We are a recipient of SECA payments, payer of SECA the Regulated Gas Business-Gas CostAdjustments section and in charges, and supplier to whom such charges may be shifted.

Note 6. Administrative hearings regarding the SECA charges concluded in May 2006, and an initial decision from the FERC Federal Regulation administrative law judge (ALJ) was issued in August 2006. The FERC decision of the ALJ generally found in favor of reducing the The FERC has jurisdiction over various aspects of our business, overall SECA liability. The decision, if upheld, is expected to including electric transmission and wholesale natural gas and significantly reduce the overall SECA liability at issue in this electricity sales. We believe that FERC's continued commitment proceeding. However, the ALJ also allowed SECA charges to be to fair and efficient wholesale energy markets should continue to shifted to upstream suppliers, subject to certain adjustments.

result in improvements to competitive markets across various Therefore, certain charges could be shifted to our wholesale regions. marketing, risk management, and trading operation. This Since 1997, operation of BGE's transmission system has decision will be reviewed by FERC. We are unable to predict the been under the authority of PJM Interconnection (PJM), the timing or final outcome of FERC's SECA rate proceeding.

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

transmission owners, including BGE, and power generators is In April 2006, FERC issued an initial order approving limited to those damages caused by the gross negligence of such PJM's proposal to restructure its capacity market. Such a entities. restructuring would change how we are paid for generating plant In addition to PJM, RTOs exist in other regions of the capacity available to PJM. However, FERC found that certain country such as the Midwest, New York, and New England. In elements of the proposal needed further development before addition to operation of the transmission system and FERC could issue a final order and encouraged the parties to the responsibility for transmission system reliability, these RTOs also proceeding, including Constellation Energy, to continue to seek operate energy markets for their region pursuant to FERC's a negotiated resolution of the remaining issues. Subsequently, 32

settlement discussions were conducted among the parties that BGE resulted in a settlement being approved by FERC in Weather affects the demand for electricity and gas for our December 2006, subject to requests for rehearing and potential regulated businesses. Very hot summers and very cold winters further judicial review. Currently, we cannot predict with increase demand. Mild weather reduces demand. Weather affects certainty the capacity prices that will result from the residential sales more than commercial and industrial sales, restructuring, given that rules must still be developed, or the which are mostly affected by business needs for electricity and possible effect such prices will have on our, or BGE's, financial gas. The Maryland PSC approved a revenue decoupling results. mechanism which allows BGE to record a monthly adjustment In February 2007, FERC adopted Order No. 890, which to our regulated gas business revenues to eliminate the effect of reforms the open-access transmission regulatory framework. We abnormal weather patterns. We discuss this further in the are in the process of evaluating this rule and its possible effect on Regulated Gas Business-Revenue Decoupling section.

our, or BGE's, financial results.

Other market changes are routinely proposed and Other Factors considered on an ongoing basis. Such changes will be subject to A number of other factors significantly influence the level and FERC's review and approval. We cannot predict the outcome of volatility of prices for energy commodities and related derivative these proceedings or the possible effect on our, or BGE's, products for our merchant energy business. These factors financial results at this time. include:

• seasonal, daily, and hourly changes in demand, FederalEnergyLegislation

• number of market participants, The Energy Policy Act of 2005 (EPACT 2005) was enacted in

• extreme peak demands, August 2005. The legislation encourages investments in energy

• available supply resources, production and delivery infrastructure, including further

• transportation and transmission availability and development of competitive wholesale energy markets, and reliability within and between regions, promotes the use of a diverse mix of fuels and renewable

• location of our generating facilities relative to the technologies to generate electricity, including federal support and location of our load-serving obligations, tax incentives for clean coal, nuclear, and renewable power

• implementation of new market rules governing generation. Effective February 2006, the legislation repealed the operations of regional power pools, Public Utility Holding Company Act of 1935 (PUHCA 1935). + procedures used to maintain the integrity of the physical In addition, EPACT 2005 significantly increased FERC's electricity system during extreme conditions, enforcement authority. There have been a number of FERC

• changes in the nature and extent of federal and state rulemaking proceedings that relate to the implementation of regulations, and EPACT 2005 including proceedings relating to FERC's new 4 international supply and demand.

responsibilities following the repeal of PUHCA 1935, its revised These factors can affect energy commodity and derivative merger authority, its new authority over electric grid reliability, prices in different ways and to different degrees. These effects and its new authority with respect to addressing electric and gas may vary throughout the country as a result of regional market manipulation. FERC has moved expeditiously to differences in:

implement its new authority under EPACT 2005 and has

• weather conditions, completed many of its rulemaking proceedings under EPACT

• market liquidity, 2005. Additional rulemaking remains to be completed, which

• capability and reliability of the physical electricity and could have a material impact on our, or BGE's, financial results. gas systems, There are also rulemakings required from other federal

• local transportation systems, and agencies, the outcome of which could affect our financial results,

• the nature and extent of electricity deregulation.

but we cannot at this time predict such outcome or the actual Other factors also impact the demand for electricity and gas effect on our financial results. in our regulated businesses. These factors include the number of customers and usage per customer during a given period. We use Weather these terms later in our discussions of regulated electric and gas Merchant Energy Business operations. In those sections, we discuss how these and other Weather conditions in the different regions of North America factors affected electric and gas sales during the periods influence the financial results of our merchant energy business. presented.

Weather conditions can affect the supply of and demand for The number of customers in a given period is affected by electricity, gas, and fuels. Changes in energy supply and demand new home and apartment construction and by the number of may impact the price of these energy commodities in both the businesses in our service territory.

spot market and the forward market, which may affect our Usage per customer refers to all other items impacting results in any given period. Typically, demand for electricity and customer sales that cannot be measured separately. These factors its price are higher in the summer and the winter, when weather include the strength of the economy in our service territory.

is more extreme. The demand for and price of natural gas and oil When the economy is healthy and expanding, customers tend to are higher in the winter. However, all regions of North America consume more electricity and gas. Conversely, during an typically do not experience extreme weather conditions at the economic downturn, our customers tend to consume less same time, thus we are not typically exposed to the effects of electricity and gas.

extreme weather in all parts of our business at once.

33

Environmental Matters and Legal Proceedings recognition of earnings from these transactions. We make these We discuss details of our environmental matters in Note 12 and elections because we believe that accrual accounting provides the Item 1. Business-EnvironmentalMatters section. We discuss most transparent presentation to our shareholders of these details of our legal proceedings in Note 12. Some of this business activities. If our commercial transactions or related information is about costs that may be material to our financial hedges meet the definition of a derivative, we must comply with results. the provisions of SFAS No. 133 in order to use cash-flow hedge accounting or the normal purchase and normal sale exception.

Accounting Standards Adopted and Issued Qualifying for either of these accounting treatments requires We discuss recently adopted and issued accounting standards in ongoing compliance with specific, detailed documentation and Note 1. other requirements that may be unrelated to the economics of the transactions or how the associated risks are managed. While Critical Accounting Policies we believe we have appropriate controls in place to comply with Our discussion and analysis of financial condition and results of these requirements, the failure to meet all of those requirements, operations is based on our consolidated financial statements that even inadvertently, may result in disqualifying the use of these were prepared in accordance with accounting principles generally accounting treatments for those transactions for any affected accepted in the United States of America. Management makes period until all such requirements are satisfied. 0 estimates and assumptions when preparing financial statements.

The exercise of management's judgment in using cash-flow These estimates and assumptions affect various matters, hedge accounting or electing the normal purchase and sale including: exception versus mark-to-market accounting, including

• our reported amounts of revenues and expenses in our compliance with all of the associated qualification and Consolidated Statements of Income, documentation requirements, materially impacts our financial

• our reported amounts of assets and liabilities in our results with respect to timing of the recognition of earnings. In Consolidated Balance Sheets, and addition, interpretations of SFAS No. 133 could continue to

• our disclosure of contingent assets and liabilities.

evolve. If there is a future change in interpretation or a failure to These estimates involve judgments with respect to meet the qualification and documentation requirements, numerous factors that are difficult to predict and are beyond contracts that currently are excluded from the provisions of SFAS management's control. As a result, actual amounts could No. 133 under the normal purchase and normal sale exception materially differ from these estimates.

or for which changes in fair value are recorded in other Management believes the following accounting policies comprehensive income under cash-flow hedge accounting could represent critical accounting policies as defined by the Securities be deemed to no longer qualify for those accounting treatments.

and Exchange Commission (SEC). The SEC defines critical If that were to occur, normal purchase and normal sale contracts accounting policies as those that are both most important to the could be required to be recorded on the balance sheet at fair portrayal of a company's financial condition and results of value with changes in value recorded in the income statement, operations and require management's most difficult, subjective, and changes in value of derivatives previously designated as cash-or complex judgment, often as a result of the need to make flow hedges could be required to be recorded in the income estimates about the effect of matters that are inherently uncertain statement rather than in other comprehensive income.

and may change in subsequent periods. We discuss our We record revenues and fuel and purchased energy significant accounting policies, including those that do not expenses from the sale or purchase of energy, energy-related require management to make difficult, subjective, or complex products, and energy services under the accrual method of judgments or estimates, in Note 1. accounting in the period when we deliver or receive energy Accounting for Derivatives commodities, products, and services, or settle contracts. We use Our merchant energy business originates and acquires contracts accrual accounting for our merchant energy and other nonregulated business transactions, including the generation or for energy, other energy-related commodities, and related purchase and sale of electricity, gas, and coal as part of our derivatives. We record merchant energy business revenues using physical delivery activities and for power, gas, and coal sales two methods of accounting: accrual accounting and mark-to-market accounting. The accounting requirements for derivatives contracts that are not subject to mark-to-market accounting.

are governed by Statement of Financial Accounting Standard Contracts that are eligible for accrual accounting include non-(SFAS) No. 133, Accounting for Derivative Instruments and derivative transactions and derivatives that qualify for and are HedgingActivities, as amended, and applying those requirements designated as normal purchases and normal sales of commodities involves the exercise of judgment in evaluating these provisions, that will be physically delivered.

as well as related implementation guidance and applying those The use of accrual accounting requires us to analyze contracts to determine whether they are non-derivatives or, if requirements to complex contracts in a variety of commodities they are derivatives, whether they meet the requirements for and markets.

Many fundamental customer contracts in our business, designation as normal purchases and normal sales. For those derivative contracts that do not meet these criteria, we may also such as those associated with our load-serving activities, must be accounted for on an accrual basis. We may economically hedge analyze whether they qualify for hedge accounting, including these contracts with derivatives and elect cash-flow hedge performing an evaluation of historical market price information accounting or apply the normal purchase and normal sale to determine whether such contracts are expected to be highly exception in order to match more closely the timing of the 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 absence of observable market information, there is a liabilities." presumption that the transaction price is equal to the We use the mark-to-market method of accounting for market value of the contract, and therefore we do not derivative contracts for which we do not elect to use accrual recognize a gain or loss at inception. We recognize such accounting or hedge accounting. These mark-to-market activities gains or losses in earnings as we realize cash flows under include derivative contracts for energy and other energy-related the contract or when observable market data becomes commodities. Under the mark-to-market method of accounting, available.

we record the fair value of these derivatives as mark-to-market

• Credit-spread adjustment-for risk management energy assets and liabilities at the time of contract execution. We purposes, we compute the value of our mark-to-market record the changes in mark-to-market energy assets and liabilities energy assets and liabilities using a risk-free discount rate.

in our Consolidated Statements of Income. In order to compute fair value for financial reporting Mark-to-market energy assets and liabilities consist of a purposes, we adjust the value of our mark-to-market combination of energy and energy-related derivative contracts. energy assets to reflect the credit-worthiness of each While some of these contracts represent commodities or counterparty based upon either published credit ratings, instruments for which prices are available from external sources, or equivalent internal credit ratings and associated other commodities and certain contracts are not actively traded default probability percentages. We compute this and are valued using modeling techniques to determine expected adjustment by applying a default probability percentage future market prices, contract quantities, or both. The market to our outstanding credit exposure, net of collateral, for prices and quantities used to determine fair value reflect each counterparty. The level of this adjustment increases management's best estimate considering various factors. as our credit exposure to counterparties increases, the However, future market prices and actual quantities will vary maturity terms of 'ur transactions increase, or the credit from those used in recording mark-to-market energy assets and ratings of our counterparties deteriorate, and it decreases liabilities, and it is possible that such variations could be when our credit exposure to counterparties decreases, the material. maturity terms of our transactions decrease, or the credit We record valuation adjustments to reflect uncertainties ratings of our counterparties improve.

associated with certain estimates inherent in the determination of Market prices for energy and energy-related commodities the fair value of mark-to-market energy assets and liabilities. The vary based upon a number of factors, and changes in market effect of these uncertainties is not incorporated in market price prices affect both the recorded fair value of our mark-to-market information or other market-based estimates used to determine energy contracts and the level of future revenues and costs fair value of our mark-to-market energy contracts. To the extent associated with accrual-basis activities. Changes in the value of possible, we utilize market-based data together with quantitative our mark-to-market energy contracts will affect our earnings in methods for both measuring the uncertainties for which we the period of the change, while changes in forward market prices record valuation adjustments and determining the level of such related to accrual-basis revenues and costs will affect our earnings adjustments and changes in those levels. in future periods to the extent those prices are realized. We We describe below the main types of valuation adjustments cannot predict whether, or to what extent, the factors affecting we record and the process for establishing each. Generally, market prices may change, but those changes could be material increases in valuation adjustments reduce our earnings, and and could affect us either favorably or unfavorably. We discuss decreases in valuation adjustments increase our earnings. our market risk in more detail in the Market Risk section.

However, all or a portion of the effect on earnings of changes in The impact of derivative contracts on our revenues and valuation adjustments may be offset by changes in the value of costs is material and is affected by many factors, including:

the underlying positions. + our ability to continue to designate and qualify derivative

• Close-out adjustment-represents the estimated cost to contracts for normal purchase and normal sale close out or sell to a third-party open mark-to-market accounting or hedge accounting under the requirements positions. This valuation adjustment has the effect of of SFAS No. 133, as amended and as interpreted in valuing "long" positions (the purchase of a commodity) supplemental guidance, at the bid price and "short" positions (the sale of a

• potential volatility in earnings from ineffectiveness commodity) at the offer price. We compute this associated with derivatives subject to hedge accounting, adjustment using a market-based estimate of the

• potential volatility in earnings from derivative contracts bid/offer spread for each commodity and option price that serve as economic hedges but do not meet the and the absolute quantity of our net open positions for accounting requirements to qualify for normal purchase each year. The level of total close-out valuation and normal sale accounting or hedge accounting, adjustments increases as we have larger unhedged

• our ability to enter into new mark-to-market derivative positions, bid-offer spreads increase, or market origination transactions, and information is not available, and it decreases as we

• sufficient liquidity and transparency in the energy reduce our unhedged positions, bid-offer spreads markets to permit us to record gains at inception of new decrease, or market information becomes available. To derivative contracts because fair value is evidenced by the extent that we are not able to obtain observable quoted market prices, current market transactions, or market information for similar contracts, the close-out other observable market information.

adjustment is equivalent to the initial contract margin, thereby resulting in no gain or loss at inception. In the 35

As discussed in Note 1, the Financial Accounting Standards market prices and project costs could vary from the assumptions Board (FASB) issued SFAS No. 157, Fair Value Measurements, used in our estimates, and the impact of such variations could be which is effective January 1, 2008 and will affect our accounting material.

for derivatives. SFAS No. 157 defines fair value, establishes a For long-lived assets that can be classified as assets held for framework for measuring fair value, and expands disclosures for sale under SFAS No. 144, an impairment loss is recognized to fair value measurements. the extent their carrying amount exceeds their fair value less costs to sell.

Evaluation of Assets for Impairment and Other Than If we determine that the undiscounted cash flows from an Temporary Decline in Value asset to be held and used are less than the carrying amount of the Long-Lived Assets asset, or if we have classified an asset as held for sale, we must We are required to evaluate certain assets that have long lives (for estimate fair value to determine the amount of any impairment example, generating property and equipment and real estate) to loss. The estimation of fair value under SFAS No. 144, whether determine if they are impaired when certain conditions exist. in conjunction with an asset to be held and used or with an asset SFAS No. 144, Accounting for the Impairment or Disposal ofLong- held for sale, also involves judgment. We consider quoted market LivedAssets, provides the accounting requirements for prices in active markets to the extent they are available. In the impairments of long-lived assets. We are required to test our absence of such information, we may consider prices of similar long-lived assets for recoverability whenever events or changes in assets, consult with brokers, or employ other valuation circumstances indicate that their carrying amount may not be techniques. Often, we will discount the estimated future cash recoverable. Examples of such events or changes are: flows associated with the asset using a single interest rate that is

• a significant decrease in the market price of a long-lived commensurate with the risk involved with such an investment or asset, employ an expected present value method that

• a significant adverse change in the manner an asset is probability-weights a range of possible outcomes. The use of being used or its physical condition, these methods involves the same inherent uncertainty of future

• an adverse action by a regulator or legislature or an cash flows as discussed above with respect to undiscounted cash adverse change in the business climate, flows. Actual future market prices and project costs could vary

• an accumulation of costs significantly in excess of the from those used in our estimates, and the impact of such amount originally expected for the construction or variations could be material.

acquisition of an asset, We are also required to evaluate our equity-method and

• a current-period loss combined with a history of losses or cost-method investments (for example, in partnerships that own the projection of future losses, or power projects) to determine whether or not they are impaired.

• a change in our intent about an asset from an intent to Accounting Principles Board (APB) Opinion No. 18, The Equity hold to a greater than 50% likelihood that an asset will Method ofAccounting for Investments in Common Stock, provides be sold or disposed of before the end of its previously the accounting requirements for these investments. The standard estimated useful life. for determining whether an impairment must be recorded under For long-lived assets that are expected to be held and used, APB No. 18 is whether the investment has experienced a loss in SFAS No. 144 provides that an impairment loss shall only be value that is considered an "other than a temporary" decline in recognized if the carrying amount of an asset is not recoverable value.

and exceeds its fair value. The carrying amount of an asset is not The evaluation and measurement of impairments under the recoverable under SFAS No. 144 if the carrying amount exceeds APB No. 18 standard involves the same uncertainties as the sum of the undiscounted future cash flows expected to result described above for long-lived assets that we own directly and from the use and eventual disposition of the asset. Therefore, account for in accordance with SFAS No. 144. Similarly, the when we believe an impairment condition may have occurred, estimates that we make with respect to our equity and cost-we are required to estimate the undiscounted future cash flows method investments are subject to variation, and the impact of associated with a long-lived asset or group of long-lived assets at such variations could be material. Additionally, if the projects in the lowest level for which identifiable cash flows are largely which we hold these investments recognize an impairment under independent of the cash flows of other assets and liabilities. This the provisions of SFAS No. 144, we would record our necessarily requires us to estimate uncertain future cash flows. proportionate share of that impairment loss and would evaluate In order to estimate future cash flows, we consider our investment for an other than temporary decline in value historical cash flows and changes in the market environment and under APB No. 18.

other factors that may affect future cash flows. To the extent applicable, the assumptions we use are consistent with forecasts Gas Properties that we are otherwise required to make (for example, in We evaluate unproved property at least annually to determine if preparing our other earnings forecasts). If we are considering it is impaired under SFAS No. 19, FinancialAccountingand alternative courses of action to recover the carrying amount of a Reporting by Oil and Gas ProducingProperties.Impairment for long-lived asset (such as the potential sale of an asset), we unproved property occurs if there are no firm plans to continue probability-weight the alternative courses of action to estimate drilling, lease expiration is at risk, or historical experience the cash flows. 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, and operating costs. However, actual future 36

Debt and Equity Securities retirement. We utilize site-specific decommissioning cost Our investments in debt and equity securities, primarily our estimates to determine our nuclear asset retirement obligations.

nuclear decommissioning trust fund assets, are subject to However, given the magnitude of the amounts involved, impairment evaluations under FASB Staff Position SFAS 115-1 complicated and ever-changing technical and regulatory and SFAS 124-1 (FSP 115-1 and 124-1), The Meaning of requirements, and the very long time horizons involved, the Other- Than-Temporary Impairment and Its Application to actual obligation could vary from the assumptions used in our CertainInvestments. FSP 115-1 and 124-1 requires us to estimates, and the impact of such variations could be material.

determine whether a decline in fair value of an investment below the amortized cost basis is other than temporary. If we Significant Events determine that the decline in fair value is judged to be other Termination of Merger Agreement with FPL Group, Inc.

than temporary, the cost basis of the investment must be On October 24, 2006, Constellation Energy and FPL written down to fair value as a new cost basis. Group, Inc. (FPL Group) agreed to terminate the Agreement and Plan of Merger the parties had entered into on Goodwill December 18, 2005. We discuss the merger termination Goodwill is the excess of the purchase price of an acquired agreement in more detail in Note 15.

business over the fair value of the net assets acquired. We account for goodwill and other intangibles under the provisions Commodity Prices of SFAS No. 142, Goodwill and Other Intangible Assets. We do During 2006, we continued to experience significant changes not amortize goodwill. SFAS No. 142 requires us to evaluate in commodity prices. This volatile commodity price goodwill for impairment at least annually or more frequently if environment continues to impact our results of operations and events and circumstances indicate the business might be financial conditions. This volatility contributed to the impaired. Goodwill is impaired if the carrying value of the following changes in our financial statements:

business exceeds fair value. Annually, we estimate the fair value

• total mark-to-market assets decreased $510.3 million of the businesses we have acquired using techniques similar to and total mark-to-market liabilities decreased those used to estimate future cash flows for long-lived assets as $796.9 million since December 31, 2005, discussed on the previous page, which involves judgment. If the

• total risk management assets decreased estimated fair value of the business is less than its carrying $1,282.9 million and total risk management liabilities value, an impairment loss is required to be recognized to the increased $528.3 million since December 31, 2005, extent that the carrying value of goodwill is greater than its fair

• net cash collateral requirements increased $630.6 value. million since December 31, 2005,

• accumulated other comprehensive loss increased Asset Retirement Obligations $1,088.1 million since December 31, 2005, We incur legal obligations associated with the retirement of

• total revenues increased $2,316.6 million during 2006 certain long-lived assets. SFAS No. 143, Accountingfor Asset compared to 2005, and Retirement Obligations,provides the accounting for legal

• total fuel and purchased energy expenses increased obligations associated with the retirement of long-lived assets. $1,691.1 million during 2006 compared to 2005.

We incur such legal obligations as a result of environmental We discuss the impact of commodity prices on our and other government regulations, contractual agreements, and financial condition and results of operations in more detail in other factors. The application of this standard requires the following sections:

significant judgment due to the large number and diverse

• MerchantEnergy Results, nature of the assets in our various businesses and the estimation

• FinancialCondition, of future cash flows required to measure legal obligations

• ContractualPayment Obligationsand Committed associated with the retirement of specific assets. FASB Amounts, and Interpretation (FIN) 47, Accountingfor ConditionalAsset

• Market Risk.

Retirement Obligations-an interpretationofFASB Statement No. 143, clarifies that obligations that are conditional upon a Residential Electric Rates future event are subject to the provisions of SFAS No. 143. We discuss Senate Bill 1 enacted by the Maryland General SFAS No. 143 requires the use of an expected present Assembly in more detail in the Item 1. Business-Electric value methodology in measuring asset retirement obligations Regulatory Matters and Competition and Regulation sections.

that involves judgment surrounding the inherent uncertainty of the probability, amount and timing of payments to settle these Gas-Fired Plants obligations, and the appropriate interest rates to discount In December 2006, we completed the sale of several gas-fired future cash flows. We use our best estimates in identifying and plants for $1.6 billion in cash, and recognized a pre-tax gain on measuring our asset retirement obligations in accordance with the sale of $259.0 million, or $163.8 million after-tax. We SFAS No. 143. discuss the sale in more detail in Note 2.

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 37

Synthetic Fuel Facilities Workforce Reduction Costs Our merchant energy business has investments in facilities that During the quarter ended March 31, 2006, we incurred costs manufacture solid synthetic fuel produced from coal as defined associated with a planned workforce restructuring at our under the Internal Revenue Code (IRC) for which we can R. E. Ginna Nuclear Power Plant (Ginna). In July 2006, we claim tax credits on our Federal income tax return through announced a planned workforce restructuring at our Nine Mile 2007. The IRC provides for a phase-out of synthetic fuel tax Point Nuclear Station (Nine Mile Point). We also initiated a credits if average annual wellhead oil prices increase above restructuring of the workforce at our Calvert Cliffs nuclear certain levels. For 2006, we estimate the tax credit reduction facility during the third quarter of 2006.

would begin if the reference price exceeds approximately $55 In addition, during 2006, we recorded a settlement charge per barrel and would be fully phased-out if the reference price in our Consolidated Statements of Income for one of our exceeds approximately $68 per barrel. We discuss how we qualified plans under SFAS No. 88, Employers'Accountingfor determine the amount of phase-out in more detail in Note 10. Settlements and CurtailmentsofDefined Benefit Pension Plans Based on monthly EIA published wellhead oil prices for andfor Termination Benefits.

the ten months ended October 31, 2006 and November and We discuss these restructurings and the settlement charge December NYMEX prices for light, sweet, crude oil (adjusted in more detail in Note 2.

for the 2006 difference between EIA and NYMEX prices), we estimate a 38% tax credit phase-out in 2006. We recorded the Acquisitions effect of this phase-out estimate as a reduction in tax credits of During 2006, we acquired working interests in gas and oil

$44.3 million during 2006. producing fields. We discuss this acquisition in more detail in For 2007, we estimate the tax credit reduction would the Note 15.

begin if the reference price exceeds approximately $56 per barrel and would be fully phased-out if the reference price Initial Public Offering of Constellation Energy Partners exceeds approximately $70 per barrel. Based on forward market LLC prices and volatilities as of February 22, 2007, we estimate a In November 2006, Constellation Energy Partners LLC (CEP),

21% tax credit phase-out in 2007. However, the ultimate a limited lidbility company formed by Constellation Energy, amount of tax credits phased-out for 2007 is subject to change completed its initial public offering of common units. CEP is based on the actual reference price and production levels for the principally engaged in the acquisition, development, and entire year. In addition, our ability to claim synthetic fuel tax exploitation of natural gas properties. CEP's existing property is credits and the potential phase-out of these credits could be located in the Robinson's Bend Field in the Black Warrior materially impacted by any future legislative changes to the Basin of Alabama.

Internal Revenue Code. We discuss the impact of this initial public offering on We actively monitor and manage our exposure to our financial results in more detail in Note 2.

synthetic fuel tax credit phase-out as part of our ongoing hedging activities. In addition, we continue to monitor various Nine Mile Point License Extension options related to our South Carolina facility, including the In October 2006, we received Nuclear Regulatory Commission suspension or cessation of synthetic fuel production depending approval for license extension for both units at our Nine Mile on our expectation of the level of tax credit phase-out. Point nuclear facility. With the renewed licenses, we can We will continue to monitor the level of synthetic fuel tax continue to operate Unit 1 until 2029 and Unit 2 until 2046.

credit phase-out based on forward market prices and volatilities and perform impairment analyses as warranted. A significant Ginna Uprate increase in synthetic fuel tax credit phase-out could result in an During the fourth quarter of 2006, we completed a planned impairment. At December 31, 2006, the book value of our outage at our Ginna nuclear facility, which included an uprate investment in synthetic fuel facilities is approximately $14 of the plant from 498 megawatts to 581 megawatts. We expect million, substantially all of which is related to our South that the increase in capacity of the facility will result in higher Carolina facility. 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

• We had higher earnings of $67.7 million after-tax at In this section, we discuss our earnings and the factors affecting our retail competitive supply operation primarily due them. We begin with a general overview, and then separately to an increase in gross margin, partially offset by higher discuss earnings for our operating segments. Significant changes operating expenses to support the growth of this in other income and expense, fixed charges, and income taxes operation. We discuss our retail gross margin in more are discussed in the aggregate for all segments in the detail in the Competitive Supply-Retail section.

ConsolidatedNonoperatingIncome and Expenses section.

• We had higher earnings of approximately $18 million after-tax due to the gain on the CEP initial public Overview offering. This gain was partially offset by cash-flow hedge losses of approximately $10 million after-tax Results reclassified from "Accumulated other comprehensive 2006 2005 2004 income" to revenues as a result of the initial public (In millions, afler-tax) offering. We discuss the CEP transaction in more Merchant energy $580.1 $359.4 $358.0 detail in Note 2.

Regulated electric 120.2 149.4 131.1

• We had higher earnings of $10.3 million after-tax from Regulated gas 37.0 26.7 22.2 our regulated gas business primarily due to the Other nonregulated 11.3 0.4 (12.9) favorable impact of the increase in gas base rates that Income from continuing operations and was approved in December 2005.

before cumulative effects of changes These increases were partially offset by the following:

in accounting principles 748.6 535.9 498.4

• We had lower earnings of $30.1 million after-tax at our Income from discontinued operations 187.8 94.4 41.3 synthetic fuel facilities mostly due to the expected Cumulative effects of changes in phase-out of tax credits as a result of the high price of accounting principles - (7.2) -

oil. We discuss the phase-out of tax credits in more Net Income $936.4 $623.1 $539.7 detail in the Significant Events section.

Other Items Included in Operations:

• We had lower earnings of $29.2 million after-tax from Gain on sale of gas-fired plants $ 47.1 $ - $ - our regulated electric business primarily due to higher Non-qualifting hedges 39.2 (24.9) 0.2 operations and maintenance expenses and lower Workforce reduction costs (17.0) (2.6) (5.9) revenues less electricity purchased for resale expenses.

Merger-related costs (5.7) (15.6) -

• We had lower earnings of $14.4 million after-tax due Recognition of 2003 synthetic fuel to workforce reduction costs associated with workforce tax credits - - 35.9 Total Other Items restructurings at our nuclear generating facilities. We

$ 63.6 $ (43.1) $ 30.2 discuss these costs in more detail in the Note 2.

Certainprior-yearamounts have been reclassified to conform with

• We had lower earnings of approximately $11 million the currentyear'spresentation. after-tax due to higher fixed charges and lower other 2006 income. We discuss these items in more detail in the Our total net income for 2006 increased $313.3 million, or ConsolidatedNonoperatingIncome and Expenses section.

$1.69 per share, compared to 2005 mostly because of the following: 2005

• We had higher earnings of approximately $144 million Our total net income for 2005 increased $83.4 million, or after-tax at our merchant energy business due to higher $0.35 per share, compared to 2004 mostly because of the gross margin from the Mid-Atlantic Region. We following:

discuss this increase in gross margin in more detail in

• We had higher earnings of approximately $58 million the Mid-Atlantic Region section. at our wholesale marketing, risk management, and

• We had higher earnings from discontinued operations trading operation. This increase is primarily due to the of $93.4 million after-tax mostly due to the gain on realization of higher gross margin, which included the sale of our High Desert facility. In addition, we had termination or restructuring of several energy contracts higher earnings of $47.1 million resulting from the and higher mark-to-market results in earnings. We recognition of a gain on sale of five other gas-fired discuss these terminations, restructurings, and mark-to-generating facilities. We discuss the sale of these plants market results in more detail in the Competitive Supply in more detail in Note 2. section. This increase in earnings was partially offset by

• We had higher wholesale competitive supply gross higher load-serving costs resulting from extreme margin of approximately $105 million after-tax. This weather and volatile commodity prices and higher increase was partially offset by approximately operating expenses.

$68 million after-tax of higher operating expenses

• We recorded higher income from discontinued mostly because of higher labor and benefit costs due to operations of $53.1 million after-tax. This increase is the growth of our wholesale competitive supply primarily due to a loss of $49.1 million after tax in operation. We discuss our mark-to-market and 2004 related to the sale of our Hawaiian geothermal wholesale accrual results in more detail in the facility which had a negative impact in that period. We Competitive Supply section. discuss discontinued operations in more detail in Note 2.

39

• We had higher earnings of approximately $34 million Merchant Energy Business after-tax primarily due to higher interest and Background investment income due to a higher cash balance, and Our merchant energy business is a competitive provider of higher decommissioning trust asset earnings, and lower energy solutions for various customers. We discuss the impact interest expense resulting from the maturity of of deregulation on our merchant energy business in Item 1.

$300.0 million in long-term debt in 2005 and the Business-Competitionsection.

favorable impact of floating-rate swaps. Our merchant energy business focuses on delivery of

• We had higher earnings of $29.1 million after-tax at physical, customer-oriented products to producers and our Nine Mile Point and Ginna facilities primarily due consumers, manages the risk and optimizes the value of our to productivity improvements and cost saving owned generation assets, and uses our portfolio management initiatives partially offset by inflationary cost increases and trading capabilities both to manage risk and to deploy risk and costs associated with the planned refueling outage capital to generate additional returns. We continue to identify at Ginna. and pursue opportunities which can generate additional returns

• We had higher earnings of $22.8 million after-tax at through portfolio management and trading activities within our regulated businesses primarily due to favorable our business. These opportunities have increased due to the weather during 2005 compared to 2004. significant growth in scale of our competitive supply

• We had higher earnings of approximately $17 million operations.

after-tax due to the absence of coal delivery issues that We record merchant energy revenues and expenses in our were experienced in 2004 that had a negative impact in financial results in different periods depending upon which that period. portion of our business they affect. We discuss our revenue

• We had higher earnings from our other nonregulated recognition policies in the CriticalAccountingPolicies section businesses of $13.3 million after-tax, including higher and in Note 1. We summarize our revenue and expense gains from the continued liquidation of our non-core recognition policies as follows:

investments and the results of Cogenex, which was + We record revenues as they are earned and fuel and acquired in April 2005. We discuss the acquisition of purchased energy expenses as they are incurred for Cogenex in more detail in Note 15. contracts and activities subject to accrual accounting,

• We had higher earnings at our South Carolina including certain load-serving activities.

synthetic fuel facility of $7.6 million after-tax due to a

• Prior to the settlement of the forecasted transaction higher level of production in 2005 compared to 2004. being hedged, we record changes in the fair value of These increases were partially offset by the following: contracts designated as cash-flow hedges in other

• Our merchant energy business recognized comprehensive income to the extent that the hedges are

$35.9 million of 2003 synthetic fuel tax credits in 2004 effective. We record the effective portion of the which had a positive impact in that period. changes in fair value of hedges in earnings in the period

• We had lower earnings at our retail competitive supply the settlement of the hedged transaction occurs. We operation of $25.1 million after-tax primarily due to record the ineffective portion of the changes in fair higher costs to serve our load obligations in Texas and value of hedges, if any, in earnings in the period in the absence of bankruptcy settlements that had a which the change occurs.

favorable impact in 2004.

• We record changes in the fair value of contracts that

• We had lower earnings of $25.1 million after-tax are subject to mark-to-market accounting in revenues related to losses associated with certain economic or fuel and purchased energy expenses in the period in hedges that do not qualify for cash-flow hedge which the change occurs.

accounting treatment. We discuss these economic Mark-to-market accounting requires us to make estimates hedges in more detail in the Mark-to-Market section. and assumptions using judgment in determining the fair value

• We had lower earnings of $15.6 million after-tax due of certain contracts and in recording revenues from those to external costs associated with the execution of our contracts. We discuss the effects of mark-to-market accounting merger agreement with FPL Group. on our results in the Competitive Supply-Mark-to-Market

• We had lower earnings of $20.0 million after-tax due section. We discuss mark-to-market accounting and the to lower competitive transition charge (CTC) revenues accounting policies for the merchant energy business further in at our merchant energy business. the CriticalAccounting Policies section and in Note 1.

• We had lower earnings of $8.5 million after-tax related Our wholesale marketing, risk management, and trading to the impact of expensing stock options during the operation actively transacts in energy and energy-related fourth quarter of 2005. commodities in order to manage our portfolio of energy

• We had lower earnings of $7.2 million after-tax due to purchases and sales to customers through structured the cumulative effect of adopting FIN 47 and SFAS transactions. As part of these activities we trade energy and No. 123 Revised (SFAS No. 123R), Share-Based energy-related commodities and deploy risk capital in the Payment.We discuss the adoption of these standards in management of our portfolio in order to earn additional detail in Note 1. returns. These activities are managed through daily value at risk Earnings per share was impacted by additional dilution, and stop loss limits and liquidity guidelines, and may have a including the issuance of 6.0 million shares of common stock material impact on our financial results. We discuss the impact on July 1, 2004. of our trading activities and value at risk in more detail in the Competitive Supply--Mark-to-Market and Market Risk sections.

40

Results We analyze our merchant energy gross margin in the 2006 2005 2004 following categories because of the risk profile of each category, (In millions) differences in the revenue sources, and the nature of fuel and Revenues $ 17,166.2 $ 14,622.4 $10,188.3 purchased energy expenses. With the exception of a portion of Fuel and purchased energy our competitive supply activities that we are required to expenses (14,256.3) (12,301.8) (8,118.1) account for using the mark-to-market method of accounting, Operating expenses (1,549.4) (1,346.1) (1,149.9)

Workforce reduction costs (28.2) (4.4) (9.7) all of these activities are accounted for on an accrual basis.

Merger-related transaction costs (13.1) (11.2) -

• Mid-Atlantic Region--our fossil, nuclear, and Depreciation, depletion, and hydroelectric generating facilities and load-serving amortization (258.7) (250.4) (221.9) activities in the PJM Interconnection (PJM) region.

Accretion of asset retirement This also includes active portfolio management of the obligations (67.6) (62.0) (53.1)

Taxes other than income taxes (120.0) (106.7) (83.3) generating assets and other physical and financial Gain on sale of gas-fired plants 73.8 - - contractual arrangements, as well as other PJM Income from Operations $ 946.7 $ 539.8 $ 552.3 competitive supply activities. In addition, due to the Income from continuing expiration of its power purchase agreement, beginning operations and before in June 2006 until its sale in December 2006, the cumulative effects of changes results of our University Park generating facility are in accounting principles (after-tax) $ 580.1 $ 359.4 $ 358.0 included with the Mid-Atlantic Region. University Income from discontinued Park was previously included in Plants with Power operations (after-tax) 186.9 73.8 31.9 Purchase Agreements.

Cumulative effects of changes + Plants with Power Purchase Agreements-our in accounting principles (after-tax) - (7.4) - generating facilities outside the Mid-Atlantic Region Net Income $ 767.0 $ 425.8 $ 389.9 with long-term power purchase agreements. As Other Items Included in Operations discussed in Note 2, the sale of the High Desert facility (after-tax) resulted in a reclassification of its results of operations Gain on sale of gas-fired plants $ 47.1 $ - $ - to discontinued operations.

Non-qualifying hedges 39.2 (24.9) 0.2

• Wholesale Competitive Supply-our marketing, risk Merger-related costs (4.3) (10.4) -

Workforce reduction costs (17.0) (2.6) (5.9) management, and trading operation that provides Recognition of 2003 synthetic energy products and services primarily to distribution fuel tax credits - - 35.9 utilities, power generators, and other wholesale Total Other Items $ 65.0 $ (37.9) $ 30.2 customers. We also provide global energy and related Certainprior-yearamounts have been reclassifiedto conform with services and upstream and downstream natural gas the currentyear's presentation.Above amounts include services.

intercompany transactionseliminated in our Consolidated

• Retail Competitive Supply--our operation that FinancialStatements. Note 3 provides a reconciliationof operating provides electric and gas energy products and services results by segment to our ConsolidatedFinancialStatements. to commercial, industrial, and governmental customers.

Revenues and Fueland PurchasedEn ergy Expenses

• Other-our investments in qualifying facilities and Our merchant energy business manages the revenues we realize domestic power projects and our generation operations from the sale of energy to our customers and our costs of and maintenance services.

procuring fuel and energy. As previously discussed, our In December 2006, we completed the sale of these gas-merchant energy business uses either accrual or mark-to-market fired plants:

accounting to record our revenues and expenses. Mark-to-market results reflect the net impact of amounts recorded in Capacity either revenues or fuel and purchased energy expenses to Facility (MV) Unit Type Location recognize changes in fair value of derivative contracts subject to High Desert 830 Combined Cycle California mark-to-market accounting during the reporting period. Rio Nogales 800 Combined Cycle Texas The difference between revenues and fuel and purchased Holland 665 Combined Cycle Illinois energy expenses, including all direct expenses, is the gross University margin of our merchant energy business, and this measure is a Park 300 Peaking Illinois useful tool for assessing the profitability of our merchant energy Big Sandy 300 Peaking West Virginia business. Accordingly, we believe it is appropriate to discuss the Wolf Hills 250 Peaking Virginia operating results of our merchant energy business by analyzing We discuss the sale of these gas-fired generating facilities the changes in gross margin between periods. In managing our in Note 2.

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.

41

We provide a summary of our revenues, fuel and Deregulationand Competition section. Our wholesale purchased energy expenses, and gross margin as follows: marketing, risk management, and trading operation served fixed-price standard offer service obligations to BGE residential 2006 2005 2004 customers during the period from July 1, 2000 until July 1, (Dollaramounts in millions)

Revenues: 2006.

Mid-Atlantic Region $ 2,813.5 $ 2,283.9 $ 1,925.6 These increases in gross margin were partially offset by:

Plants with Power

• lower CTC revenues of approximately $64 million due Purchase to customers that completed their obligation and the Agreements 650.5 665.9 555.3 Competitive Supply continued decline in the CTC rate, and Retail 8,014.7 6,942.3 4,280.0 + lower generation at Calvert Cliffs, which resulted in Wholesale 5,612.7 4,672.3 3,353.8 lower gross margin of approximately $37 million, Other 74.8 58.0 73.6 Total $ 17,166.2 $ 14,622.4 $10,188.3 mostly because of a longer planned 2006 refueling Fuel and purchased outage that included replacement of the reactor vessel energy expenses: head.

Mid-Atlantic Region $ (1,727.6) $ (1,436.5) $ (946.9) The decrease in Mid-Atlantic Region gross margin in Plants with Power Purchase 2005 compared to 2004 is primarily due to rising commodity Agreements (67.9) (72.5) (46.4) prices and hotter than normal weather during the third quarter Competitive Supply of 2005, which resulted in higher load-serving costs. In Retail (7,570.2) (6,668.2) (4,011.4) addition, CTC revenues were $33.1 million lower during 2005 Wholesale (4,890.6) (4,124.6) (3,113.4)

Other - - - compared to 2004. These decreases in gross margin were Total $ (14,256.3) $ (12,301.8) $ (8,118.1) partially offset by the absence of coal delivery issues that we

%/of %of %of experienced in 2004 that had a negative impact in that period.

Total Total Total Gross maegin:

Mid-Atlantic Region $ 1,085.9 37% $ 847.4 36% $ 978.7 47%

Plantf with Power PurcrhaeAoreemente Plants with Power 2006 2005 2004 Purchase (In millions)

Agreements 582.6 20 593.4 25 508.9 25 Competitive Supply Revenues $ 650.5 $ 665.9 $ 555.3 Retail 444.5 15 274.1 12 268.6 13 Fuel and purchased energy Wholesale 722.1 25 547.7 24 240.4 12 expenses (67.9) (72.5) (46.4)

Other 74.8 3 58.0 3 73.6 3 Gross margin $ 582.6 $ 593.4 $ 508.9 Total $ 2,909.9 100% $ 2,320.6 100% $ 2,070.2 100%

Certainprior-yearamounts have been reclassifiedto conform with Gross margin from our Plants with Power Purchase the currentyear'spresentation. Agreements decreased slightly in 2006 compared to the same periods of 2005. This was mostly due to approximately $14 Mid-Atlantic Re ion million in lower gross margin from the University Park facility.

As discussed in the Revenues and Fuel and PurchasedEnergy 2006 2005 2004 Expenses section, the University Park power purchase agreement (In millions)

Revenues $ 2,813.5 $ 2,283.9 $1,925.6 expired in May 2006. As a result, beginning in June 2006 until Fuel and purchased energy its sale in December 2006, the results of University Park are expenses (1,727.6) (1,436.5) (946.9) included in the Mid-Atlantic Region.

Gross margin $ 1,085.9 $ 847.4 $ 978.7 The increase in gross margin from our Plants with Power Purchase Agreements in 2005 compared to 2004 was primarily The increase of $238.5 million in gross margin in 2006 due to:

compared to 2005 is primarily due to approximately $340

• higher gross margin of $71.5 million from Ginna, million in higher gross margin mostly from favorable portfolio which was acquired in June 2004. This increase in management, including higher margins on existing contracts gross margin at Ginna includes an increase in revenues and new contracts that began in 2006. of $76.9 million, and Our wholesale marketing, risk management, and trading

• higher gross margin of $39.0 million at our Nine Mile operation was awarded contracts in 2006 to supply a Point facility that benefited from higher generation substantial portion of BGE's standard offer service obligation to primarily due to fewer refueling outage days, the residential customers beginning July 1, 2006 through May 31, absence of an unplanned outage that occurred in 2007. The increase in gross margin included higher revenues January 2004, and higher prices on the portion of our from BGE of approximately $256 million mostly from these output sold into the wholesale market.

new contracts during 2006 compared to 2005. This increase in These increases in gross margin were partially offset by gross margin was partially offset by the negative impact of $26.0 million primarily related to changes in commodity prices higher expenses from serving the original BGE standard offer that had a negative impact on realized hedging activities related service obligation during the first six months of 2006 as to the portion of these facilities sold into the wholesale market.

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 42

Competitive Supply

• an increase of approximately $85 million primarily We analyze our retail accrual, wholesale accrual, and mark-to- related to the growth in our coal and natural gas market competitive supply activities below. activities.

These increases in gross margin were partially offset by the Retail following:

2006 2005 2004

• a decrease of $24.8 million as a result of the initial (In millions) public offering of CEP and the sale of our gas-fired Accrual revenues $ 8,000.6 $ 6,944.2 $ 4,281.0 plants. As a result of these transactions, forecasted Fuel and purchased energy transactions associated with cash-flow hedges were expenses (7,577.0) (6,688.4) (4,011.4) determined to be probable of not occurring, and the Retail accrual activities 423.6 255.8 269.6 associated amounts previously recorded in Mark-to-market activities 20.9 18.3 (1.0) "Accumulated other comprehensive loss" were Gross margin $ 444.5 $ 274.1 $ 268.6 reclassified into earnings, and

• a decrease of approximately $20 million from contract The increase in accrual gross margin of $167.8 million from restructurings related to unit contingent power our retail activities during 2006 compared to 2005 is primarily purchase agreements during the year ended due to:

December 2006 compared to 2005. The termination

+ approximately $158 million in higher margins primarily due to higher electric rates and lower costs and sale of these contracts has allowed us to eliminate our exposure to performance risk under these contracts.

related to our fixed-price load-serving obligations as a result of milder weather in 2006 compared to the prior Our wholesale marketing, risk management, and trading operation's accrual gross margin was $16.9 million higher in year, and 2005 compared to 2004 primarily due to newly originated and

• approximately $13 million in higher gross margin due to higher volumes, including 3.6 million more realized business in power, gas, and coal in 2005, including several contract terminations and restructurings. During 2005, megawatt hours of electricity and 55 billion cubic feet we terminated or restructured several in-the-money contracts in more of natural gas served to retail customers during exchange for upfront cash payments and a reduction or the year ended December 31, 2006 compared to 2005.

The decrease in gross margin from our retail competitive cancellation of future performance obligations. The termination or restructuring of two contracts allowed us to supply accrual activities in 2005 compared to 2004 is primarily lower our exposure to performance risk under these contracts, due to:

and resulted in the realization of $77.0 million of pre-tax

+ a combination of higher market prices for electricity, price volatility, and increased customer usage primarily earnings in 2005 that would have been recognized over the life of these contracts. These increases were partially offset by lower in Texas resulting mostly from extreme summer gross margins of approximately $60 million mostly due to the weather, which increased our cost to serve our fixed-absence of several favorable items, including settlements, power price load-serving obligations, prices, and contracts that had a positive impact ir 2004.

• the expiration of higher margin contracts, and

• the absence of favorable bankruptcy settlements, which Mark-to-Market had a positive impact in 2004.

These decreases were partially offset by serving Mark-to-market results include net gains and losses from origination, trading, and risk management activities for which approximately 20 million more megawatt hours in 2005 we use the mark-to-market method of accounting. We discuss compared to 2004 mostly due to the growth of this operation.

these activities and the mark-to-market method of accounting Wholesale in more detail in the CriticalAccountingPolicies section and in Note 1.

2006 2005 2004 As a result of the nature of our operations and the use of (In millions) mark-to-market accounting for certain activities, mark-to-Accrual revenues $ 5,232.7 $ 4,281.8 $ 3,253.7 market earnings will fluctuate. We cannot predict these Fuel and purchased energy fluctuations, but the impact on our earnings could be material.

expenses (4,890.6) (4,124.6) (3,113.4)

We discuss our market risk in more detail in the Market Risk Wholesale accrual activities 342.1 157.2 140.3 section. The primary factors that cause fluctuations in our Mark-to-market activities 380.0 390.5 100.1 mark-to-market results are:

Gross margin $ 722.1 $ 547.7 $ 240.4

+ the number, size, and profitability of new transactions Our wholesale marketing, risk management, and trading including terminations or restructuring of existing operation had $184.9 million of higher gross margin from contracts,

• the number and size of our open derivative positions, accrual activities during 2006 compared to 2005 due to:

• an increase of approximately $145 million primarily and due to new contracts entered into during 2006 and + changes in the level and volatility of forward higher realized gross margin on existing contracts, and commodity prices and interest rates.

43

Mark-to-market results were as follows: results and the change in our net mark-to-market energy asset on the next page.

2006 2005 2004 Total mark-to-market results decreased $7.9 million in (In millions) 2006 compared to 2005 because of a decrease in origination Unrealized mark-to-market results Origination gains $ 13.5 $ 61.6 $ 19.7 gains of $48.1 million, mostly offset by an increase in Risk management and trading-- unrealized changes in fair value of $40.2 million. Unrealized mark-to-market changes in fair value increased primarily due to higher pre-tax Unrealized changes in fair value 387.4 347.2 79.4 gains of approximately $105 million related to the positive Changes in valuation techniques - - -

impact of certain economic hedges primarily related to gas Reclassification of settled contracts to realized (372.1) (257.7) (85.4) transportation and storage contracts that do not qualify for or Total risk management and are not designated as cash-flow hedges. These mark-to-market trading-mark-to-market 15.3 89.5 (6.0) results will be offset as we realize the related accrual load-serving Total unrealized mark-to-market* 28.8 151.1 13.7 positions in cash.

Realized mark-to-market 372.1 257.7 85.4 This increase in unrealized changes in fair value was Total mark-to-market results $ 400.9 $ 408.8 $ 99.1 partially offset by:

• Total unrealized mark-to-market is the sum of originationtransactionsand

• a lower level of gains from risk management and totalrisk managementand trading-mark-to-market.

trading-mark-to-market activities of approximately Origination gains arise primarily from contracts that our $45 million, and wholesale marketing, risk management, and trading operation

• the absence of a $19.5 million favorable impact related structures to meet the risk management needs of our customers to changes in the close-out adjustment in 2006 or relate to our trading activities. Transactions that result in compared to 2005. The close-out adjustments are origination gains may be unique and provide the potential for determined by the change in open positions, new individually significant gains from a single transaction. transactions where we did not have observable market Origination gains represent the initial fair value price information, and existing transactions where we recognized on these structured transactions. The recognition of have now observed sufficient market price information origination gains is dependent on the existence of observable and/or we realized cash flows since the transactions' market data that validates the initial fair value of the contract. inception. We discuss the close-out adjustment in more Origination gains arose primarily from: detail in the CriticalAccounting Policies section.

• 3 transactions completed in 2006, of which no Total mark-to-market results increased $309.7 million in transaction contributed in excess of $10 million pre- 2005 compared to 2004 due to:

tax,

• approximately $260 million primarily related to a

• 6 transactions completed in 2005, one of which higher level of risk management and trading activities.

contributed approximately $35 million pre-tax, and Increases in our gas and coal activities, higher

• 7 transactions completed in 2004, of which no commodity price volatility, and greater market transaction contributed in excess of $10 million pre- liquidity resulted in more opportunities to deploy risk tax. capital and to earn additional returns in 2005 As noted above, the recognition of origination gains is compared to 2004. These items resulted in an dependent on sufficient observable market data that validates increased number of transactions that were entered into the initial fair value of the contract. Liquidity and market and realized during 2005 and a higher level of open conditions impact our ability to identify sufficient, objective positions that resulted in increased gains in 2005 market-price information to permit recognition of origination compared to 2004. During 2005, slightly more than gains. As a result, while our strategy and competitive position half of the mark-to-market results were derived from provide the opportunity to continue to originate such power, approximately one-third from gas, and the transactions, the level of origination gains we are able to remainder from other transactions.

recognize may vary from year to year as a result of the number, * $41.9 million related to a higher level of origination size, and market-price transparency of the individual gains as discussed above, and transactions executed in any period. * $49.9 million related to the decrease in the close-out Risk management and trading-mark-to-market adjustment during 2005 compared to the prior year for represents both realized and unrealized gains and losses from transactions that we have now observed sufficient changes in the value of our portfolio, including the recognition market price information and/or we realized cash flows of gains associated with decreases in the close-out adjustment since the transactions' inception.

when we are able to obtain sufficient market price information. These increases in mark-to-market results were partially In addition, we use derivative contracts subject to mark-to- offset by the impact of $41.5 million of higher mark-to-market market accounting to manage our exposure to changes in losses on certain economic hedges that did not qualify for cash-market prices primarily as a result of our gas transportation and flow hedge accounting treatment. Changing forward prices storage activities, while in general the underlying physical result in shifting value between accrual contracts and the transactions related to our gas activities are accounted for on an associated mark-to-market positions of certain contracts in accrual basis. We discuss the changes in mark-to-market results New England that contain fuel adjustment clauses and gas below. We show the relationship between our mark-to-market 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, Changes in the net mark-to-market energy asset that they do not qualify for cash-flow hedge accounting under SFAS affected earnings were as follows:

No. 133. As a result, we recorded $41.2 million of pre-tax

• Origination gains represent the initial unrealized fair losses in 2005 and $0.3 million of pre-tax gains in 2004. These value at the time these contracts are executed to the mark-to-market gains and losses will be offset as we realize the extent permitted by applicable accounting rules.

related accrual load-serving positions in cash.

• Unrealized changes in fair value represent unrealized changes in commodity prices, the volatility of options Mark-to-MarketEnergy Assets and Liabilities on commodities, the time value of options, and other Our mark-to-market energy assets and liabilities are comprised valuation adjustments.

of derivative contracts. While some of our mark-to-market

• Changes in valuation techniques represent contracts represent commodities or instruments for which improvements in estimation techniques, including prices are available from external sources, other commodities modeling and other statistical enhancements used to and certain contracts are not actively traded and are valued value our portfolio to reflect more accurately the using other pricing sources and modeling techniques to economic value of our contracts.

determine expected future market prices, contract quantities, or

• Reclassification of settled contracts to realized both. We discuss our modeling techniques later in this section. represents the portion of previously unrealized amounts Mark-to-market energy assets and liabilities consisted of settled during the period and recorded as realized the following: revenues.

The net mark-to-market energy asset also changed due to At December 31, 2006 2005 the following items recorded in accounts other than in our (In millions) Consolidated Statements of Income:

Current Assets $1,294.8 $1,339.2

• Changes in value of exchange-listed futures and Noncurrent Assets 623.4 1,089.3 options are adjustments to remove unrealized revenue Total Assets 1,918.2 2,428.5 from exchange-traded contracts that are included in Current Liabilities 1,071.7 1,348.7 risk management revenues. The fair value of these Noncurrent Liabilities 392.4 912.3 contracts is recorded in "Accounts receivable" rather Total Liabilities 1,464.1 2,261.0 than "Mark-to-market energy assets" in our Net mark-to-market energy asset $ 454.1 $ 167.5 Consolidated Balance Sheets because these amounts are settled through our margin account with a third-party The following are the primary sources of the change in broker.

net mark-to-market energy asset during 2006 and 2005: + Net changes in premiums on options reflects the accounting for premiums on options purchased as an 2006 2005 increase in the net mark-to-market energy asset and (In millions) premiums on options sold as a decrease in the net Fair value beginning of year $167.5 $ 52.4 mark-to-market energy asset.

Changes in fair value recorded in earnings

• Contracts acquired represents the initial fair value of Origination gains $ 13.5 $ 61.6 acquired derivative contracts recorded in Unrealized changes in fair "Mark-to-market energy assets."

value 387.4 347.2 Changes in valuation techniques Reclassification of settled contracts to realized (372.1) (257.7)

Total changes in fair value recorded in earnings 28.8 151.1 Changes in value of exchange-listed futures and options 277.8 (119.9)

Net change in premiums on options (29.8) 79.7 Contracts acquired 17.4 Other changes in fair value 9.8 (13.2)

Fair value at end of year $454.1 $ 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 Modeling techniques include estimating the present value based upon the delivery period of our contracts and the of cash flows based upon underlying contractual terms and individual components of the risks within each contract. incorporate, where appropriate, option pricing models and Accordingly, we record and manage the energy purchase and statistical and simulation procedures. Inputs to the models sale obligations under our contracts in separate components include:

based upon the commodity (e.g., electricity or gas), the product + observable market prices, (e.g., electricity for delivery during peak or off-peak hours), the

• estimated market prices in the absence of quoted delivery location (e.g., by region), the risk profile (e.g., forward market prices, or option), and the delivery period (e.g., by month and year).

• the risk-free market discount rate, Consistent with our risk management practices, we have

• volatility factors, presented the information in the table above based upon the

• estimated correlation of energy commodity prices, and ability to obtain reliable prices for components of the risks in

• expected generation profiles of specific regions.

our contracts from external sources rather than on a contract- Additionally, we incorporate counterparty-specific credit by-contract basis. Thus, the portion of long-term contracts that quality and factors for market price and volatility uncertainty is valued using external price sources is presented under the and other risks in our valuation. The inputs and factors used to caption "prices provided by external sources." This is consistent determine fair value reflect management's best estimates.

with how we manage our risk, and we believe it provides the The electricity, fuel, and other energy contracts we hold best indication of the basis for the valuation of our portfolio. have varying terms to maturity, ranging from contracts for Since we manage our risk on a portfolio basis rather than delivery the next hour to contracts with terms often years or contract-by-contract, it is not practicable to determine more. Because an active, liquid electricity futures market separately the portion of long-term contracts that is included in comparable to that for other commodities has not developed, each valuation category. We describe the commodities, the majority of contracts used in the wholesale marketing, risk products, and delivery periods included in each valuation management, and trading operation are direct contracts category in detail below. between market participants and are not exchange-traded or The amounts for which fair value is determined using financially settling contracts that can be readily liquidated in prices provided by external sources represent the portion of their entirety through an exchange or other market mechanism.

forward, swap, and option contracts for which price quotations Consequently, we and other market participants generally are available through brokers or over-the-counter transactions. realize the value of these contracts as cash flows become due or The term for which such price information is available varies by payable under the terms of the contracts rather than through commodity, region, and product. The fair values included in selling or liquidating the contracts themselves.

this category are the following portions of our contracts: Consistent with our risk management practices, the

• forward purchases and sales of electricity during peak amounts shown in the table above as being valued using prices and off-peak hours for delivery terms primarily through from external sources include the portion of long-term 2010, but up to 2012, depending upon the region, contracts for which we can obtain reliable prices from external

• options for the purchase and sale of electricity during sources. The remaining portions of these long-term contracts peak hours for delivery terms through 2008, depending are shown in the table as being valued using models. In order to upon the region, realize the entire value of a long-term contract in a single

• forward purchases and sales of electric capacity for transaction, we would need to sell or assign the entire contract.

delivery terms primarily through 2007, but up to 2008, If we were to sell or assign any of our long-term contracts in depending on the region, their entirety, we may realize an amount different from the

• forward purchases and sales of natural gas, coal, and oil value reflected in the table. However, based upon the nature of for delivery terms through 2011, and the wholesale marketing, risk management, and trading

• options for the purchase and sale of natural gas, coal, operation, we generally expect to realize the value of these and oil for delivery terms through 2008. contracts, as well as any contracts we may enter into in the The remainder of the net mark-to-market energy asset is future to manage our risk, over time as the contracts and valued using models. The portion of contracts for which such related hedges settle in accordance with their terms. In general, techniques are used includes standard products for which we do not expect to realize the value of these contracts and external prices are not available and customized products that related hedges by selling or assigning the contracts themselves are valued using modeling techniques to determine expected in total.

future market prices, contract quantities, or both.

46

The fair values in the table represent expected future cash Our investment in qualifying facilities and domestic flows based on the level of forward prices and volatility factors power projects consisted of the following:

as of December 31, 2006 and could change significantly as a result of future changes in these factors. Additionally, because Book Value at December 31, 2006 2005 the depth and liquidity of the power markets vary substantially (In millions) between regions and time periods, the prices used to determine Project Type fair value could be affected significantly by the volume of Coal $125.7 $127.8 transactions executed. Hydroelectric 55.1 55.9 Management uses its best estimates to determine the fair Geothermal 40.5 43.7 value of commodity and derivative contracts it holds and sells. Biomass 46.6 48.0 These estimates consider various factors including closing Fuel Processing 33.7 23.8 exchange and over-the-counter price quotations, time value, Solar 7.0 7.0 volatility factors, and credit exposure. However, future market Total $308.6 $306.2 prices and actual quantities will vary from those used in recording mark-to-market energy assets and liabilities, and it is We believe the current market conditions for our possible that such variations could be material. equity-method investments that own geothermal, coal, hydroelectric, and fuel processing projects provide sufficient positive cash flows to recover our investments. We Risk Management Assets and Liabilities continuously monitor issues that potentially could impact We record derivatives that qualify' for designation as hedges future profitability of these investments, including under SFAS No. 133 in "Risk management assets and environmental and legislative initiatives. We discuss certain liabilities" in our Consolidated Balance Sheets. Our risk risks and uncertainties in more detail in our ForwardLooking management assets and liabilities consisted of the following:

Statements and Item ]A. Risk Factors sections. However, should At December 31, 2006 2005 future events cause these investments to become uneconomic, (In millions) our investments in these projects could become impaired under Current Assets $ 261.7 $1,244.3 the provisions of APB No. 18.

Noncurrent Assets 325.7 626.0 The ability to recover our equity- and cost-method Total Assets 587.4 1,870.3 investments that own biomass and solar projects is partially Current Liabilities 1,340.0 483.5 dependent upon subsidies from the State of California. Under Noncurrent Liabilities 707.3 1,035.5 the California Public Utility Act, subsidies currently exist in Total Liabilities 2,047.3 1,519.0 that the California Public Utilities Commission (CPUC) requires load-serving entities to identify a separate rate Net risk management (liability) component to be collected from customers to fund the asset $(1,459.9) $ 351.3ý development of renewable resources technologies, including The decrease in our net risk management asset of $1.8 solar, biomass, and wind facilities. In addition, legislation in billion since December 31, 2005 was due primarily to decreases California requires that each load-serving entity increase its in power prices that reduced the fair value of our cash-flow total procurement of eligible renewable energy resources by at hedge positions and the settlement of cash-flow hedges during least one percent per year so that 20% of its retail sales are 2006. A decrease in the fair value of our cash-flow hedges procured from eligible renewable energy resources by 2017.

indicates an increase in value of the accrual positions to which The legislation also requires the California Energy Commission these hedges are related. to award supplemental energy payments to load-serving entities to cover above-market costs of renewable energy.

Other Given the need for electric power and the desire for renewable resource technologies, we believe California will 2006 2005 2004 continue to subsidize the use of renewable energy to make these (In millions) projects economical to operate. However, should the California Revenues $74.8 $58.0 $73.6 legislation fail to adequately support the renewable energy initiatives, our equity-method investments in these types of Our merchant energy business holds up to a 50% voting interest in 24 operating domestic energy projects that consist of projects could become impaired under the provisions of APB No. 18, and any losses recognized could be material.

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 OperatingExpene use of a cogeneration process. Earnings from our investments Our merchant energy business operating expenses increased were $13.8 million in 2006, $3.6 million in 2005, and $203.3 million in 2006 compared to 2005 mostly due to the

$18.0 million in 2004. 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 Taxes Other Than Income Taxes operations, primarily due to acquisitions made in Merchant energy taxes other than income taxes increased June 2005, and $13.3 million in 2006 compared to 2005 mostly due to

• an increase of approximately $18 million at our $5.3 million related to higher gross receipts taxes at our retail generating facilities, which includes higher expenses competitive supply operation and $3.1 million related to our associated with longer planned outages, offset in part working interests in gas producing properties.

by lower expenses that resulted from our productivity Merchant energy taxes other than income taxes increased initiatives. $23.4 million in 2005 compared to 2004 mostly due to Our merchant energy business operating expenses $19.6 million related to higher gross receipts taxes at our retail increased $196.2 million in 2005 compared to 2004 mostly electric operation and $4.0 million related to property taxes for due to the following: Ginna.

+ an increase of $101.8 million at our wholesale marketing, risk management, and trading operation Regulated Electric Business due to an increase in compensation and benefit costs Our regulated electric business is discussed in detail in Item 1.

including our expanding gas and coal operations, Business-ElectricBusiness section.

• an increase of $81.5 million from Ginna, which was Results acquired in June 2004,

• an increase of $26.5 million at our retail operation 2006 2005 2004 primarily related to a $10.8 million increase in (In millions) uncollectible expenses and a $8.7 million increase in Revenues $ 2,115.9 $ 2,036.5 $ 1,967.7 aggregator fees, Electricity purchased

• an increase of $17.3 million at our gas-fired generating for resale expenses (1,167.8) (1,068.9) (1,034.0) facilities primarily due to increased corporate overhead Operations and expenses, and maintenance

• an increase of $13.0 million at Calvert Cliffs primarily expenses (351.3) (318.4) (304.2) due to an increase in corporate overhead expenses, Merger-related costs (3.3) (4.0) -

partially offset by fewer employees and a shorter Depreciation and refueling outage in 2005. amortization (181.5) (185.8) (194.2)

These increases in expense were partially offset by lower Taxes other than operating expenses of $56.5 million at Nine Mile Point income taxes (134.9) (135.3) (132.8) primarily due to lower refueling outage expenses and a lower Income from number of employees and contractors. Operations $ 277.1 $ 324.1 $ 302.5 Net Income $ 120.2 $ 149.4 $ 131.1 Workforce Reduction Costs Other Items Included in Operations (afler-tax)

Our merchant energy business recognized expenses associated Merger-related costs $ (0.8) $ (3.7) $ -

with our workforce reduction efforts as discussed in more detail Above amounts include intercompany transactionseliminatedin our in Note 2.

ConsolidatedFinancialStatements. Note 3 provides a reconciliation of operatingresults by segment to our ConsolidatedFinancial Merger-RelatedCosts Statements.

We discuss costs related to the merger with FPL Group, which has been terminated, in Note 15. Net income from the regulated electric business decreased

$29.2 million in 2006 compared to 2005 mostly because of the Depreciation,Depletion, and Amortization Expense following:

Merchant energy depreciation, depletion, and amortization

• increased operations and maintenance expenses of expenses increased $28.5 million in 2005 compared to 2004 $19.9 million after-tax mostly due to higher labor and mostly due to: benefit costs and incremental costs associated with

• $10.2 million related to our South Carolina synthetic 2006 storms, and fuel facility, + decreased revenues less electricity purchased for resale

• $8.8 million related to Ginna, which was acquired in expenses of $11.8 million after-tax.

June 2004, and Net income from the regulated electric business increased

• $6.0 million increase related to our 2005 investments $18.3 million in 2005 compared to 2004 mostly because of the in gas producing facilities. following:

• increased revenues less electricity purchased for resale Accretion ofAsset Retirement Obligations expenses of $20.7 million after-tax, The increase in accretion expense of $8.9 million in 2005 + decreased depreciation and amortization expense of compared to 2004 is primarily due to Ginna which was $5.1 million after-tax, and acquired in June 2004 and the impact of normal

• increased other income primarily due to gains on the compounding. sales of land of $3.6 million after-tax.

48

These favorable results were partially offset by the residential rate freeze in July 2006, partially offset by lower following: standard offer service volumes.

• increased operations and maintenance expenses of Standard offer service revenues increased in 2005

$8.7 million after-tax mostly due to higher labor and compared to 2004 mostly because of increased standard offer benefit costs and the impact of inflation on other costs, service volumes to residential customers and increased standard and offer service rates for all customers partially offset by lower

• merger-related transaction costs of $3.7 million after- standard offer service volumes associated with those tax. commercial and industrial customers that elected alternative suppliers beginning July 1, 2004.

Electric Revenues The changes in electric revenues in 2006 and 2005 compared Rate Stabilization Credits to the respective prior year were caused by: 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 2006 2005 from July 1, 2006 until May 31, 2007 for recovery in the (In millions) future. Therefore, the increase in standard offer service Distribution volumes $ (40.9) $21.3 revenues is partially offset by rate stabilization credits in order Standard offer service 433.7 38.8 to reduce rates for residential customers from market price to Rate stabilization credits (321.9) - the approved increase of 15% in Senate Bill 1.

Total change in electric revenues from electric system sales 70.9 60.1 Electricity Purchased for Resale Expenses Other 8.5 8.7 Electricity purchased for resale expenses include the cost of Total chanize in electric revenues $ 79.4 $68.8 electricity purchased for resale to our standard offer service customers. These costs do not include the cost of electricity Distribution Volumes purchased by delivery service only customers. The following Distribution volumes are the amount of electricity that BCE table summarizes our regulated electricity purchased for resale delivers to customers in its service territory. expenses:

The percentage changes in our electric system distribution volumes, by type of customer, in 2006 and 2005 compared to 2006 2005 2004 the respective prior year were: (in millions)

Actual costs $1,489.7 $1,068.9 $ 1,034.0 2006 2005 Deferral under rate Residential (6.4)% 3.4% stabilization plan (321.9)--

Commercial (0.6) 5.1 Electricity purchased Industrial (7.5) (6.4) for resale expenses $1,167.8 $1,068.9 $1,034.0 In 2006, we distributed less electricity to residential customers mostly due to milder weather and decreased usage Actual Costs per customer, partially offset by an increased number of BCE's actual costs for electricity purchased for resale increased customers. We distributed less electricity to commercial

$420.8 million in 2006 compared to 2005 due to higher customers mostly due to milder weather, partially offset by an contract prices to purchase electricity resulting from the increased number of customers and increased usage per expiration of contracts that were executed in 2000 as part of the customer. We distributed less electricity to industrial customers implementation of electric deregulation in Maryland, partially mostly due to decreased usage per customer.

offset by lower standard offer service volumes.

In 2005, we distributed more electricity to residential BCE's actual costs for electricity purchased for resale customers compared to 2004 mostly due to warmer summer increased $34.9 million in 2005 compared to 2004 mostly weather and an increased number of customers. We distributed because of increased standard offer service volumes to more electricity to commercial customers mostly due to residential customers and higher costs to serve all standard offer increased usage per customer, an increased number of service customers, partially offset by lower electricity purchased customers, and warmer summer weather. We distributed less for resale expenses associated with commercial and industrial electricity to industrial customers mostly due to decreased usage customers that elected alternative suppliers beginning July 1, per customer.

2004.

Standard04Zer Service Deferral under Rate Stabilization Plan BCE provides standard offer service for customers that do not We defer the difference between our actual costs of electricity select an alternative supplier. We discuss the provisions of purchased for resale and what we are allowed to bill customers Maryland's Senate Bill 1 related to residential electric rates in under Senate Bill 1. In 2006, we deferred $321.9 million in the Item 1. Business-ElectricRegulatory Matters and electricity purchased for resale expenses. These deferred Competition section.

expenses, plus carrying charges, are included in "Regulatory Standard offer service revenues were higher in 2006 Assets (net)" in our, and BCE'S, Consolidated Balance Sheets.

compared to 2005 mostly due to an increase to market prices in We discuss the provisions of Senate Bill 1 related to residential the standard offer service rates due to the expiration of the 49

electric rates in the Item 1. Business-Electric Regulatory Matters Net income from the regulated gas business increased and Competition section. $10.3 million in 2006 compared to 2005 mostly due to increased revenues less gas purchased for resale expenses of Electric Operationsand MaintenanceEx~penses $19.8 million after-tax, which was primarily due to the increase Regulated electric operations and maintenance expenses in gas base rates that was approved by the Matyland PSC in increased $32.9 million in 2006 compared to 2005 mostly due December 2005. This increase was partially offset by higher to higher labor and benefit costs and the impact of inflation on operations and maintenance expenses of $7.9 million after-tax.

other costs and $13.1 million of incremental distribution Net income from our regulated gas business was about the service restoration expenses associated with 2006 storms. same in 2005 compared to 2004.

Regulated electric operations and maintenance expenses increased $14.2 million in 2005 compared to 2004 mostly due Gas Revenues to higher labor and benefit costs and the impact of inflation on The changes in gas revenues in 2006 and 2005 compared to other costs. the respective prior year were caused by:

Merger-Related Transaction Costs 2006 2005 (in millions)

We discuss costs related to the merger with FPL Group, which has been terminated, in Note 15. Distribution volumes $ (38.0) $ 3.9 Base rates 33.4 2.6 Revenue decoupling 28.4 2.5 ElectricDepreciationandAinortizationExpense Gas cost adjustments (112.3) 129.1 Regulated electric depreciation and amortization expense Total change in gas revenues from gas decreased $4.3 million in 2006 compared to 2005 mostly system sales (88.5) 138.1 because of the absence of $6.9 million amortization expense associated with certain software, partially offset by $3.0 million Off-system sales 13.9 77.5 Other 1.3 0.2 related to additional property placed in service.

Regulated electric depreciation and amortization expense Total change in gas revenues $ (73.3) $215.8 decreased $8.4 million in 2005 compared to 2004 mostly because of the absence of $12.6 million of accelerated Distribution Volumes amortization expense associated with certain information The percentage changes in our distribution volumes, by type of technology assets replaced in 2004, partially offset by customer, in 2006 and 2005 compared to the respective prior

$4.2 million related to additional property placed in service. year were:

2006 2005 Regulated Gas Business Residential (17.0)% (1-3)%

Our regulated gas business is discussed in detail in Item 1. (13.3)

Commercial (9.0)

Business-Gas Business section. Industrial 3.2 33.6 Results In 2006, we distributed less gas to residential and 2006 2005 2004 commercial customers compared to 2005 mostly due to milder (In millions) weather and decreased usage per customer, partially offset by an Revenues $ 899.5 $ 972.8 $ 757.0 increased number of customers. We distributed more gas to Gas purchased for resale industrial customers mostly due to increased usage per expenses (581.5) (687.5) (484.3) customer.

Operations and In 2005, we distributed less gas to residential and maintenance expenses (144.8) (131.8) (123.6) commercial customers compared to 2004 mostly due to Merger-related costs (1.4) (1.4) -

decreased usage per customer partially offset by colder winter Depreciation and weather and an increased number of customers. We distributed amortization (46.0) (46.6) (48.1) more gas to industrial customers mostly due to increased usage Taxes other than income per customer.

taxes (33.8) (33.1) (32.1)

Income from Operations $ 92.0 $ 72.4 $ 68.9 Base Rates Net Income $ 37.0 $ 26.7 $ 22.2 In December 2005, the Matyland PSC issued an order granting Other Items Included in Operations (after-tax) BGE a $35.6 million annual increase in its gas base rates. In Merger-related costs $ (0.4) $ (1.3) $ - December 2006, the Baltimore City Circuit Court upheld the Above amounts include intercompany transactionseliminated in rate order. However, certain parties have filed an appeal with our ConsolidatedFinancialStatements. Note 3 provides a the Court of Special Appeals. We cannot provide assurance that reconciliation of operating results by segment to our Consolidated the Matyland PSC's order will not be reversed in whole or in FinancialStatements. part or that certain issues will not be remanded to the Maryland PSC for reconsideration.

50

Revenue Decouplinp, Regulated gas operations and maintenance expenses The Maryland PSC allows us to record a monthly adjustment increased $8.2 million in 2005 compared to 2004 mostly due to our gas distribution revenues to eliminate the effect of to higher compensation and benefit costs and the impact of abnormal weather patterns on our gas distribution volumes. inflation on other costs.

This means our monthly gas distribution revenues are based on weather that is considered "normal" for the month and, Merger-Related Transaction Costs therefore, are not affected by actual weather conditions. We discuss costs related to the merger with FPL Group, which has been terminated, in Note 15.

Gas CostAdiustments We charge our gas customers for the natural gas they purchase Other Nonregulated Businesses from us using gas cost adjustment clauses set by the Maryland Results PSC as described in Note 1. However, under the market-based 2006 2005 2004 (In millions) rates mechanism approved by the Maryland PSC, our actual cost of gas is compared to a market index (a measure of the Revenues $ 231.0 $ 207.0 $ 201.1 market price of gas in a given period). The difference between Operating expenses (173.1) (156.2) (180.0) our actual cost and the market index is shared equally between Merger-related costs (0.5) (0.4) -

Depreciation and shareholders and customers.

amortization (37.7) (40.2) (24.2)

Customers who do not purchase gas from BGE are not Taxes other than income subject to the gas cost adjustment clauses because we are not selling gas to them. However, these customers are charged base taxes (2.0) (2.0) (2.4) rates to recover the costs BGE incurs to deliver their gas Income (Loss) from through our distribution system, and are included in the gas Operations $ 17.7 $ 8.2 $ (5.5) distribution volume revenues. Income (Loss) from Gas cost adjustment revenues decreased in 2006 continuing operations compared to 2005 because we sold less gas at lower prices. and before cumulative Gas cost adjustment revenues increased in 2005 compared effects of changes in to 2004 because we sold more gas at higher prices. accounting principles (after-tax) $ 11.3 $ 0.4 $ (12.9)

Oa:-System Sales Income from Off-system gas sales are low-margin direct sales of gas to discontinued wholesale suppliers of natural gas. Off-system gas sales, which operations (after-tax) 0.9 20.6 9.4 occur after BGE has satisfied its customers' demand, are not Cumulative effects of subject to gas cost adjustments. The Maryland PSC approved changes in accounting an arrangement for part of the margin from off-system sales to principles (after-tax) - 0.2 -

benefit customers (through reduced costs) and the remainder to Net Income (Loss) $ 12.2 $ 21.2 $ (3.5) be retained by BGE (which benefits shareholders). Changes in Other Items IncludedIn Operations (after-tax) off-system sales do not significantly impact earnings. Merger-related costs $ (0.2) $ (0.2) $

Revenues from off-system gas sales increased in 2006 Certainprior-yearamounts have been reclassified to conform with compared to 2005 because we sold more gas, partially offset by the currentyear'spresentation.Above amounts include lower prices.

intercompany transactionseliminatedin our Consolidated Revenues from off-system gas sales increased in 2005 FinancialStatements. Note 3 provides a reconciliationofoperating compared to 2004 because we sold more gas at higher prices.

results by segment to our ConsolidatedFinancialStatements.

Gas PurchasedFor Resale Expenses Net income from our other nonregulated businesses decreased Gas purchased for resale expenses include the cost of gas $9.0 million in 2006 compared to 2005 primarily due to a purchased for resale to our customers and for off-system sales. $19.7 million decrease in income from discontinued These costs do not include the cost of gas purchased by operations, partially offset by a $10.7 million increase in net delivery service only customers. income from our remaining other nonregulated businesses, Gas purchased for resale expenses decreased including an increase in net income from our continued

$106.0 million in 2006 compared to 2005 because we liquidation of our real estate investments.

purchased less gas at lower prices. Net income from our other nonregulated businesses Gas purchased for resale expenses increased in 2005 increased $24.7 million in 2005 compared to 2004 primarily compared to 2004 because we purchased more gas at higher due to:

prices.

• a $16.1 million after-tax gain on sale of Constellation Power International Investments, Ltd., which held our Gas Operationsand MaintenanceExpenses other nonregulated international investments, in Regulated gas operations and maintenance expenses October 2005, and increased $13.0 million in 2006 compared to 2005 mostly

• a $13.2 million after-tax increase in net income from due to higher labor and benefit costs and the impact of the continued liquidation of our financial investments.

inflation on other costs.

51

These increases were partially offset by $4.9 million lower Total fixed charges for BGE increased $9.1 million in net income from our other nonregulated international 2006 compared to 2005 mostly because of a higher level of investments due to their sale in October 2005. We discuss the debt outstanding. Total fixed charges for BGE decreased sale of our other nonregulated international investments in $2.7 million in 2005 compared to 2004 mostly because of a more detail in Note 2. lower level of debt outstanding.

In 2001, we decided to sell certain non-core assets and accelerate the exit strategies on other assets that we continued Income Taxes to hold and own. While our intent is to dispose of these The differences in income taxes result from a combination of remaining non-core assets, market conditions and other events the changes in income and the impact of the recognition of tax beyond our control may affect the actual sale of these assets. In credits on the effective tax rate. We include an analysis of the addition, a future decline in the fair value of these assets could changes in the effective tax rate in Note 10.

result in losses that could have a material impact on our Total income taxes increased $187.1 million in 2006 financial results. compared to 2005 primarily due to a higher level of pre-tax income, including the gain on sale of gas-fired plants and the Consolidated Nonoperating Income and Expenses gain on initial public offering of CEP, as well as a decrease in Gain on Initial Public Offering of CEP LLC synthetic fuel tax credits. We discuss all of these events in the In November 2006, CEP, a limited liability company formed Significant Events section.

by Constellation Energy, completed an initial public offering of Total income taxes increased $45.5 million in 2005 5.2 million common units at $21 per unit. As a result of the compared to 2004 primarily due to the recognition of $35.9 initial public offering of CEP, we recognized a pre-tax gain of million in synthetic fuel tax credits in 2004 related to 2003

$28.7 million, or $17.9 million after recording deferred taxes production.

on the gain. We discuss the initial public offering of CEP in Total income taxes for BGE decreased $17.7 million in more detail in Note 2. 2006 compared to 2005 mostly due to lower pre-tax income.

Total income taxes for BGE increased $17.4 million in Other Income 2005 compared to 2004 mostly due to higher pre-tax income.

Other income increased $40.0 million in 2005 compared to 2004 primarily because of higher interest and investment Defined Benefit Obhlgations income due to a higher cash balance and higher We expect to contribute $125 million to our pension plans in decommissioning trust asset earnings and gains on the sales of 2007.

land at BGE. At December 31, 2006, we recorded a net after-tax charge Total other income at BGE increased $12.3 million in to "Accumulated other comprehensive income" of $93.9 2005 compared to 2004 primarily due to approximately million. This net after-tax charge was a result of the following:

$7 million of gains on the sales of land.

• reducing our additional minimum pension liability, which resulted in an increase to "Accumulated other Fixed Charges comprehensive income" of $75.6 million, and Total fixed charges increased $18.5 million mostly because of a

• the adoption of SFAS No. 158, Employers'Accounting higher level of debt outstanding, including commercial paper for Defined Benefit Pension and Other Postretirement borrowings, and higher interest rates in 2006 compared to Plans, an amendment ofFASB Statements No. 87, 106 2005. and 132(R), which resulted in a decrease to Total fixed charges decreased $16.6 million in 2005 "Accumulated other comprehensive income" of $169.5 compared to 2004 mostly because of the benefit of lower million.

interest rates due to interest rate swaps entered into during the SFAS No. 158, discussed in Note 1, creates the potential third quarter of 2004 and a lower level of debt outstanding. We for additional volatility in accumulated other comprehensive discuss the interest rate swaps in more detail in Note 13. 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 $ 952.1 $ (72.8) $ 165.6 1,085.4 (546.8) (65.9)

Financing Activities*

Net issuance (repayment) of debt 242.2 (339.6) (152.8)

Proceeds from issuance of common stock 84.4 96.9 293.9 Common stock dividends paid (264.0) (228.8) (189.7)

Proceeds from initial public offering of CEP LLC 101.3 Proceeds from contract and portfolio acquisitions 221.3 1,026.9 117.5 Other 5.5 98.1 (18.0)

Net cash provided by financing activities 390.7 653.5 50.9 Net increase (decrease) in cash and cash equivalents $ 1,476.1 $ 106.7 $ (15.0)

• Items are not allocatedto the business segments because they are managedfor the company as a whole.

Cash Flows from OperatingActivities Changes in working capital had a negative impact of Cash provided by operating activities was $525.3 million in $671.9 million on cash flow from operations in 2006 2006 compared to $627.2 million in 2005. This compared to a negative impact of $775.3 million in 2005. The

$101.9 million decrease was primarily due to a decrease in non- negative impact of $671.9 million related to working capital cash adjustments to net income in 2006, partially offset by was primarily due to the commodity price environment and favorable changes in net income and working capital. increased risk management and trading activities that resulted Non-cash adjustments to net income decreased by in an increase of approximately $630 million in net cash

$550.6 million in 2006 compared to 2005 primarily due to the collateral requirements, primarily for requirements on change in deferred fuel costs of $336.6 million related mostly exchange-settled transactions. This increase in cash collateral to the deferred recovery of electricity purchased for resale under requirements was accompanied by a decrease in our letters of the BGE rate stabilization plan. We discuss the rate credit requirements.

stabilization plan in more detail in the Item 1-.Business-- Cash provided by operating activities was $627.2 million Electric Regulatory Matters and Competition section and Note 1. in 2005 compared to $1,086.8 million in 2004. Net income In addition, our gains on the sale of gas-fired plants and was higher by $83.4 million in 2005 compared to 2004. Non-discontinued operations increased $177.6 million in 2006 cash adjustments to net income were $159.3 million lower in compared to 2005. We discuss this in more detail in Note 2. 2005 compared to 2004. The decrease in non-cash adjustments 53

to net income was primarily due to the reclassification of 2005 compared to 2004 was mostly due to an increase in

$72.6 million of proceeds from derivative power sales contracts proceeds from contract and portfolio acquisitions of as financing activities under SFAS No. 149, Amendment of $909.4 million. We discuss proceeds from contract and FASB Statement No. 133 on Derivative and Hedging Activities portfolio acquisitions in more detail below. This increase in and $63.9 million related to the impact of discontinued cash provided by financing activities was partially offset by a operations. reduction in proceeds from issuances of common stock, an Changes in working capital had a negative impact of increase in cash used for repayments of debt, and higher

$775.3 million on cash flow from operations in 2005 dividend payments in 2005 compared to 2004.

compared to a negative impact of $319.6 million in 2004. The decrease of $455.7 million was due to a $598 million Contract and Portfolio Acquisitions unfavorable change in working capital primarily related to our During 2006, 2005, and 2004, our merchant energy business accounts receivable, accounts payable, and fuel stocks mostly acquired several pre-existing energy purchase and sale due to higher commodity prices, increased value of emissions agreements, which generated significant cash flows at the credits, and business growth. This was partially offset by an inception of the contracts. These agreements had contract increase of $142 million of net cash collateral received, which prices that differed from market prices at closing, which was also due to higher commodity prices. resulted in cash payments from the counterparty at the acquisition of the contract. We received net cash of Cash Flows from Investing A cavities $219.0 million in 2006, $690.7 million in 2005, and $117.5 Cash provided by investing activities was $560.1 million in million in 2004 for various contract and portfolio acquisitions.

2006 compared to cash used in investing activities We reflect the underlying contracts on a gross basis as assets or

$1,174.0 million in 2005. The $1,734.1 million favorable liabilities in our Consolidated Balance Sheets depending on change in 2006 compared to 2005 was primarily due to the whether they were at above- or below-market prices at closing; increase in proceeds from sale of gas-fired plants and therefore, we have also reflected them on a gross basis in cash discontinued operations of $1,341.3 million and a decrease of flows from investing and financing activities in our

$333.9 million in cash paid for contract and portfolio Consolidated Statements of Cash Flows as follows:

acquisitions. We discuss contract and portfolio acquisitions in more detail below. Year ended December31, 2006 2005 2004 Cash used in investing activities was $1,174.0 million in (In millions) 2005 compared to $1,152.7 million in 2004. The slight Financing activities-proceeds increase in cash used in investing activities was mostly due to from contract and portfolio

$336.2 million of cash paid for contract and portfolio acquisitions $221.3 $1,026.9 $117.5 acquisitions and $82.8 million in issuances of loans receivable Investing activities-contract related primarily to a customer contract restructuring. We and portfolio acquisitions (2.3) (336.2) -

discuss contract and portfolio acquisitions in more detail Cash flows from contract and below, and the customer contract restructuring is discussed in portfolio acquisitions $219.0 $ 690.7 $117.5 more detail in Note 4. These increases in cash used in 2005 compared to 2004 were partially offset by less cash paid for We record the proceeds we receive to acquire energy asset acquisitions and business combinations of $220.1 million purchase and sale agreements as a financing cash inflow because in 2005 compared to 2004 and an increase in cash proceeds it constitutes a prepayment for a portion of the market price of from the sale of discontinued operations of $216.7 million, energy, which we will buy or sell over the term of the primarily due to the sale of Oleander and our other agreements and does not represent a cash inflow from current nonregulated international investments in 2005 as discussed in period operating activities. For those acquired contracts that are more detail in Note 2. derivatives, we record the ongoing cash flows related to the contract with the counterparties as financing cash inflows in Cash Flows from FinancingActivities accordance with SFAS No. 149.

Cash provided by financing activities was $390.7 million in We discuss certain of these contract and portfolio 2006 compared to $653.5 million in 2005. The decrease of acquisitions in more detail in Note 4 and Note 5.

$262.8 million in cash provided in 2006 compared to 2005 was primarily due to a decrease in proceeds from acquired Security Ratings contracts of $805.6 million, a decrease in other financing Independent credit-rating agencies rate Constellation Energy's activities of $92.6 million, and a $35.2 million increase in our and BGE's fixed-income securities. The ratings indicate the dividends paid in 2006 compared to 2005. We discuss the agencies' assessment of each company's ability to pay interest, proceeds from acquired contracts below. These decreases were distributions, dividends, and principal on these securities.

partially offset by a net increase in cash related to changes in These ratings affect how much it will cost each company to sell short-term borrowings and long-term debt of $581.8 million these securities. Generally, the better the rating, the lower the and $101.3 million in proceeds from the initial public offering cost of the securities to each company when they sell them.

of CEP. The factors that credit rating agencies consider in Cash provided by financing activities was $653.5 million establishing Constellation Energy's and BGE's credit ratings in 2005 compared to $50.9 million in 2004. The increase in include, but are not limited to, cash flows, liquidity, business 54

risk profile, and the amount of debt as a component of total MerchantEnergy capitalization. In November 2006, we completed the initial public offering of At the date of this report, our credit ratings were as CEP and received $101.3 million of net cash proceeds. We follows: discuss the initial public offering in more detail in Note 2. We Standard may obtain additional cash by completing sales of our other

& Poors Moody's natural gas properties. Our ability to complete these sales will Rating Investors Fitch- depend on market conditions, and we cannot give assurances that Grout) Service Ratines these sales could be completed.

Constellation Energy On October 31, 2006, CEP entered into a $200.0 million Commercial Paper A-2 P-2 F-2 secured revolving credit facility. The credit facility will mature Senior Unsecured Debt BBB+ Baal BBB+ on October 31, 2010. We discuss this long-term facility in BGE more detail in Note 9.

Commercial Paper A-2 P-2 F-2 In December 2006, we completed the sale of our gas-fired Mortgage Bonds A Baal A plants and received $1.6 billion in cash. The proceeds from the Senior Unsecured Debt BBB+ Baa2 A- sale are expected to be applied to reduce debt and invest in our Trust Preferred Securities BBB- Baa3 BBB+ business or repurchase equity. We discuss this sale in more Preference Stock BBB- Bal BBB+ detail in Note 2.

Available Sources of Funding BGE We continuously monitor our liquidity requirements and BGE currently maintains a $400.0 million five-year revolving believe that our credit facilities and access to the capital markets credit facility expiring in 2011. BGE can borrow directly from provide sufficient liquidity to meet our business requirements. the banks or use the facilities to allow commercial paper to be We discuss our available sources of funding in more detail issued. As of December 31, 2006, BGE had no outstanding below. commercial paper, which results in $400.0 million in unused credit facilities.

ConstellationEnergy Pursuant to Senate Bill 1, BGE is permitted to recover In addition to our cash balance, we have a commercial paper deferred costs associated with the residential electric rate program under which we can issue short-term notes to fund deferral by issuing rate stabilization bonds after January 1, 2007 our subsidiaries. At December 31, 2006, we had approximately that securitize the deferred costs. In December 2006, the

$4,550 million of credit under several facilities. These facilities Maryland PSC issued an order, which allows BGE to issue include: bonds in an aggregate principal amount of approximately $630

+ a $1.0 billion 364-day credit facility expiring million, subject to adjustment. We currently intend to issue October 2007, such bonds in 2007. We discuss Senate Bill I in more detail in

• a $200.0 million 364-day credit facility expiring Item 1. Business-Electric Regulatory Matters and Competition December 2007, section.

• a $1.5 billion five-year revolving credit facility that expires in March 2010, Other NonregulatedBusinesses

• a $1.1 billion five-year revolving credit facility that If we can get a reasonable value for our remaining real estate expires in November 2010, and projects and other investments, additional cash may be

• a $750.0 million five-year revolving credit facility that obtained by selling them. Our ability to sell or liquidate assets expires in November 2010. will depend on market conditions, and we cannot give We enter into these facilities to ensure adequate liquidity assurances that these sales or liquidations could be made.

to support our operations. Currently, we use the facilities to issue letters of credit primarily for our merchant energy Capital Resources business. Additionally, we can borrow directly from the banks Our actual consolidated capital requirements for the years 2004 or use the facilities to allow the issuance of commercial paper through 2006, along with the estimated annual amount for with the exception of the $1.0 billion 364-day facility, which 2007, are shown in the table on the next page.

only supports $500.0 million of letters of credit and the $200.0 We will continue to have cash requirements for:

million 364-day facility, which only supports letters of credit.

• working capital needs, These revolving credit facilities allow the issuance of *. payments of interest, distributions, and dividends, letters of credit up to $4,050 million. At December 31, 2006,

• capital expenditures, and letters of credit that totaled $1,648 million were issued under

• the retirement of debt and redemption of preference all of our facilities, which results in approximately $2.9 billion stock.

of unused credit facilities. Capital requirements for 2007 and 2008 include estimates We expect to fund future acquisitions with an overall goal of spending for existing and anticipated projects. We of maintaining a strong investment grade credit profile. 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,

• costs of complying with the Environmental Protection

• the type and number of projects selected for Agency (EPA), Maryland, and Pennsylvania construction or acquisition, environmental regulations and legislation, and

• the effect of market conditions on those projects,

• enhancements to our information technology infrastructure.

• the cost and availability of capital,

• the availability of cash from operations, and

• business decisions to invest in capital projects. RegulatedElectric and Gas Regulated electric and gas construction expenditures primarily Our estimates are also subject to additional factors. Please include new business construction needs and improvements to see the ForwardLooking Statements and Item MA.Risk Factors existing facilities, including projects to improve reliability.

sections.

Funding for Capital Requirements 2004 2005 2006 2007 (In millions) Merchant Energy Business Nonregulated Capital Funding for our merchant energy business is expected from Requirements: internally generated funds. If internally generated funds are not Merchant energy (excludes sufficient to meet funding requirements, we have available acquisitions) sources from commercial paper issuances, issuances of long-Generation plants $182 $ 182 $ 235 $ 235 term debt and equity, leases, and other financing activities.

Nuclear fuel 133 130 137 150 The projects that our merchant energy business develops Environmental controls - 1 17 , 330 typically require substantial capital investment. Many of the Portfolio qualifying facilities and independent power projects that we acquisitions/investments 11 231 227 550 have an interest in are financed primarily with non-recourse Technology/other 129 165 152 200 debt that is repaid from the project's cash flows. This debt is Total merchant energy collateralized by interests in the physical assets, major project capital requirements 455 709 768 1,465 contracts and agreements, cash accounts and, in some cases, the Other nonregulated capital ownership interest in that project.

requirements 42 32 21 10 We expect to fund acquisitions with a mixture of debt Total nonregulated capital and equity with an overall goal of maintaining a strong requirements 497 741 789 1,475 investment grade credit profile.

Regulated Capital Requirements: RegulatedElectric and Gas Regulated electric 209 241 297 380 Funding for regulated electric and gas capital expenditures is Regulated gas 56 50 63 60 expected from internally generated funds. If internally Total regulated capital generated funds are not sufficient to meet funding requirements 265 291 360 440 requirements, we have available sources from commercial Totalcapitalrequirements $762 $1,032 $1,149 $1,915 paper issuances, available capacity under credit facilities, the The table above does not include amounts related to pre- issuance of long-term debt, trust preferred securities, or acquisition capitalrequirementsbut does includepost-acquisition preference stock, and/or from time to time equity contributions capitalrequirements. We discuss our acquisitions in more detail in from Constellation Energy. We discuss BGE's planned issuance Note 15. of rate stabilization bonds in the Available Sources ofFunding section. BGE also participates in a cash pool administered by As of the date of this report, we have not completed our Constellation Energy as discussed in Note 16.

2008 capital budgeting process, but expect our 2008 capital requirements to be approximately $1.7 billion.

Other NonregulatedBusinesses Our environmental controls capital requirements are Funding for our other nonregulated businesses is expected from affected by new rules or regulations that require modifications internally generated funds. If internally generated funds are not to our facilities. Based on information currently available to us sufficient to meet funding requirements, we have available regarding recently issued regulations, we will install additional sources from commercial paper issuances, issuances of long-air emission control equipment at certain of our coal-fired term debt of Constellation Energy, sales of securities and assets, generating facilities in Maryland and at co-owned coal-fired and/or from time to time equity contributions from generating facilities in Pennsylvania. We estimate another Constellation Energy.

$800 million of capital spending from 2008-2011 for environmental controls. We discuss environmental matters in Our ability to sell or liquidate securities and non-core more detail in Item 1. Business-EnvironmentalMatters. assets will depend on market conditions, and we cannot give assurances that these sales or.liquidations could be made. We Capital Requirements discuss our remaining non-core assets and market conditions in MerchantEnergy Business the Results of Operations-OtherNonregulatedBusinesses section.

Our merchant energy business' capital requirements consist of its continuing requirements, including expenditures for: Contractual Payment Obligations and

• improvements to generating plants, Committed Amounts

• nuclear fuel costs, We enter into various agreements that result in contractual

• upstream gas investments, payment obligations in connection with our business activities.

+ portfolio acquisitions and other investments, These obligations primarily relate to our financing 56

arrangements (such as long-term debt, preference stock, and Lquidity Provisions operating leases), purchases of capacity and energy to support In many cases, customers of our merchant energy business rely the growth in our merchant energy business activities, and on the creditworthiness of Constellation Energy. A decline purchases of fuel and transportation to satisfy the fuel below investment grade by Constellation Energy would requirements of our power generating facilities. negatively impact the business prospects of that operation.

Our total contractual payment obligations as of We regularly review our liquidity needs to ensure that we December 31, 2006, increased $2.4 billion compared to 2005 have adequate facilities available to meet collateral primarily due to an increase in fuel and transportation requirements. This includes having liquidity available to meet obligations and long-term debt. Our fuel and transportation margin requirements for our wholesale marketing, risk obligations increased mostly due to new coal contracts related management, and trading operation and our retail competitive to our merchant energy business. Our long-term debt increased supply activities.

mostly due to the issuance of BGE Notes, offset in part by We have certain agreements that contain provisions that repayments made during the year. We detail our contractual would require additional collateral upon credit rating decreases payment obligations as of December 31, 2006 in the following in the senior unsecured debt of Constellation Energy.

table: Decreases in Constellation Energy's credit ratings would not trigger an early payment on any of our credit facilities.

Payments 2008- 2010- Under counterparty contracts related to our wholesale 2007 2009 2011 Thereafter Total (In millions) marketing, risk management, and trading operation, we are ContractualPayment Obligations obligated to post collateral if Constellation Energy's senior Long-term debt:'

Nonregulared unsecured credit ratings declined below established contractual Principal $ 620.5 $ 507.7 $ 58.8 $2,203.3 $ 3,390.3 levels. Based on contractual provisions at December 31, 2006, Interest 183.9 333.6 286.9 1,276.1 2,080.5 we estimate that if Constellation Energy's senior unsecured Total 804.4 841.3 345.7 3,479.4 5,470.8 BGE debt were downgraded we would have the following additional Principal 121.4 306.1 22.0 1,267.2 1,716.7 collateral obligations:

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 L stock - - - 190.0 190.0 B,-low Cumulative Operating leases' 186.0 222.3 153.4 391.6 953.3 Credit Ratings Cuirrent Incremental Incremental Purchase Downgraded to PRiting Obligations Obligations obligations:'

(In millions)

Purchased capacity and energye 367.1 755.5 271.8 526.0 1,920.4 BBB/Baa2 1 $495 $ 495 Fuel and BBB-/Baa3 2 246 741 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 Below investment Other noncurrent grade 3 547 1,288 liabilities:

Pension benefits' 128.8 71.5 144.0 - 344.3 Based on market conditions and contractual obligations at Postretirement the time of a downgrade, we could be required to post and post collateral in an amount that could exceed the amounts specified employment benefits' 35.2 81.1 91.5 290.7 498.5 above, which could be material. We discuss our credit ratings Total contractual in the Security Ratings section and our credit facilities in the 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 Available Sources ofFundingsection.

to repay $384.3 million early throughput options andremarketingfearures.Interest on The credit facilities of Constellation Energy and BGE variable rate debt is included based on the December31, 2006forward curve for have limited material adverse change clauses that only consider interest rates. a material change in financial condition and are not directly 2 Our operatinglease commitments includefture payment obligations under certain powerpurchase agreements as discussedfrrtherin Note 11. affected by decreases in credit ratings. If these clauses are 3 Contractstopurchasegoods or services that specify all significant terms. Amounts invoked, the lending institutions can decline to make new relatedto certainpurchaseobligationsare based onjuturepurchase expectations which may diffir tom actualpurchases.

advances or issue new letters of credit, but cannot accelerate the 4 Our contractualobligationsforpurchasedcapacity and energy are shown on a gross payment of existing amounts outstanding. The long-term debt basisf*r certain transactions, includingboth thefixed paymentportions of tolling indentures of Constellation Energy and BGE do not contain contractsand estimated variablepayments under unit-contingentpowerpurchase agreements. material adverse change clauses or financial covenants.

5 Amounts relatedto pension benefits reflect our current5-yearforecastfor contributions Certain credit facilities of Constellation Energy contain a for our qualifiedpension plans and participantpayments for our nonqualifiedpension provision requiring Constellation Energy to maintain a ratio of plans. Refer to Note 7for more detail on ourpension plans.

6 Amounts relatedto postretirementandpostemployment benefits arefor unfundedplans debt to capitalization equal to or less than 65%. At andreflect present value amounts consistent with the determinationof the related December 31, 2006, the debt to capitalization ratios as defined liabilities recordedin our Consolidated BalanceSheets as discussed in Note 7.

in the credit agreements were no greater than 48%. The credit agreement of BGE contains a provision requiring BGE to TerminationofMerger w4rh FPL Group, Inc. maintain a ratio of debt to capitalization equal to or less than In connection with the termination of the merger agreement 65%. At December 31, 2006, the debt to capitalization ratio with FPL Group, there are contingencies relating to certain for BGE as defined in this credit agreement was 49%. At types of transactions entered into prior to September 30, 2007. December 31, 2006, no amount was outstanding under this We discuss these contingencies in Note 15. agreement.

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Failure by Constellation Energy, or BGE, to comply with As of December 31, 2006, we have no material off-balance sheet these provisions could result in the acceleration of the maturity arrangements including:

of the debt outstanding under these facilities. The credit facilities

• guarantees with third-parties that are subject to the of Constellation Energy contain usual and customary initial recognition and measuremeht requirements of cross-default provisions that apply to defaults on debt by FASB Interpretation No. 45, Guarantor'sAccounting and Constellation Energy and certain subsidiaries over a specified Disclosure Requirementsfor Guarantees,IncludingIndirect threshold. Guarantees of Indebtedness to Others, The BGE credit facility also contains usual and customary

• retained interests in assets transferred to unconsolidated cross-default provisions that apply to defaults on debt by BGE entities, over a specified threshold. The indenture pursuant to which

• derivative instruments indexed to our common stock, BGE has issued and outstanding mortgage bonds provides that a and classified as equity, or default under any debt instrument issued under the indenture

• variable interests in unconsolidated entities that provide may cause a default of all debt outstanding under such indenture. financing, liquidity, market risk or credit risk support, or Constellation Energy also provides credit support to engage in leasing, hedging or research and development Calvert Cliffs, Nine Mile Point, and Ginna to ensure these plants services.

have funds to meet expenses and obligations to safely operate and At December 31, 2006, Constellation Energy had a total of maintain the plants. $11,277.3 million in guarantees outstanding, of which Pursuant to Senate Bill 1 and an order issued by the $10,001.8 million related to our competitive supply activities.

Maryland PSC, BGE is permitted to recover deferred costs These amounts do not represent incremental consolidated associated with the residential electric rate deferral after Constellation Energy obligations; rather, they primarily represent January 1, 2007, including through the issuance of rate parental guarantees of certain subsidiary obligations to third stabilization bonds that securitize the deferred costs. We discuss parties. These guarantees are put into place in order to allow our Senate Bill 1 in more detail in Item 1.-Business-Electric subsidiaries the flexibility needed to conduct business with Regulatory Matters and Competition section and the rate counterparties without having to post other forms of collateral.

stabilization bonds in Available Sources ofFundingsection. While the stated limit of these guarantees is $10,001.8 million, We discuss our short-term credit facilities in Note 8, long- our calculated fair value of obligations for commercial term debt in Note 9, lease requirements in Note 11, and transactions covered by these guarantees was $2,190.6 million at commitments and guarantees in Note 12. December 31, 2006. If the parent company was required to fund these subsidiary obligations, the total amount based on Off-Balance Sheet Arrangements December 31, 2006 market prices would be $2,190.6 million.

For financing and other business purposes, we utilize certain off- For those guarantees related to our mark-to-market energy or balance sheet arrangements that are not reflected in our risk management liabilities, the fair value of the obligation is Consolidated Balance Sheets. Such arrangements do not recorded in our Consolidated Balance Sheets. We believe it is represent a significant part of our activities or a significant unlikely that we would be required to perform or incur any losses ongoing source of financing. associated with guarantees of our subsidiaries' obligations.

We use these arrangements when they enable us to obtain We discuss our other guarantees in Note 12 and our financing or execute commercial transactions on favorable terms. significant variable interests in Note 4.

Market Risk We have a Risk Management Committee (RMC) that is We are exposed to various risks, including, but not limited to, responsible for establishing risk management policies, reviewing energy commodity price and volatility risk, credit risk, interest procedures for the identification, assessment, measurement and rate risk, equity price risk, foreign exchange risk, and operations management of risks, and the monitoring and reporting of risk risk. Our risk management program is based on established exposures. The RMC meets on a regular basis and is chaired by policies and procedures to manage these key business risks with a the Vice Chairman of Constellation Energy & Chairman of strong focus on the physical nature of our business. This Constellation Energy Commodities Group, and consists of our program is predicated on a strong risk management culture Chief Executive Officer, our Chief Financial Officer and Chief (7 combined with an effective system of internal controls. Administrative Officer, our Executive Vice President of The Audit Committee of the Board of Directors Corporate Strategy and Retail Competitive Supply, the periodically reviews compliance with our risk parameters, limits Co-Presidents & Chief Executive Officers of Constellation and trading guidelines, and our Board of Directors has Energy Commodities Group, the President of Constellation established a value at risk limit. We have a Risk Management Generation Group and the Chief Risk Officer. In addition, the Division that is responsible for monitoring the key business risks, CRO coordinates with the risk management committees at the enforcing compliance with risk management policies and risk major operating subsidiaries that meet regularly to identify, limits, as well as managing credit risk. The Risk Management assess, and quantify material risk issues and to develop strategies Division reports to the Chief Risk Officer (CRO) who provides to manage these risks.

regular risk management updates to the Audit Committee and the Board of Directors.

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Interest Rate Risk $450.0 million of our long-term debt. These fair value hedges We are exposed to changes in interest rates as a result of effectively convert our current fixed-rate debt to a floating-rate financing through our issuance of variable-rate and fixed-rate instrument tied to the three month London Inter-Bank Offered debt and certain related interest rate swaps. We may use Rate. Including the $450.0 million in interest rate swaps, derivative instruments to manage our interest rate risks. approximately 14% of our long-term debt is floating-rate.

In December 2006, in order to manage the exposure to We discuss our use of derivative instruments to manage our fluctuations in interest rates on variable rate debt, CEP entered interest rate risk in more detail in Note 13.

into a pay fixed and receive floating interest rate swap relating to The following table provides information about our debt

$16.5 million of its outstanding debt. obligations that are sensitive to interest rate changes:

In July 2004, to optimize the mix of fixed and floating-rate debt, we entered into interest rate swaps relating to PrincipalPayments andInterestRate Derailby ContractualMaturity Date Fair value at December 31, 2007 2008 2009 2010 2011 Thereafter Total 2006 (Dollars in millions)

Long-term debt Variable-rate debt $ -- $ -- $ -- $ 5.5 $36.0 $ 681.7 $ 723.2 $ 723.2 Average interest rate 6.63% 3.55% 5.50% 5.52%

Fixed-rate debt $741.9(A) $301.1 $512.7 $16.8 $22.5 $2,788.8 $4,383.8 $4,513.8 Average interest rate 6.47% 6.09% 6.13% 6.60% 6.63% 6.41% 6.55%

(A) Amount excludes $384.3 million oflong-term debt that containscertain put options under which lenders couldpotentially require us to repay the debt priorto maturity of which $136.9 million is classified as currentportion of long-term debt in our ConsolidatedBalance Sheets and in our ConsolidatedStatements of Capitalization.

Commodity Risk

• extreme peak demands due to weather conditions, We are exposed to the impact of market fluctuations in the price

• available supply resources, and transportation costs of electricity, natural gas, coal, and other

• transportation availability and reliability within and commodities. These risks arise from our ownership and between regions, operation of power plants, the load-serving activities of BGE and

• location of our generating facilities relative to the our competitive supply operations, and our origination, risk location of our load-serving obligations, management, and trading activities. We discuss these risks

• procedures used to maintain the integrity of the physical separately for our merchant energy and our regulated businesses electricity system during extreme conditions, below.

• changes in the nature and extent of federal and state regulations, and MerchantEnergy Business

• geopolitical concerns affecting global supply of oil and Our merchant energy business is exposed to various risks in the natural gas.

competitive marketplace that may materially impact its financial These factors can affect energy commodity and derivative results and affect our earnings. These risks include changes in prices in different ways and to different degrees. These effects commodity prices, imbalances in supply and demand, and may vary throughout the country as a result of regional operations risk. differences in:

• weather conditions, Commodit Prices

• market liquidity, Commodity price risk arises from:

• capability and reliability of the physical electricity and

• the potential for changes in the price of, and gas systems, and transportation costs for, electricity, natural gas, coal, and

• the nature and extent of electricity deregulation.

other commodities, Additionally, we have fuel requirements that are subject to

+ the volatility of commodity prices, and future changes in coal, natural gas, and oil prices. Our power

• changes in interest rates and foreign exchange rates. generation facilities purchase fuel under contracts or in the spot A number of factors associated with the structure and market. Fuel prices may be volatile, and the price that can be operation of the energy markets significantly influence the level obtained from power sales may not change at the same rate or in and volatility of prices for energy commodities and related the same direction as changes in fuel costs. This could have a derivative products. We use such commodities and contracts in material adverse impact on our financial results.

our merchant energy business, and if we do not properly hedge the associated financial exposure, this commodity price volatility Supply and DemandRisk could affect our earnings. These factors include: We are exposed to the risk that available sources of supply may

• seasonal, daily, and hourly changes in demand, differ from the amount of power demanded by our customers 59

under fixed-price load-serving contracts. During periods of high + futures contracts, which are exchange-traded demand, our power supplies may be insufficient to serve our standardized commitments to purchase or sell a customers' needs and could require us to purchase additional commodity or financial instrument, or to make a cash energy at higher prices. Alternatively, during periods of low settlement, at a specific price and future date; demand, our power supplies may exceed our customers' needs

• swap agreements, which require payments to or from and could result in us selling that excess energy at lower prices. counterparties based upon the differential between two Either of those circumstances could have a negative impact on prices for a predetermined contractual (notional) our financial results. quantity; and We are also exposed to variations in the prices and required

• option contracts, which convey the right to buy or sell a volumes of natural gas, oil, and coal we burn at our power plants commodity, financial instrument, or index at a to generate electricity. During periods of high demand on our predetermined price.

generation assets, our fuel supplies may be insufficient and could The objectives for entering into such hedges include:

require us to procure additional fuel at higher prices. + fixing the price for a portion of anticipated future Alternatively, during periods of low demand on our generation electricity sales at a level that provides an acceptable assets, our fuel supplies may exceed our needs, and could result return on our electric generation operations, in us selling the excess fuels at lower prices. Either of these

• fixing the price of a portion of anticipated fuel purchases circumstances will have a negative impact on our financial for the operation of our power plants, results. + fixing the price for a portion of anticipated energy purchases to supply our load-serving customers, and OperationsRisk

• managing our exposure to interest rate risk and foreign Operations risk is the risk that a generating plant will not be currency exchange risks.

available to produce energy and the risks related to physical The portion of forecasted transactions hedged may vary delivery of energy to meet our customers' needs. If one or more based upon management's assessment of market, weather, of our generating facilities is not able to produce electricity when operational, and other factors.

required due to operational factors, we may have to forego sales While some of the contracts we use to manage risk opportunities or fulfill fixed-price sales commitments through represent commodities or instruments for which prices are the operation of other more costly generating facilities or available from external sources, other commodities and certain through the purchase of energy in the wholesale market at higher contracts are not actively traded and are valued using other prices. We purchase power from generating facilities we do not pricing sources and modeling techniques to determine expected own. If one or more of those generating facilities were unable to future market prices, contract quantities, or both. We use our produce electricity due to operational factors, we may be forced best estimates to determine the fair value of commodity and to purchase electricity in the wholesale market at higher prices. derivative contracts we hold and sell. These estimates consider This could have a material adverse impact on our financial various factors including closing exchange and over-the-counter results. price quotations, time value, volatility factors, and credit Our nuclear plants produce electricity at a relatively low exposure. However, it is likely that future market prices could marginal cost. The Nine Mile Point facility sells 90% of its vary from those used in recording mark-to-market energy assets output under unit-contingent power purchase agreements (we and liabilities, and such variations could be material.

have no obligation to provide power if the units are not We measure the sensitivity of our wholesale marketing and available) to the previous owners. Based on its new capacity, risk management mark-to-market energy contracts to potential beginning in 2007, we will sell approximately 80% of Ginna's changes in market prices using value at risk. Value at risk is a output under a unit-contingent power purchase agreement to the statistical model that attempts to predict risk of loss based on former owners. However, if an unplanned outage were to occur historical market price volatility. We calculate value at risk using at Calvert Cliffs during periods when demand was high, we may a historical variance/covariance technique that models option have to purchase replacement power at potentially higher prices positions using a linear approximation of their value.

to meet our obligations, which could have a material adverse Additionally, we estimate variances and correlation using impact on our financial results. historical commodity price changes over the most recent rolling three-month period. Our value at risk calculation includes all Risk Management and Tradins wholesale marketing and risk management mark-to-market As part of our overall portfolio, we manage the commodity price energy assets and liabilities, including contracts for energy risk of our competitive supply activities and our electric commodities and derivatives that result in physical settlement generation facilities, including power sales, fuel and energy and contracts that require cash settlement.

purchases, emission credits, interest rate and foreign currency The value at risk calculation does not include market risks risks, weather risk, and the market risk of outages. In order to associated with activities that are subject to accrual accounting, manage these risks, we may enter into fixed-price derivative or primarily our generating facilities and our competitive supply non-derivative contracts to hedge the variability in future cash load-serving activities. We manage these risks by monitoring our flows from forecasted sales and purchases of energy, including: fuel and energy purchase requirements and our estimated

• forward contracts, which commit us to purchase or sell contract sales volumes compared to associated supply energy commodities in the future; 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 the potential 2005, for the trading portion of our wholesale trading portfolio pre-tax loss in the fair value of our wholesale mar keting and risk due to increased commodity prices, volatility, and trading management mark-to-market energy assets and li abilities over activity. Our trading positions can be used to manage the one and ten-day holding periods. commodity price risk of our competitive supply activities and our generation facilities. We also engage in trading activities for Total Wholesale Value at Risk profit. These activities are managed through daily value at risk For the year ended December 31, 2006 2005 and stop loss limits and liquidity guidelines.

(In millions) Due to the inherent limitations of statistical measures such 99% Confidence Level, One-Day Holding as value at risk and the seasonality of changes in market prices, Period the value at risk calculation may not reflect the full extent of our Year end $13.4 $10.0 commodity price risk exposure. Additionally, actual changes in Average 16.7 6.1 the value of options may differ from the value at risk calculated High 28.0 14.5 using a linear approximation inherent in our calculation method.

Low 9.6 2.4 As a result, actual changes in the fair value of mark-to-market 95% Confidence Level, One-Day Holding energy assets and liabilities could differ from the calculated value Period at risk, and such changes could have a material impact on our Year end $10.2 $ 7.6 financial results.

Average 12.7 4.7 High 21.3 11.0 RegulatedElectric Business Low 7.3 1.8 BGE's residential base rates were frozen for the six-year period 95% Confidence Level, Ten-Day Holding ended June 30, 2006, and its commercial and industrial base Period rates were frozen for a four-year period that ended June 30, Year end $32.3 $24.1 2004. The commodity and transmission components of rates Average 40.2 14.7 were frozen for different time periods depending on the customer High 67.4 34.9 type and service options selected by customers.

Low 23.0 5.8 Our wholesale marketing, risk management, and trading Based on a 99% confidence interval, we would expect a operation provided BGE 100% of the energy and capacity to one-day change in the fair value of the portfolio greater than or meet its residential standard offer service obligations through equal to the daily value at risk approximately once in every June 30, 2006. Bidding to supply BGE's standard offer service to 100 days. In 2006, we did not experience any instance where the all customers will occur from time to time through a competitive actual daily mark-to-market change in portfolio value exceeded bidding process approved by the Maryland PSC. Our wholesale the predicted value at risk. However, published market studies marketing, risk management, and trading operation is supplying conclude that exceeding daily value at risk less than seven times a portion of BGE's standard offer service obligation to all in a one-year period is considered consistent with a 99% customers. We discuss standard offer service and the impact on confidence interval. base rates in more detail in Item 1. Business-ElectricBusiness The table above is the value at risk associated with our section.

wholesale marketing, risk management, and trading operation's BGE may receive performance assurance collateral from mark-to-market energy assets and liabilities, including both suppliers to mitigate suppliers' credit risks in certain trading and non-trading activities. We experienced higher value circumstances. Performance assurance collateral is designed to at risk for the year ended December 31, 2006 compared to the protect BGE's potential exposure over the term of the supply year ended December 31, 2005, primarily due to a higher contracts and will fluctuate to reflect changes in market prices. In number of economic hedges of accrual positions and an increase addition to the collateral provisions, there are supplier "step-up" in our trading activities discussed below. We discuss our mark- provisions, where other suppliers can step in if the early to-market results in more detail in the Competitive Supply termination of a Full-Requirements Service Agreement with a section. supplier should occur, as well as specific mechanisms for BGE to The following table details our value at risk for the trading otherwise replace defaulted supplier contracts. All costs incurred portion of our wholesale marketing and risk management mark- by BGE to replace the supply contract are to be recovered from to-market energy assets and liabilities over a one-day holding the defaulting supplier or from customers through rates. Finally, period at a 99% confidence level for 2006 and 2005: BGE's exposure to uncollectible expense or credit risk from customers for the commodity portion of the bill is covered by the Wholesale Trading Value at Risk administrative fee included in Provider of Last Resort rates.

For the year ended December31, 2006 2005 (In millions) Our regulated electric business may enter into electric Average $11.2 $ 5.5 futures, options, and swaps to hedge its price. We discuss this High 17.6 13.3 further in Note 13. At December 31, 2006 and 2005, our exposure to commodity price risk for our regulated electric We experienced higher value at risk for the year ended December 31, 2006 compared to the year ended December 31, business was not material.

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Regulated Gas Business Our exposure to "Not Rated" counterparties was Our regulated gas business may enter into gas futures, options, $1.1 billion at December 31, 2006 compared to $1.4 billion at and swap's to hedge its price risk under our market-based rate December 31, 2005. This decrease was mostly due to a decrease incentive mechanism and our off-system gas sales program. We in our credit portfolio related to natural gas and international discuss this further in Note 13. At December 31, 2006 and 2005, coal customers that do not have public credit ratings. Although our exposure to commodity price risk for our regulated gas not rated, a majority of these counterparties are considered business was not material. investment grade equivalent based on our internal credit ratings.

We utilize internal credit ratings to evaluate the creditworthiness Credit Risk of our wholesale customers, including those companies that do We are exposed to credit risk, primarily through our merchant not have public credit ratings. Based on internal credit ratings, energy business. Credit risk is the loss that may result from approximately $643.8 million or 59% of the exposure to unrated counterparties' nonperformance. We evaluate the credit risk of counterparties was rated investment grade equivalent at our wholesale marketing, risk management, and trading December 31, 2006 and approximately $915.7 million or 68%

operation and our retail competitive supply activities separately was rated investment grade equivalent at December 31, 2005.

as discussed below. The following table provides the breakdown of the credit quality of our wholesale credit portfolio based on our internal credit Wholesale CreditRisk ratings.

We measure wholesale credit risk as the replacement cost for open energy commodity and derivative transactions (both mark- At December 31, 2006 2005 to-market and accrual) adjusted for amounts owed to or due Investment Grade Equivalent 82% 80%

from counterparties for settled transactions. The replacement Non-Investment Grade 18 20 cost of open positions represents unrealized gains, net of any A portion of our total wholesale credit risk is related to unrealized losses, where we have a legally enforceable right of transactions that are recorded in our Consolidated Balance setoff. We monitor and manage the credit risk of our wholesale Sheets. These transactions primarily consist of open positions marketing, risk management, and trading operation through from our wholesale marketing, risk management, and trading credit policies and procedures which include an established credit operation that are accounted for using mark-to-market approval process, daily monitoring of counterparty credit limits, accounting, as well as amounts owed by wholesale counterparties the use of credit mitigation measures such as margin, collateral, for transactions that settled but have not yet been paid. The or prepayment arrangements, and the use of master netting following table highlights the credit quality and exposures related agreements.

to these activities:

As of December 31, 2006 and 2005, the credit portfolio of our wholesale marketing, risk management, and trading Number of Net operation had the following public credit ratings: Total Counterparties Exposure of Exposure Greater Cotuterparties Before than 10% Greater than At December31, 2006 2005 Credit Credit Net of Net 10% of Net Rating Collateral Collateral Exposure Exposure Exposure Rating (Dollarsin millions)

Investment Grade' 61% 53% Investment grade $1,268 $130 $1,138 -$ S-Non-Investment Grade 3 7 Split rating 34 5 29 - -

Non-investment grade 81 44 37 - -

Not Rated 36 40 Internally rated-1 Includes counterpartieswith an investmentgrade rating by at investment grade 511 71 440 - -

Internally rated-least one ofthe major credit rating agencies.If split ratingexists, non-investment the lower ratingis used. 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 CreditRisk currencies other than the U.S. dollar. In 2006, our exposure to We are exposed to retail credit risk through our competitive foreign currency risk was not material. However, we expect our electricity and natural gas supply activities which serve foreign currency exposure to grow due to our Canadian commercial and industrial companies. Retail credit risk results operations, global power, coal, freight, and natural gas when customers default on their contractual obligations. This operations, and our UniStar venture. We manage our exposure risk represents the loss that may be incurred due to the to foreign currency exchange rate risk using a comprehensive nonpayment of a customer's accounts receivable balance, as well foreign currency hedging program. While we cannot predict as the loss from the resale of energy previously committed to currency fluctuations, the impact of foreign currency exchange serve the customer. rate risk could be material.

Retail credit risk is managed through established credit policies, monitoring customer exposures, and the use of credit Equity Price Risk mitigation measures such as letters of credit or prepayment We are exposed to price fluctuations in equity markets primarily arrangements. through our pension plan assets, our nuclear decommissioning Our retail credit portfolio is well diversified with no trust funds, and trust assets securing certain executive benefits.

significant company or industry concentrations. During 2006, We are required by the NRC to maintain externally funded we did not experience a material change in the credit quality of trusts for the costs of decommissioning our nuclear power plants.

our retail credit portfolio compared to 2005. Retail credit quality We discuss our nuclear decommissioning trust funds in more is dependent on the economy and the ability of our customers to detail in Note 1.

manage through unfavorable economic cycles and other market A hypothetical 10% decrease in equity prices would result changes. If the business environment were to be negatively in an approximate $130 million reduction in the fair value of our affected by changes in economic or other market conditions, our financial investments that are classified as trading or available-retail credit risk may be adversely impacted. for-sale securities. In 2006, our actual return on pension plan assets was $141.1 million due to advances in the markets in Foreign Currency Risk which plan assets are invested. We describe our financial Our merchant energy business is exposed to the impact of investments in more detail in Note 4, and our pension plans in foreign exchange rate fluctuations. This foreign currency risk Note 7.

arises from our activities in countries where we transact in 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 FinancialStatements accordance with generally accepted accounting principles in the The management of Constellation Energy Group, Inc. and United States of America.

Baltimore Gas and Electric Company (the "Companies") is The management of Constellation Energy conducted an responsible for the information and representations in the evaluation of the effectiveness of Constellation Energy's Companies' financial statements. The Companies prepare the internal control over financial reporting using the framework in financial statements in accordance with accounting principles Internal Control-Integrated Framework issued by the generally accepted in the United States of America based upon Committee of Sponsoring Organizations of the Treadway available facts and circumstances and management's best Commission (COSO). As noted in the COSO framework, an estimates and judgments of known conditions. internal control system, no matter how well conceived and PricewaterhouseCoopers LLP, an independent registered operated, can provide only reasonable-not absolute-assurance to public accounting firm, has audited the financial statements management and the Board of Directors regarding achievement and expressed their opinion on them. They performed their of an entity's financial reporting objectives. Based upon the audit in accordance with the standards of the Public Company evaluation under this framework, management concluded that Accounting Oversight Board (United States). Constellation Energy's internal control over financial reporting The Audit Committee of the Board of Directors, which was effective as of December 31, 2006.

consists of three independent Directors, meets periodically with PricewaterhouseCoopers LLP, an independent registered management, internal auditors, and PricewaterhouseCoopers public accounting firm, has audited management's assessment LLP to review the activities of each in discharging their of the effectiveness of Constellation Energy's internal control responsibilities. The internal audit staff and over financial reporting at December 31, 2006, as stated in PricewaterhouseCoopers LLP have free access to the Audit their report set forth below.

Committee. As discussed in Item 9A. Controls and Procedures, the management of Baltimore Gas & Electric Company ("BGE")

Management'sReport on InternlalControlOver Financial has not assessed the effectiveness of BGE's internal control over Reporting financial reporting on a standalone basis because it is not yet The management of Constellation Energy Group, Inc. required to do so by applicable federal securities laws and

("Constellation Energy"), under the direction of its principal regulations.

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 Mayo A. Shattuck III E. Follin Smith to Constellation Energy's management and Board of Directors Chairman of the Board, Executive Vice-President, regarding the reliability of financial reporting and the President and Chief ChiefFinancialOfficer, and preparation of financial statements for external purposes in Executive Officer ChiefAdministrative Officer REITEE PULI ACONTN FIR I RPR S S OF INEEDN To the Board ofDirectors and Shareholders of December 31, 2006 in conformity with accounting principles Constellation Energy Group, Inc. generally accepted in the United States of America. In addition, We have completed integrated audits of Constellation Energy in our opinion, the financial statement schedule listed in the Group, Inc. and Subsidiaries' consolidated financial statements index appearing under Item 15(a) (2) presents fairly, in all and of its internal control over financial reporting as of material respects, the information set forth therein when read December 31, 2006 in accordance with the standards of the in conjunction with the related consolidated financial Public Company Accounting Oversight Board (United States). statements. These financial statements and financial statement Our opinions, based on our audits, are presented below. schedule are the responsibility of the Company's management.

Our responsibility is to express an opinion on these financial Consolidated financial statements and financial statements and financial statement schedule based on our statement schedule audits. We conducted our audits of these statements in In our opinion, the consolidated financial statements listed in accordance with the standards of the Public Company the index appearing under Item 15(a) (1) present fairly, in all Accounting Oversight Board (United States). Those standards material respects, the financial position of Constellation Energy require that we plan and perform the audit to obtain reasonable Group, Inc. and Subsidiaries (the Company) at December 31, assurance about whether the financial statements are free of 2006 and 2005, and the results of their operations and their material misstatement. An audit of financial statements cash flows for each of the three years in the period ended includes examining, on a test basis, evidence supporting the 64

amounts and disclosures in the financial statements, assessing such other procedures as we consider necessary in the the accounting principles used and significant estimates made circumstances. We believe that our audit provides a reasonable by management, and evaluating the overall financial statement basis for our opinions.

presentation. We believe that our audits provide a reasonable A company's internal control over financial reporting is a basis for our opinion. process designed to provide reasonable assurance regarding the As discussed in Note I to the consolidated financial reliability of financial reporting and the preparation of financial statements, in 2006 the Company changed its method of statements for external purposes in accordance with generally accounting for defined benefit pension and other accepted accounting principles. A company's internal control postretirement plans. As discussed in Note 1 to the consolidated over financial reporting includes those policies and procedures financial statements, in 2005 the Company changed its method that (i) pertain to the maintenance of records that, in of accounting for conditional asset retirement obligations and the reasonable detail, accurately and fairly reflect the transactions accounting for stock based compensation. and dispositions of the assets of the company; (ii) provide We have also previously audited, in accordance with the reasonable assurance that transactions are recorded as necessary standards of the Public Company Accounting Oversight Board to permit preparation of financial statements in accordance (United States), the consolidated balance sheets and statements with generally accepted accounting principles, and that receipts of capitalization of Constellation Energy Group, Inc. and and expenditures of the company are being made only in Subsidiaries as of December 31, 2004, 2003, and 2002, and accordance with authorizations of management and directors of the related consolidated statements of income, cash flows, and the company; and (iii) provide reasonable assurance regarding common shareholders' equity and comprehensive income for prevention or timely detection of unauthorized acquisition, use, the years ended December 31, 2003 and 2002 (none of which or disposition of the company's assets that could have a are presented herein); and we expressed unqualified opinions material effect on the financial statements.

on those consolidated financial statements. In our opinion, the Because of its inherent limitations, internal control over information set forth in the Summary of Operations and financial reporting may not prevent or detect misstatements.

Summary of Financial Condition of Constellation Energy Also, projections of any evaluation of effectiveness to future Group, Inc. and Subsidiaries included in the Selected Financial periods are subject to the risk that controls may become Data for each of the five years in the period ended inadequate because of changes in conditions, or that the degree December 31, 2006, is fairly stated, in all material respects, in of compliance with the policies or procedures may deteriorate.

relation to the consolidated financial statements from which it has been derived.

"10' Internal control over financial reporting PricewaterhouseCoopers LLP Also, in our opinion, management's assessment, included in Baltimore, Maryland Management's Report on Internal Control Over Financial February 26, 2007 Reporting appearing under Item 8, that the Company maintained effective internal control over financial reporting as To Board of Directors and Shareholder of Baltimore Gas and of December 31, 2006, based on criteria established in Internal Electric Company Control-IntegratedFramework issued by the Committee of In our opinion, the consolidated financial statements listed in Sponsoring Organizations of the Treadway Commission the index appearing under Item 15(a) (1) present fairly, in all (COSO), is fairly stated, in all material respects, based on those material respects, the financial position of Baltimore Gas and criteria. Furthermore, in our opinion, the Company Electric Company and Subsidiaries (the Company) at maintained, in all material respects, effective internal control December 31, 2006 and 2005, and the results of their over financial reporting as of December 31, 2006, based on operations and their cash flows for each of the three years in the criteria established in Internal Control-IntegratedFramework period ended December 31, 2006 in conformity with issued by the COSO. The Company's management is accounting principles generally accepted in the United States of responsible for maintaining effective internal control over America. In addition, in our opinion, the financial statement financial reporting and for its assessment of the effectiveness of schedule listed in the index appearing under Item internal control over financial reporting. Our responsibility is 15(a) (2) presents fairly, in all material respects, the to express opinions on management's assessment and on the information set forth therein when read in conjunction with effectiveness of the Company's internal control over financial the related consolidated financial statements. Threse financial reporting based on our audit. We conducted our audit of statements and financial statement schedule are the internal control over financial reporting in accordance with the responsibility of the Company's management. Our standards of the Public Company Accounting Oversight Board responsibility is to express an opinion on these financial (United States). Those standards require that we plan and statements and financial statement schedule based on our perform the audit to obtain reasonable assurance about whether audits. We conducted our audits of these statements in effective internal control over financial reporting was accordance with the standards of the Public Company maintained in all material respects. An audit of internal control Accounting Oversight Board (United States). Those standards over financial reporting includes obtaining an understanding of require that we plan and perform the audit to obtain reasonable internal control over financial reporting, evaluating assurance about whether the financial statements are free of management's assessment, testing and evaluating the design material misstatement. An audit includes examining, on a test and operating effectiveness of internal control, and performing basis, evidence supporting the amounts and disclosures in the 65

financial statements, assessing the accounting principles used Summary of Operations and Summary of Financial Condition and significant estimates made by management, and evaluating of Baltimore Gas and Electric Company and Subsidiaries the overall financial statement presentation. We believe that included in the Selected Financial Data for each of the five our audits provide a reasonable basis for our opinion. years in the period ended December 31, 2006, is fairly stated, We have also previously audited, in accordance with the in all material respects, in relation to the consolidated financial standards of the Public Company Accounting Oversight Board statements from which it has been derived.

(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 PricewaterhouseCoopers LLP comprehensive income for the years ended December 31, 2003 Baltimore, Maryland and 2002 (none of which are presented herein); and we February 26, 2007 expressed unqualified opinions on those consolidated financial statements. In our opinion, the information set forth in the 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 ConsolidatedFinancialStatements.

Certainprior-yearamounts have been reclassified to conform with the currentyear 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 ConsolidatedFinancialStatements.

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 ConsolidatedFinancialStatements.

69

COSOLIDAT. STAEMNS OCAHF WS Constellation Energy Group, Inc. and Subsidiaries Year Ended December 31. 2006 2005 2004 (In millions)

Cash Flows From Operating Activities Net income $ 936.4 $ 623.1 $ 539.7 Adjustments to reconcile to net cash provided by operating activities (Gain) loss on sales of gas-fired plants and discontinued operations (191.4) (13.8) 50.1 Cumulative effects of changes in accounting principles 7.2 Depreciation, depletion, and amortization 545.1 606.5 650.3 Accretion of asset retirement obligations 67.6 62.1 53.2 Deferred income taxes 128.0 136.9 123.4 Investment tax credit adjustments (6.9) (7.1) (7.2)

Deferred fuel costs (348.5) (11.9) 6.0 Defined benefit obligation expense 129.7 94.2 81.1 Defined benefit obligation payments (89.2) (90.8) (94.7)

Gain on initial public offering of CEP LLC (28.7)

Equity in earnings of affiliates less than dividends received 27.6 38.7 29.5 Proceeds from derivative power sales contracts classified as financing activities under SFAS No. 149 2.6 (72.6)

Changes in Accounts receivable (653.7) (961.2) (397.4)

Mark-to-market energy assets and liabilities (275.9) (88.4) (27.2)

Risk management assets and liabilities (4.4) (27.5) (39.7)

Materials, supplies, and fuel stocks (267.2) (250.3) (112.1)

Other current assets 240.6 (277.1) 5.3 Accounts payable and accrued liabilities 380.5 282.8 260.2 Other current liabilities (91.8) 546.4 (8.7)

Other 24.9 30.0 (25.0)

Net cash provided by operating activities 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 (0.7) 10.7 (9.6)

Proceeds from issuance of Common stock 84.4 96.9 293.9 Long-term debt 852.0 12.0 100.0 Proceeds from initial public offering of Constellation Energy Partners LLC 101.3 Common stock dividends paid (264.0) (228.8) (189.7)

Proceeds from contract and portfolio acquisitions 221.3 1,026.9 117.5 Repayment of long-term debt (609.1) (362.3) (243.2)

Proceeds from derivative power sales contracts classified as financing activities under SFAS No. 149 (2.6) 72.6 Other 8.1 25.5 (18.0)

Net cash provided by financing activities 390.7 653.5 50.9 Net Increase (Decrease) in Cash and Cash Equivalents 1,476.1 106.7 (15.0)

Cash and Cash Equivalents at Beginning of Year 813.0 706.3 721.3 Cash and Cash Equivalents at End of Year $2,289.1 $ 813.0 $ 706.3 Other Cash Flow Information:

Cash paid during the year for:

Interest (net of amounts capitalized) $ 304.7 $ 301.3 $ 327.9 Income taxes $ 109.3 $ 115.3 $ 203.9 See Notes to ConsolidatedFinancialStatements.

Certainprior-yearamounts have been reclassifiedto conform with the currentyear's presentation.

70

COSOIAE STAT.MEN SOF COMO SHREODES EQIT AN COPEESV INCOM Constellation Energy Group, Inc. and Subsidiaries Accumulated Other Common Stock Retained Comprehensive Total Year Ended December 31, 2006,2005, and2004 Shares Amount Earnings Loss Amount (Dollaramounts in millions, number ofshares in thousands)

Balance at December 31, 2003 167,819 $ 2,179.8 $ 2,081.9 $ (121.2) $ 4,140.5 Comprehensive Income Net income 539.7 539.7 Other comprehensive income Hedging instruments:,

Reclassification of net gains on hedging instruments from OCI to net income, net of taxes of $169.0 (270.8) (270.8)

Net unrealized gain on hedging instruments, net of taxes of

$124.7 196.8 196.8 Available-for-sale securities:

Reclassification of net loss on securities from OCI to net income, net of taxes of $1.4 2.2 2.2 Net unrealized gain on securities, net of taxes of $22.2 33.7 33.7 Minimum pension liability, net of taxes of $27.9 (42.6) (42.6)

Net unrealized gain on foreign currency translation 0.4 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 ConsolidatedFinancialStatements.

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 ConsolidatedFinancialStatements.

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 ConsolidatedFinancialStatements.

73

COSLIAE STTMET OF INCOM Baltimore Gas and Electric Company and Subsidiaries Year Ended December31, 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 December31, 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 ConsolidatedFinancialStatements 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 ConsolidatedFinancialStatements.

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 ConsolidatedFinancialStatements.

76

COSLIAE STTMET OF CAS FLOW Baltimore Gas and Electric Company and Subsidiaries Year Ended December 31, 2006 2005 2004 (In millions)

Cash Flows From Operating Activities Net income $ 170.3 $ 189.0 $ 166.3 Adjustments to reconcile to net cash provided by operating activities Depreciation and amortization 241.1 250.5 260.9 Deferred income taxes 126.6 (0.9) 34.9 Investment tax credit adjustments (1.7) (1.8) (1.8)

Deferred fuel costs (348.5) (11.9) 6.0 Defined benefit plan expenses 47.2 37.8 31.9 Allowance for equity funds used during construction (3.7) (3.9) (2.0)

Changes in Accounts receivable 135.8 (98.7) (27.0)

Receivables, affiliated companies (0.7) (0.8) 3.5 Materials, supplies, and fuel stocks (8.2) (21.7) (28.4)

Other current assets (31.0) (0.5) 1.0 Accounts payable and accrued liabilities 17.6 44.3 24.2 Accounts payable and accrued liabilities, affiliated companies 10.6 6.7 .(5.6)

Other current liabilities (0.9) 12.0 (10.3)

Long-term receivables and payables, affiliated companies (70.1) (42.9) (52.0)

Other (27.5) (37.4) (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) $ 87.2 $ 88.6 $ 95.5 Income taxes $ 18.7 $ 123.3 $ 80.7 See Notes to ConsolidatedFinancialStatements.

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Notes to Consolidated Financial Statements I Significant Accounting Policies Nature of Our Business (including qualifying facilities and power projects) where we Constellation Energy Group, Inc. (Constellation Energy) is an hold a 20% to 50% voting interest. Under the equity method, energy company that conducts its business through various we report:

subsidiaries including a merchant energy business and + our interest in the entity as an investment in our Baltimore Gas and Electric Company (BGE). Our merchant Consolidated Balance Sheets, and energy business is a competitive provider of energy solutions for

• our percentage share of the earnings from the entity in a variety of customers. BGE is a regulated electric transmission our Consolidated Statements of Income.

and distribution utility company and a regulated gas The only time we do not use this method is if we can distribution utility company with a service territory that covers exercise control over the operations and policies of the the City of Baltimore and all or part often counties in central company. If we have control, accounting rules require us to use Maryland. We describe our operating segments in Note 3. consolidation.

This report is a combined report of Constellation Energy and BGE. References in this report to "we" and "our" are to The Cost Method Constellation Energy and its subsidiaries. References in this We usually use the cost method if we hold less than a 20%

report to the "regulated business(es)" are to BGE. voting interest in an investment. Under the cost method, we report our investment at cost in our Consolidated Balance Termination of Merger Agreement with Sheets. The only time we do not use this method is when we FPL Group, Inc. can exercise significant influence over the operations and On October 24, 2006, Constellation Energy and FPL policies of the company. If we have significant influence, Group, Inc. (FPL Group) agreed to terminate the Agreement accounting rules require us to use the equity method.

and Plan of Merger the parties had entered into on December 18, 2005. We discuss the terminated merger in more Sale ofSubsidiaryStock detail in Note 15. We may sell portions of our ownership interests through public offerings of a subsidiary's stock. We record any gains or losses Consolidation Policy on public offerings in our Consolidated Statements of Income, We use three different accounting methods to report our as a component of non-operating income.

investments in our subsidiaries or other companies:

consolidation, the equity method, and the cost method. Regulation of Electric and Gas Business The Maryland Public Service Commission (Maryland PSC)

Consolidation and the Federal Energy Regulatory Commission (FERC)

We use consolidation for two types of entities: provide the final determination of the rates we charge our

• subsidiaries (other than variable interest entities) in customers for our regulated businesses. Generally, we use the which we own a majority of the voting stock, and same accounting policies and practices used by nonregulated

• variable interest entities (VIEs) for which we are the companies for financial reporting under accounting principles primary beneficiary. Financial Accounting Standards generally accepted in the United States of America. However, Board (FASB) Interpretation No. (FIN) 46R, sometimes the Maryland PSC or the FERC orders an Consolidationof Variable Interest Entities, requires us to accounting treatment different from that used by nonregulated use consolidation when we are the primary beneficiary companies to determine the rates we charge our customers.

of a VIE, which means that we have a controlling When this happens, we must defer (include as an asset or financial interest in a VIE. We discuss our investments liability in our, and BGE's, Consolidated Balance Sheets and in VIEs in more detail in Note 4. exclude from our, and BGE's, Consolidated Statements of Consolidation means that we combine the accounts of Income) certain regulated business expenses and income as these entities with our accounts. Therefore, our consolidated regulatory assets and liabilities. We have recorded these financial statements include our accounts, the accounts of our regulatory assets and liabilities in our, and BGE's, Consolidated majority-owned subsidiaries that are not VIEs, and the Balance Sheets in accordance with Statement of Financial accounts of VIEs for which we are the primary beneficiary. We Accounting Standards (SFAS) No. 71, Accountingfor the Effects have not consolidated any entities for which we do not have a of Certain Types ofRegulation.

controlling voting interest. We eliminate all intercompany We summarize and discuss our regulatory assets and balances and transactions when we consolidate these accounts. liabilities further in Note 6.

The Equity Method Use of Accounting Estimates We usually use the equity method to report investments, Management makes estimates and assumptions when preparing corporate joint ventures, partnerships, and affiliated companies financial statements under accounting principles generally 78

accepted in the United States of America. These estimates and earnings in 2005 that would have been recognized over the life assumptions affect various matters, including: of these contracts.

• our reported amounts of revenues and expenses in our Consolidated Statements of Income during the Mark-to-MarketAccounting reporting periods, We record revenues using the mark-to-market method of

• our reported amounts of assets and liabilities in our accounting for derivative contracts for which we are not Consolidated Balance Sheets at the dates of the permitted to use accrual accounting or hedge accounting. We financial statements, and discuss our use of hedge accounting in the Derivatives and

• our disclosure of contingent assets and liabilities at the HedgingActivities section later in this Note. These mark-to-dates of the financial statements. market activities include derivative contracts for energy and These estimates involve judgments with respect to other energy-related commodities. Under the mark-to-market numerous factors that are difficult to predict and are beyond method of accounting, we record the fair value of these management's control. As a result, actual amounts could derivatives as mark-to-market energy assets and liabilities at the materially differ from these estimates. time of contract execution. Our wholesale marketing, risk management, and trading operation records changes in mark-Reclassifications to-market energy assets and liabilities on a net basis in We have reclassified certain prior-year amounts for comparative "Nonregulated revenues" in our Consolidated Statements of purposes. These reclassifications primarily relate to operations Income. Our retail competitive supply operation records that have been classified as discontinued operations in the changes in sale contracts accounted for as mark-to-market in current year and did not affect consolidated net income for the "Nonregulated revenues" in our Consolidated Statements of years presented. Income.

Mark-to-market energy assets and liabilities consist of Revenues derivative contracts. While some of these contracts represent AccrualAccounring commodities or instruments for which prices are available from We record revenues from the sale of energy, energy-related external sources, other commodities and certain contracts are products, and energy services under the accrual method of not actively traded and are valued using modeling techniques to accounting in the period when we deliver energy commodities determine expected future market prices, contract quantities, or or products, render services, or settle contracts. We use accrual both. The market prices and quantities used to determine fair accounting for our merchant energy and other nonregulated value reflect management's best estimate considering various business transactions, including the generation or purchase and factors, including closing exchange and over-the-counter sale of electricity, gas, and coal as part of our physical delivery quotations, time value, and volatility factors. However, future activities and for power, gas, and coal sales contracts that are market prices and actual quantities will vary from those used in not subject to mark-to-market accounting. Sales contracts that recording mark-to-market energy assets and liabilities, and it is are eligible for accrual accounting include non-derivative possible that such variations could be material.

transactions and derivatives that qualify for and are designated Mark-to-market revenues include:

as normal purchases and normal sales of commodities that will

• gains or losses on new transactions at origination to the be physically delivered. We record accrual revenues, including extent permitted by applicable accounting rules, settlements with independent system operators, on a gross basis + unrealized gains and losses from changes in the fair because we are a principal to the transaction and otherwise value of open contracts, meet the requirements of Emerging Issues Task Force

• net gains and losses from realized transactions, and (EITF) 03-11, Reporting Gainsand Losses on Derivative

• changes in valuation adjustments.

Instruments That Are Subject to FASB Statement No. 133, Origination gains, which are included in mark-to-market Accountingfor Derivative Instruments and HedgingActivities, revenues, arise primarily from contracts that our wholesale and Not Heldfor TradingPurposes, and EITF 99-19, Reporting marketing, risk management, and trading operation structures Revenue Gross as a Principalversus Net as an Agent. to meet the risk management needs of our customers.

We may make or receive cash payments at the time we Transactions that result in origination gains may be unique and assume a power sale agreement for which the contract price provide the potential for individually significant gains from a differs from current market prices. We recognize the cash single transaction.

payment at inception in our Consolidated Balance Sheets as an Origination gains represent the initial fair value "Unamortized energy contract" asset or liability. We amortize recognized on these structured transactions. The recognition of these assets and liabilities into revenues based on the expected origination gains is dependent on the existence of observable cash flows provided by the contracts. market data that validates the initial fair value of the contract.

During 2006 and 2005, we terminated or restructured in- Origination gains were:

the-money contracts in exchange for upfront cash payments * $13.5 million pre-tax in 2006, and a reduction or cancellation of future performance * $61.6 million pre-tax in 2005, and obligations. The termination or restructuring of contracts * $19.7 million pre-tax in 2004.

allowed us to lower our exposure to performance risk under Origination gains arose primarily from:

these contracts, and resulted in the realization of $56.7 million

• 3 transactions completed in 2006, of which no of pre-tax earnings in 2006 and $77.0 million of pre-tax transaction contributed in excess of $10 million pre-tax, 79

+ 6 transactions completed in 2005, one of which our credit exposure to counterparties increases, the contributed approximately $35 million pre-tax, and maturity terms of our transactions increase, or the

• 7 transactions completed in 2004, of which no credit ratings of our counterparties deteriorate, and it transaction contributed in excess of $10 million decreases when our credit exposure to counterparties pre-tax. decreases, the maturity terms of our transactions decrease, or the credit ratings of our counterparties Valuation Adjustments improve.

We record valuation adjustments to reflect uncertainties associated with certain estimates inherent in the determination FinancialStatement Presentation of the fair value of mark-to-market energy assets and liabilities. Certain transactions entered into under master agreements and To the extent possible, we utilize market-based data together other arrangements provide our wholesale competitive supply with quantitative methods for both measuring the uncertainties operation with a right of setoff in the event of bankruptcy or for which we record valuation adjustments and determining the default by the counterparty. We report such transactions net in level of such adjustments and changes in those levels. our Consolidated Balance Sheets in accordance with FASB We describe below the main types of valuation Interpretation No. 39, Offietting ofAmounts Related to Certain adjustments we record and the process for establishing each. Contracts.

Generally, increases in valuation adjustments reduce our earnings, and decreases in valuation adjustments increase our Equity in Earnings earnings. However, all or a portion of the effect on earnings of We include equity in earnings from our investments in changes in valuation adjustments may be offset by changes in qualifying facilities and power projects in "Nonregulated the value of the underlying positions. revenues" in our Consolidated Statements of Income in the

• Close-out adjustment-represents the estimated cost to period they are earned.

close out or sell to a third-party open mark-to-market positions. This valuation adjustment has the effect of Fuel and Purchased Energy Expenses valuing "long" positions (the purchase of a commodity) We incur costs for:

at the bid price and "short" positions (the sale of a

• the fuel we use to generate electricity, commodity) at the offer price. We compute this + purchases of electricity from others, and adjustment based on our estimate of the bid/offer

• natural gas and coal that we resell.

spread for each commodity and option price and the These costs are included in "Fuel and purchased energy absolute quantity of our net open positions for each expenses" in our Consolidated Statements of Income. We year. The level of total close-out valuation adjustments discuss certain of these separately below. We also include increases as we have larger unhedged positions, bid- certain non-fuel direct costs, such as ancillary services, offer spreads increase, or market information is not transmission costs, and brokerage fees in "Fuel and purchased available, and it decreases as we reduce our unhedged energy expenses" in our Consolidated Statements of Income.

positions, bid-offer spreads decrease, or market Our retail competitive supply operation records changes information becomes available. To the extent that we in purchase contracts accounted for as mark-to-market in "Fuel are not able to obtain observable market information and purchased energy expenses" in our Consolidated for similar contracts, the close-out adjustment is Statements of Income.

equivalent to the initial contract margin, thereby recording no gain or loss at inception. In the absence of Fuel Used to GenerateElectricityand Purchasesof observable market information, there is a presumption Electricity that the transaction price is equal to the market value NonregulatedBusinesses of the contract, and therefore we do not recognize a We assemble a variety of power supply resources, including gain or loss at inception. We recognize such gains or baseload, intermediate, and peaking plants that we own, as well losses in earnings as we realize cash flows under the as a variety of power supply contracts that may have similar contract or when observable market data becomes characteristics, in order to enable us to meet our customers' available. energy requirements, which vary on an hourly basis. The

• Credit-spread adjustment-for risk management amount of power purchased depends on a number of factors, purposes we compute the value of our mark-to-market including the capacity and availability of our power plants, the energy assets and liabilities using a risk-free discount level of customer demand, and the relative economics of rate. In order to compute fair value for financial generating power versus purchasing power from the spot reporting purposes, we adjust the value of our mark-to- market.

market energy assets to reflect the credit-worthiness of We also have acquired contracts and certain power each customer (counterparty) based upon either purchase agreements that qualify as operating leases. Under published credit ratings, or equivalent internal credit these operating leases, we record fuel and purchased energy ratings and associated default probability percentages. expense as we make fixed capacity payments, as well as variable We compute this adjustment by applying the payments based on the actual output of the plants.

appropriate default probability percentage to our outstanding credit exposure, net of collateral, for each counterparry. The level of this adjustment increases as 80

We may make or receive cash payments at the time we Derivatives and Hedging Activities acquire a contract or assume a power purchase agreement when We are exposed to market risk, including changes in interest rates the contract price differs from market prices at closing. We and the impact of market fluctuations in the price and recognize the cash payment or receipt at inception in our transportation costs of electricity, natural gas, and other Consolidated Balance Sheets as an "Unamortized energy commodities as discussed further in Note 13. In order to manage contract" asset (payment) or liability (receipt). We amortize these these risks, we use both derivative and non-derivative contracts assets and liabilities into fuel and purchased energy expenses that may provide for settlement in cash or by delivery of a based on the expected cash flows provided by the contracts. commodity, including:

• forward contracts, which commit us to purchase or sell Reulated Electric energy commodities in the future, BGE is obligated to provide market-based standard offer service + futures contracts, which are exchange-traded to residential and small commercial customers for the indefinite standardized commitments to purchase or sell a future, and for large commercial and industrial customers for commodity or financial instrument, or to make a cash varying periods beyond June 30, 2004, depending on customer settlement, at a specific price and future date, load. The Provider of Last Resort (POLR) rates charged during

• swap agreements, which require payments to or from these time periods will recover BGE's wholesale power supply counterparties based upon the differential between two costs and include an administrative fee. The administrative fee prices for a predetermined contractual (notional) includes a shareholder return component and an incremental quantity, and cost component. Pursuant to Senate Bill 1, the energy legislation

• option contracts, which convey the right to buy or sell a enacted in Maryland in June 2006, collection of the shareholder commodity, financial instrument, or index at a return component of the administrative fee for residential POLR predetermined price.

service will be suspended beginning January 1, 2007 for a SFAS No. 133, Accountingfor DerivativeInstruments and 10-year period. HedgingActivities, as amended, requires that we recognize at fair In accordance with the POLR settlement agreement value all derivatives not qualifying for accrual accounting under approved by the Maryland PSC, BGE defers the difference the normal purchase and normal sale exception. We record between certain of its actual costs related to the electric derivatives that are designated as hedges in "Risk management commodity and what it collects from customers under the assets or liabilities" and derivatives not designated as hedges in commodity charge in a given period. BGE either bills or refunds "Mark-to-market energy assets or liabilities" in our Consolidated its customers the difference in the future. In addition, Senate Balance Sheets.

Bill 1 imposed a 15% rate cap for BGE residential electric We record changes in the value of derivatives that are not customers from July 1, 2006 until May 31, 2007. We discuss designated as cash-flow hedges in earnings during the period of this in more detail in Note 6. change. We record changes in the fair value of derivatives BGE's obligation to provide market-based standard offer designated as cash-flow hedges that are effective in offsetting the service to its largest commercial and industrial customers expired variability in cash flows of forecasted transactions in other May 31, 2005. BGE continues to provide an hourly priced comprehensive income until the forecasted transactions occur. At market-based standard offer service to those customers. the time the forecasted transactions occur, we reclassify the amounts recorded in other comprehensive income into earnings.

Reeulated Gas We record the ineffective portion of changes in the fair value of BGE charges its gas customers for the natural gas they purchase derivatives used as cash-flow hedges immediately in earnings.

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.

81

We summarize our cash-flow hedging activities under "Risk management assets and liabilities" in our Consolidated SFAS No. 133 and the income statement classification of Balance Sheets. In addition, we record the difference between amounts reclassified from "Accumulated other comprehensive interest on hedged fixed-rate debt and floating-rate swaps in income (loss)" as follows: "Interest expense" in the periods that the swaps settle.

Income Statement Unamortized Energy Assets and Liabilities Risk Derivative Classification Unamortized energy contract assets and liabilities represent the Interest rate risk Interest rate swaps Interest expense remaining unamortized balance of non-derivative energy associated with contracts that we acquired or derivatives designated as normal new debt purchases and normal sales that we had previously recorded as issuances "Mark-to-market energy assets or liabilities" or "Risk Interest rate risk Interest rate swaps Interest expense management assets and liabilities." The initial amount recorded associated with represents the fair value of the contract at the time of acquisition variable-rate or designation, and the balance is amortized over the life of the debt contract in relation to the present value of the underlying cash flows. The amortization of these values is discussed in the Nonregulated Futures and Nonregulated Revenues and Fuel and PurchasedEnergy Expenses sections of this energy sales forward revenues Note.

contracts Nonregulated fuel Futures and Fuel and purchased Credit Risk and energy forward energy expenses Credit risk is the loss that may result from counterparty non-purchases contracts performance. We are exposed to credit risk, primarily through Nonregulated gas Futures and Fuel and purchased our merchant energy business. We use credit policies to manage purchases for forward energy expenses our credit risk, including utilizing an established credit approval resale contracts and process, daily monitoring of counterparty limits, employing price and basis credit mitigation measures such as margin, collateral or swaps prepayment arrangements, and using master netting agreements.

We measure credit risk as the replacement cost for open energy Regulated gas Price and basis Fuel and purchased commodity and derivative positions (both mark-to-market and purchases for swaps energy expenses accrual) plus amounts owed from counterparties for settled resale transactions. The replacement cost of open positions represents Regulated Price and basis Fuel and purchased unrealized gains, less any unrealized losses where we have a electricity swaps energy expenses legally enforceable right of setoff.

purchases for Electric and gas utilities, municipalities, cooperatives, resale generation owners, and energy marketers comprise the majority of counterparties underlying our assets from our wholesale We designate certain derivatives as fair value hedges. We marketing and risk management activities. We held cash record changes in the fair value of these derivatives and changes in the fair value of the hedged assets or liabilities in earnings as collateral from these counterparties totaling $252.6 million as of December 31, 2006 and $388.4 million as of December 31, the changes occur. We summarize our fair value hedging 2005. These amounts are included in "Customer deposits and activities and the income statement classification of changes in the fair value of these hedges and the related hedged items as collateral" in our Consolidated Balance Sheets.

follows:

Taxes Income Statement We summarize our income taxes in Note 10. BGE and our other Risk Derivative Classification subsidiaries record their allocated share of our consolidated Optimize mix of Interest rate swaps Interest expense federal income tax liability using the percentage complementary fixed and method specified in U.S. income tax regulations. As you read this floating-rate section, it may be helpful to refer to Note 10.

debt Value of natural Forward contracts Nonregulated Income Tax Expense We have two categories of income tax expense-current and gas in storage and price and revenues and basis swaps Fuel and deferred. We describe each of these below:

• current income tax expense consists solely of regular tax purchased less applicable tax credits, and energy expenses

+ deferred income tax expense is equal to the changes in We record changes in the fair value of interest rate swaps the net deferred income tax liability, excluding amounts and the debt being hedged in "Risk management assets and charged or credited to accumulated other comprehensive liabilities" and "Long-term debt" and changes in the fair value of income. Our deferred income tax expense is increased or the gas being hedged and related derivatives in "Fuel stocks" and reduced for changes to the "Income taxes recoverable 82

through future rates (net)" regulatory asset (described Our dilutive common stock equivalent shares consist of below) during the year. stock options and other stock-based compensation awards. The following table presents stock options that were not dilutive and Tax Credits were excluded from the computation of diluted EPS in each We have deferred the investment tax credits associated with our period, as well as the dilutive common stock equivalent shares as regulated business and assets previously held by our regulated follows:

business in our Consolidated Balance Sheets. The investment tax credits are amortized evenly to income over the life of each Year Ended December 31, 2006 2005 2004 property. We reduce current income tax expense in our (In millions)

Non-dilutive stock options - 0.1 -

Consolidated Statements of Income for the investment tax credits and other tax credits associated with our nonregulated Dilutive common stock equivalent businesses. shares 2.0 2.2 1.0 We have certain investments in facilities that manufacture solid synthetic fuel produced from coal as defined under the Stock-Based Compensation Internal Revenue Code for which we claim tax credits on our Under our long-term incentive plans, we have granted stock Federal income tax return. We recognize the tax benefit of these options, performance-based units, performance and service-based credits in our Consolidated Statements of Income when we restricted stock, and equity to officers, key employees, and believe it is highly probable that the credits will be sustained. members of the Board of Directors. We discuss these awards in more detail in Note 14.

DeferredIncome Tax Assets and Liabilities We elected to early adopt SFAS No. 123 Revised (SFAS We must report some of our revenues and expenses differently No. 123R), Share-BasedPayment, on October 1, 2005, which for our financial statements than for income tax return purposes. was prior to the required effective date of January 1, 2006. SFAS The tax effects of the temporary differences in these items are No. 123R requires companies to recognize compensation reported as deferred income tax assets or liabilities in our expense for all equity-based compensation awards issued to Consolidated Balance Sheets. We measure the deferred income employees that are expected to vest. Equity-based compensation tax assets and liabilities using income tax rates that are currently awards include stock options, restricted stock, and any other in effect. share-based payments. We recognized a small, favorable A portion of our total deferred income tax liability relates to cumulative effect of change in accounting principle of our regulated business, but has not been reflected in the rates we $0.2 million after-tax due to the requirement to reduce charge our customers. We refer to this portion of the liability as compensation expense for estimated forfeitures relating to "Income taxes recoverable through future rates (net)." We have outstanding unvested service-based restricted stock awards and recorded that portion of the net liability as a regulatory asset in performance-based unit awards at October 1, 2005.

our Consolidated Balance Sheets. We discuss this further in Under SFAS No. 123R, we recognize compensation cost Note 6. ratably or in tranches (depending if the award has cliff or graded vesting) over the period during which an employee is required to State and Local Taxes provide service in exchange for the award, which is typically a State and local income taxes are included in "Income taxes" in one to five-year period. We use a forfeiture assumption to our Consolidated Statements of Income. estimate the number of awards that are expected to vest during BGE also pays Maryland public service company franchise the service period, and ultimately true-up the estimated expense tax on distribution, and delivery of electricity and natural gas. to the actual expense associated with vested awards. We estimate We include the franchise tax in "Taxes other than income taxes" the fair value of stock option awards on the date of grant using in our Consolidated Statements of Income. the Black-Scholes option-pricing model and we remeasure the fair value of liability awards each reporting period. The following Earnings Per Share table presents the pro-forma effect on net income and earnings Basic earnings per common share (EPS) is computed by dividing per share for all outstanding stock options and stock awards in each period that the fair value provisions of SFAS No. 123R earnings applicable to common stock by the weighted-average number of common shares outstanding for the year. Diluted EPS were not in effect. We do not capitalize any portion of our reflects the potential dilution of common stock equivalent shares stock-based compensation.

that could occur if securities or other contracts to issue common stock were exercised or converted into common stock.

83

Year Ended December31, 2005 2004 in our Consolidated Statements of Common Shareholders' (In millions, except Equity and Comprehensive Income and Consolidated per shareamounts)

Statements of Capitalization.

Net income, as reported $623.1 $539.7 Add: Actual stock-based compensation Evaluation of Assets for Impairment and Other Than expense determined under intrinsic Temporary Decline in Value value method and included in reported Long-Lived Assets net income, net of related tax effects 17.8* 13.2 We are required to evaluate certain assets that have long lives (for Deduct: Pro-forma stock-based example, generating property and equipment and real estate) to compensation expense determined determine if they are impaired when certain conditions exist.

under fair value based method for all SFAS No. 144, Accounting for the Impairmentor DisposalofLong-awards, net of related tax effects (24.5)* (21.3)

Lived Assets, provides the accounting requirements for Pro-forma net income $616.4 $531.6 impairments of long-lived assets and proved gas properties. We Earnings per share: are required to test our long-lived assets and proved gas Basic-as reported $ 3.51 $ 3.14 properties for recoverability whenever events or changes in Basic-pro-forma $ 3.47 $ 3.09 circumstances indicate that their carrying amount may not be Diluted-as reported $ 3.47 $ 3.12 recoverable.

Diluted-pro-forma $ 3.43 $ 3.07 We determine if long-lived assets and proved gas properties

• Represents expense for the nine months ended September 30, 2005, are impaired by comparing their undiscounted expected future which was prior to adoption of SEAS No. 123R cash flows to their carrying amount in our accounting records.

We would record an impairment loss if the undiscounted Cash and Cash Equivalents expected future cash flows were less than the carrying amount of All highly liquid investments with original maturities of three the asset. Cash flows for long-lived assets, or a group of long-months or less are considered cash equivalents. lived assets, are determined at the lowest level for which identifiable cash flows are largely independent of the cash flows Accounts Receivable and Allowance for Uncollectibles of other assets and liabilities. Proven gas properties' cash flows Accounts receivable, which includes cash collateral posted in our are determined at the field level. Undiscounted expected future margin account with a third-parry broker, are stated at the cash flows include risk-adjusted probable and possible reserves.

historical carrying amount net of write-offs and allowance for We are also required to evaluate our equity-method and cost-uncollectibles. We establish an allowance for uncollectibles based method investments (for example, in partnerships that own on our expected exposure to the credit risk of customers based on power projects) for impairment. Accounting Principles Board a variety of factors. (APB) No. 18, The Equity Method ofAccountingfor Investments in Common Stock (APB No. 18), provides the accounting Materials, Supplies, and Fuel Stocks requirements for these investments. The standard for We record our fuel stocks, emissions credits, coal held for resale, determining whether an impairment must be recorded under and materials and supplies at the lower of cost or market. We APB No. 18 is whether the investment has experienced a loss in determine cost using the average cost method for all of our value that is considered an "other than a temporary" decline in inventory other than our coal held for resale for which we use the value.

specific identification method. We are also required to evaluate unproved gas producing properties at least annually to determine if it is impaired under Financial Investments SFAS No. 19, FinancialAccountingand Reporting by Oil and Gas In Note 4, we summarize the financial investments that are in our ProducingProperties.Impairment for unproved property occurs if Consolidated Balance Sheets. there are no firm plans to continue drilling, lease expiration is at SFAS No. 115, Accountingfor CertainInvestments in Debt risk, or historical experience necessitates a valuation allowance.

and Equity Securities, applies particular requirements to some of We use our best estimates in making these evaluations and our investments in debt and equity securities. We report those consider various factors, including forward price curves for investments at fair value, and we use either specific identification energy, fuel costs, legislative initiatives, and operating costs.

or average cost to determine their cost for computing realized However, actual future market prices and project costs could gains or losses. vary from those used in our impairment evaluations, and the impact of such variations could be material.

A vailable-for-Sale Securities We classify our investments in the nuclear decommissioning Debt and Equity Securities trust funds as available-for-sale securities. We describe the Our investments in debt and equity securities, which primarily nuclear decommissioning trusts and the related asset retirement consist of our nuclear decommissioning trust fund investments, obligations later in this Note. In addition, we have investments are subject to impairment evaluations under FASB Staff Position in marketable equity securities and trust assets securing certain (FSP) FAS 115-1, The Meaning of Other-Than-Temporary executive benefits that are classified as available-for-sale securities. Impairmentand Its Application to CertainInvestments. FSP We include any unrealized gains or losses on our available- FAS 115-1 requires us to determine whether a decline in fair for-sale securities in "Accumulated other comprehensive income" value of an investment below the amortized cost basis is other 84

than temporary. If we determine that the decline in fair value is merchant energy business. For all other assets, we remove the judged to be other than temporary, the cost basis of the accumulated depreciation and amortization amounts from our investment must be written down to fair value as a new cost Consolidated Balance Sheets and record any gain or loss in our basis. Consolidated Statements of Income.

The costs of maintenance and certain replacements are Intangible Assets charged to "Operating expenses" in our Consolidated Statements Goodwill is the excess of the purchase price of an acquired of Income as incurred.

business over the fair value of the net assets acquired. We Our oil and gas exploitation and production activities account for goodwill and other intangibles under the provisions consist of working interests in gas producing fields. We account of SFAS No. 142, Goodwill and Other IntangibleAssets. We do for these activities under the successful efforts method of not amortize goodwill. SFAS No. 142 requires us to evaluate accounting. Acquisition, development, and exploitation costs are goodwill for impairment at least annually or more frequently if capitalized as permitted by SFAS No. 19. Costs of drilling events and circumstances indicate the business might be exploratory wells are initially capitalized and later charged to impaired. Goodwill is impaired if the carrying value of the expense if reserves are not discovered or deemed not to be business exceeds fair value. Annually, we estimate the fair value commercially viable. Other exploratory costs are charged to of the businesses we have acquired using techniques similar to expense when incurred.

those used to estimate future cash flows for long-lived assets as Capitalized exploratory well costs were $24.7 million at previously discussed. If the estimated fair value of the business is December 31, 2006 and $11.4 million at December 31, 2005, less than its carrying value, an impairment loss is required to be and do not include amounts that were capitalized and recognized to the extent that the carrying value of goodwill is subsequently expensed within the same period. During 2006, greater than its fair value. SFAS No. 142 also requires the there were $23.9 million of well costs capitalized at amortization of intangible assets with finite lives. We discuss the December 31, 2005 that were reclassified to well, facilities, and changes in our intangible assets in more detail in Note 5. equipment based on the determination of proved reserves.

During 2005, there were $1.4 million of well costs capitalized at Property, Plant and Equipment, Depreciation, Depletion, December 31, 2004 that were reclassified to well, facilities, and Amortization, and Accretion of Asset Retirement equipment based on the determination of proved reserves.

Obligations No exploratory well costs have been capitalized for a period We report our property, plant and equipment at its original cost, greater than one year since the completion of drilling.

unless impaired under the provisions of SFAS No. 144.

Our original costs include: Depreciation and Depleton Espense

• material and labor, We compute depreciation for our generating, electric

+ contractor costs, and transmission and distribution, and gas distribution facilities. We

• construction overhead costs, financing costs, and costs compute depletion for our exploitation and production activities.

for asset retirement obligations (where applicable). Depreciation and depletion are determined using the following We own an undivided interest in the Keystone and methods:

Conemnaugh electric generating plants in Western Pennsylvania,

• the group straight-line method, approved by the as well as in the transmission line that transports the plants' Maryland PSC, applied to the average investment, output to the joint owners' service territories. Our ownership adjusted for anticipated costs of removal less salvage, in interests in these plants are 20.99% in Keystone and 10.56% in classes of depreciable property based on an average rate Conemnaugh. These ownership interests represented a net of approximately 3.5% per year for our regulated investment of $183.1 million at December 31, 2006 and business,

$171.8 million at December 31, 2005. Each owner is responsible

• the group straight-line method using rates averaging for financing its proportionate share of the plants' working approximately 2.5% per year for the fossil generating funds. Working funds are used for operating expenses and capital assets transferred from BCE to our merchant energy expenditures. Operating expenses related to these plants are business and our nuclear generating assets, included in "Operating expenses" in our Consolidated

• the modified units of production method (greater of Statements of Income. Capital costs related to these plants are straight-line method or units of production method) for included in "Nonregulated property, plant and equipment" in fossil generating assets constructed after deregulation our Consolidated Balance Sheets. that were not previously owned by BCE, or The "Nonregulated property, plant and equipment" in our

• the units-of-production method over the remaining life Consolidated Balance Sheets includes nonregulated generation of the estimated proved reserves at the field level for construction work in progress of $229.5 million at acquisition costs and over the remaining life of proved December 31, 2006 and $228.8 million at December 31, 2005. developed reserves at the field level for development W~Qhen we retire or dispose of property, plant and costs. The estimates for gas reserves are based on internal equipment, we remove the asset's cost from our Consolidated calculations.

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 85

Other assets are depreciated primarily using the straight- The increase in the capitalized cost is included in line method and the following estimated useful lives: determining depreciation expense over the estimated useful lives of these assets. Since the fair value of the asset retirement Asset Estimated Useful Lives obligations is determined using a present value approach, Building and improvements 5 - 50 years accretion of the liability due to the passage of time is recognized Office equipment and furniture 3 - 20 years each period to "Accretion of asset retirement obligations" in our Transportation equipment 5 - 15 years Consolidated Statements of Income until the settlement of the Computer software 3 - 10 years liability. We record a gain or loss when the liability is settled after retirement for any difference between the accrued liability and Amortization Expense actual costs. The change in our "Asset retirement obligations" Amortization is an accounting process of reducing an amount in liability during 2006 was as follows:

our Consolidated Balance Sheets over a period of time that approximates the useful life of the related item. W~(hen we reduce (In millions) amounts in our Consolidated Balance Sheets, we increase Liability at January 1, 2006 $908.0 amortization expense in our Consolidated Statements of Income. Liabilities incurred 3.4 Liabilities settled (0.3)

Accretion Expense Accretion expense 67.6 SFAS No. 143, AccountingforAsset Retirement Obligations, Revisions to cash flows (2.4) provides the accounting requirements for recognizing an Other (1.5) estimated liability for legal obligations associated with the Liability at December 31, 2006 $974.8 retirement of tangible long-lived assets. In the fourth quarter of 2005, we adopted FIN 47, Accounting for ConditionalAsset "Liabilities incurred" in the table above primarily reflect Retirement Obligations-an Interpretationof FASB Statement new asset retirement obligations recorded at our fossil generating No. 143. FIN 47 clarifies that asset retirement obligations that facilities in Maryland. "Other" represents the asset retirement are conditional upon a future event are subject to the provisions obligation associated with our gas-fired plants, which were sold of SFAS No. 143. Our conditional asset retirement obligations in December 2006. At the time of the sale, the asset retirement relate primarily to asbestos removal at certain of our generating obligation was transferred to the buyer of the gas-fired plants.

facilities. In 2005, we recorded an asset retirement obligation of We discuss the sale of the gas-fired plants in more detail in

$13.9 million for these facilities and recorded a $7.4 million Note 2.

after-tax charge to earnings as a cumulative effect of change in accounting principle. Nuclear Fuel At December 31, 2006, $950.4 million of our total asset We amortize the cost of nuclear fuel, including the quarterly fees retirement obligation of $974.8 million was associated with the we pay to the Department of Energy for the future disposal of decommissioning of our nuclear power plants-Calvert Cliffs spent nuclear fuel, based on the energy produced over the life of Nuclear Power Plant (Calvert Cliffs), Nine Mile Point Nuclear the fuel. These fees are based on the kilowatt-hours of electricity Station (Nine Mile Point) and R. E. Ginna Nuclear Power Plant sold. We report the amortization expense for nuclear fuel in (Cinna). The remainder of our asset retirement obligations is "Fuel and purchased energy expenses" in our Consolidated associated with our other generating facilities and certain other Statements of Income.

long-lived assets. From time to time, we will perform studies to updaxe our asset retirement obligations. We record a liability Nuclear Decommissioning when we are able to reasonably estimate the fair value of any Effective January 1, 2003, we began to record decommissioning future legal obligations associated with retirement that have been expense for Calvert Cliffs in accordance with SFAS No. 143. The incurred and capitalize a corresponding amount as part of the "Asset retirement obligations" liability associated with the book value of the related long-lived assets. 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 Allowance for Funds Used DuringConstruction (AFC)

Mile Point in accordance with SFAS No. 143 on January 1, BGE finances its construction projects with borrowed funds and 2003. The "Asset retirement obligations" liability associated with equity funds. BGE is allowed by the Maryland PSC to record the the decommissioning was $408.1 million at December 31, 2006 costs of these funds as part of the cost of construction projects in and $378.7 million at December 31, 2005. We determined that its Consolidated Balance Sheets. BGE does this through the the decommissioning trust funds established for Nine Mile Point AFC, which it calculates using rates authorized by the Maryland are adequately funded to cover the future costs to decommission PSC. BGE bills its customers for the AFC plus a return after the the plant and as such, no contributions were made to the trust utility property is placed in service.

funds during the years ended December 31, 2006, 2005, The AFC rates are 9.4% for electric plant, 8.5% for gas and 2004. plant, and 9.2% for common plant. BGE compounds AFC Upon the closing of the Ginna acquisition in 2004, the annually.

seller transferred $200.8 million in decommissioning funds. In return, we assumed all liability for the costs to decommission the Long-Term Debt unit. We believe that this transfer will be sufficient to cover the We defer all costs related to the issuance of long-term debt.

future costs to decommission the plant and as such, no These costs include underwriters' commissions, discounts or contributions were made to the trust funds during the years premiums, other costs such as legal, accounting, and regulatory ended December 31, 2006, 2005, and 2004. Effective fees, and printing costs. We amortize these costs into interest June 2004, we began to record decommissioning expense for expense over the life of the debt.

Ginna in accordance with SFAS No. 143. The "Asset retirement When BGE incurs gains or losses on debt that it retires obligations" liability associated with the decommissioning was prior to maturity, it amortizes those gains or losses over the

$209.9 million at December 31, 2006 and $196.6 million at remaining original life of the debt.

December 31, 2005.

In accordance with Nuclear Regulatory Commission Accounting Standards Issued (NRC) regulations, we maintain external decommissioning trusts SFAS No. 157 to fund the costs expected to be incurred to decommission In September 2006, the FASB issued SFAS No. 157, Fair Value Calvert Cliffs, Nine Mile Point, and Ginna. The NRC requires Measurements. SFAS No. 157 defines fair value, establishes a owners to provide financial assurance that they will accumulate framework for measuring fair value, and expands disclosures for sufficient funds to pay for the cost of nuclear decommissioning. fair value measurements. SFAS No. 157 is effective for all fair The assets in the trusts are reported in "Nuclear value measurements beginning January 1, 2008. We are decommissioning trust funds" in our Consolidated Balance currently assessing the potential impact of SFAS No. 157. Based Sheets. These amounts are legally restricted for funding the costs upon our initial assessment, we believe that SFAS No. 157 will of decommissioning. We classify the investments in the nuclear affect the accounting for derivatives, which is one of our critical decommissioning trust funds as available-for-sale securities, and accounting policies, in at least two ways:

we report these investments at fair value in our Consolidated

• We record mark-to-market energy assets net of a close-Balance Sheets as previously discussed in this Note. Investments out valuation adjustment, a portion of which represents by nuclear decommissioning trust funds are guided by the the initial contract margin when we are unable to obtain "prudent man" investment principle. The funds are prohibited observable market price information for similar from investing directly in Constellation Energy or its affiliates contracts. As a result, we do not recognize gains or losses and any other entity owning a nuclear power plant. in earnings at the inception of such contracts; instead, As the owner of Calvert Cliffs we, along with other we recognize gains or losses in earnings as we realize cash domestic utilities, were required by the Energy Policy Act of flows under the contract or when observable market data 1992 to make contributions to a fund for decommissioning and becomes available. In certain instances, SFAS No. 157 decontaminating the Department of Energy's uranium will require us to record mark-to-market energy assets at enrichment facilities. The contributions were paid by BGE over a fair value without such a valuation adjustment, resulting 15 year period ending in 2006. BGE amortizes the deferred costs in the potential for recognition of gains or losses in of decommissioning and decontaminating the Department of earnings at the inception of new mark-to-market Energy's uranium enrichment facilities. The previous owners derivative contracts executed after the effective date.

retained the obligation for Nine Mile Point and Ginna. + We presently determine fair value for mark-to-market energy liabilities and risk management liabilities for Capitalized Interest and Allowance for Funds Used which prices are not available from external sources by During Construction discounting the expected cash flows from the contracts CapitalizedInterest using a risk-free discount rate. We do not apply a credit-Our nonregulated businesses capitalize interest costs under SFAS spread valuation adjustment to reflect our own credit No. 34, CapitalizingInterest Costs, for costs incurred to finance risk in determining fair value for these liabilities.

our power plant construction projects, real estate developed for SFAS No. 157 will require us to record all liabilities internal use, and other capital projects. 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 plan funded status. The adoption of SFAS No. 158 did not have value for these liabilities. any impact on BGE's financial results or our, or BGE's, debt Because SFAS No. 157 applies broadly to all fair value covenants. We discuss the additional minimum pension liability measurements, we have not completed our assessment of its and the adoption of SFAS No. 158 in more detail in Note 7.

requirements, the effects of which could extend beyond the matters discussed on the previous page. In accordance with the FSP FIN 46R-6 statement's provisions, we will record the initial effects of In April 2006, the FASB issued Staff Position (FSP) FIN 46R-6, applying SFAS No. 157 by adjusting opening retained earnings Determiningthe Variabilityto Be Considered in Applying FASB as of the required January 1, 2008 adoption date for the effect of InterpretationNo. 46R. FSP FIN 46R-6 provides that, in eliminating the close-out valuation adjustment for applying FASB Interpretation No. 46R, Consolidation of Variable inception gains. The remaining impacts of adoption will be InterestEntities an InterpretationofARB No. 51, the reporting reflected in earnings in 2008. The ultimate impact of applying enterprise should consider the design of the entity, the nature of the provisions of SFAS No. 157 could be material to our, or the entity's risks, and the purpose for which the entity was BGE's, financial results. created. FSP FIN 46R-6 must be applied prospectively to new or modified contracts beginning July 1, 2006. The adoption of this FIN 48 FSP did not have a material impact on our, or BGE's, financial In July 2006, the FASB issued Interpretation (FIN) No. 48, results.

Accountingfor Uncertainty in Income Taxes. FIN 48 provides guidance for the recognition and measurement of an entity's FSP FAS 115-1 andFAS 124-1 uncertain tax positions through the use of a "more-likely-than- In November 2005, FASB Staff Position SFAS 115-1 and not" threshold. This threshold would be used to evaluate SFAS 124-1 (FSP FAS 115-1 and FAS 124-1), The Meaning of whether each tax position will be sustained based solely on its Other-Than- TemporaryImpairmentand its Application to Certain technical merits and assuming examination by a taxing authority. Investments, was issued to replace the measurement and FIN 48 must be applied to all tax positions beginning January 1, recognition criteria of EITF 03-1, The Meaning of Other-Than-2007. Based on the analysis performed to date, we estimate the Temporary Impairment and its Application to Certain Investments.

adoption of FIN 48 will not have a material impact on our, or FSP FAS 115-1 and FAS 124-1 references existing guidance in BGE's, financial results. As a result of pending implementation SFAS No. 115, SEC Staff Accounting Bulletin No. 59, guidance, we are still evaluating the impact of FIN 48, and Accountingfor NoncurrentMarketable Equity Securities, and APB therefore the actual impact of FIN 48 on our, or BGE's, financial No. 18. FSP FAS 115-1 and FAS 124-1 requires an other-than-results could differ from the above estimate. temporary analysis to be completed each reporting period (i.e.,

every quarter) beginning after December 15, 2005. The adoption Accounting Standards Adopted of this standard did not have a material impact on our, or BGE's, SFAS No. 158 financial results.

In September 2006, the FASB issued SFAS No. 158, Employers' Accountingfor Defined Benefit Pension and Other Postretirement SAB 108 Plans, an amendment of FASB Statements No. 87, 106 and In September 2006, the Securities and Exchange Commission 132(R). SFAS No. 158 requires the underfunded status of issued Staff Accounting Bulletin No. 108 (SAB 108), Considering defined benefit postretirement plans to be recognized as a the Effects ofPrior Year Misstatements when Quanti~jing liability in the balance sheets. Unrecognized actuarial losses or Misstatements in Current Year FinancialStatements. SAB 108 was gains, unrecognized prior service costs, and unrecognized issued in order to eliminate the diversity in practice surrounding transition amounts are recognized as part of accumulated other how public companies quantify financial statement comprehensive income, net of tax. Subsequent changes in funded misstatements.

status are recognized in the year in which changes occur through SAB 108 establishes an approach that requires accumulated other comprehensive income. SFAS No. 158 was quantification of financial statement misstatements based on the effective for us on December 31, 2006. effects of the misstatements on each financial statement and the Although we adopted SFAS No. 158 effective related financial statement disclosures. This model requires December 31, 2006, we were required to remeasure the quantification of errors based on both an income statement and additional minimum pension liability prior to calculating the balance sheet approach. SAB 108 required public companies to impact of adopting SFAS No. 158. As a result, we recorded a initially apply its provisions for fiscal periods ending after

$75.6 million after-tax increase to accumulated other November 15, 2006.

comprehensive income to reduce the additional minimum The implementation of SAB 108 did not have any effect on pension liability at December 31, 2006. This reflected favorable our financial results.

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 88

2 Other Events 2006 Events At the time of the agreement for sale, we evaluated these plants for classification as discontinued operations under Pre-Tax After-Tax SFAS No. 144. Discontinued operations classification only (In millions) applies to assets held for sale that meet the definition of a Gain on sale of gas-fired plants $ 73.8 $ 47.1 component of an entity. A component of an entity comprises Workforce reduction costs (28.2) (17.0) operations and cash flows that can be clearly distinguished, Merger-related costs (18.3) (5.7) operationally and for financial reporting purposes, from the rest Gain on initial public offering of of the entity.

Constellation Energy Partners LLC 28.7 17.9 High Desert met the requirements to be classified as a Income from discontinued operations discontinued operation because it had a power sales agreement High Desert 294.1 186.9 for its full output, was determined to be a component of International investments 1.4 0.9 Constellation Energy, and had separately identifiable cash Total income from discontinued flows. The table below provides additional detail about the operations 295.5 187.8 amounts recorded in "Income from discontinued operations" Total other items $351.5 $230.1 related to our High Desert facility.

The remaining gas-fired plants were managed within our Sale of Gas-Fired Plants merchant business as a group or on a portfolio basis because In December 2006, we completed the sale of the following they have aggregated risks, were hedged as a group, and natural gas-fired plants owned by our merchant energy generated joint cash flows. These gas-fired plants do not meet business: the requirements to be classified as discontinued operations.

The results of operations for these gas-fired plants, as well as Capacity the $73.8 million pre-tax gain on sale, remain classified in Facility (MW Unit Type Location continuing operations.

High Desert 830 Combined Cycle California Rio Nogales 800 Combined Cycle Texas International Investments Holland 665 Combined Cycle Illinois In the fourth quarter of 2005, we completed the sale of University Park 300 Peaking Illinois Constellation Power International Investments, Ltd. (CPII).

Big Sandy 300 Peaking West Virginia We recognized an after-tax gain of $0.9 million for the year Wolf Hills 250 Peaking Virginia ended December 31, 2006 due to the resolution of an outstanding contingency related to the sale. We discuss the We sold these gas-fired plants for cash of $1.6 billion, details of the outstanding contingency later in this Note.

which is subject to working capital adjustments, and recognized Presented in the table below are the amounts related to a pre-tax gain on the sale of $259.0 million of which those discontinued operations that are included in "Income

$73.8 million was included in "Gain on sale of gas-fired plants" from discontinued operations" in our Consolidated Statements and $185.2 million was included in "Income from of Income:

discontinued operations" in our Consolidated Statements of Income.

High Desert Oleander Intrenational Investments Total 2006 2005 2004 2006 2005 2004 2006 2005 2004 2006 2005 2004 (In millions)

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) millionfrom the sale of our Hawaiian Geothermalfacility in 2004. We discuss the sale of this facility later in this Note.

89

Workforce Reduction Costs Merger-Relatedcosts In March 2006, we approved a restructuring of the workforce We incurred costs during 2006 related to the proposed merger at our Ginna nuclear facility. In connection with this with FPL Group. The merger was terminated in October 2006.

restructuring, 32 employees were terminated. During the These costs totaled $18.3 million pre-tax for 2006. In addition, quarter ended March 31, 2006, we recognized costs of during 2006 we recognized tax benefits of $5.3 million on

$2.2 million pre-tax related to recording a liability for severance merger costs incurred in 2005 that were not considered and other benefits under our existing benefit programs. deductible for income tax purposes until the termination of the We completed this workforce reduction effort in 2006. As merger in 2006. Our total pre-tax merger-related costs were a result, no involuntary severance liability was recorded at $35.3 million.

December 31, 2006.

In July 2006, we announced a planned restructuring of InitialPublic Offering of ConstellationEnergy PartnersLLC In November 2006, Constellation Energy Partners LLC (CEP),

the workforce at our Nine Mile Point nuclear facility. We a limited liability company formed by Constellation Energy, recognized costs during the quarter ended September 30, 2006 completed an initial public offering of 5.2 million common of $15.1 million pre-tax related to the elimination of 126 units at $21 per unit. The initial public offering resulted in positions associated with this restructuring. We also initiated a cash proceeds of $101.3 million, after expenses associated with restructuring of the workforce at our Calvert Cliffs nuclear the offering, for Constellation Energy.

facility during the third quarter of 2006 and we recognized We continue to own approximately 54% of CEP and as a costs of $2.9 million pre-tax related to the elimination of result, we continue to consolidate CEP. As a result of the initial 30 positions associated with this restructuring. public offering of CEP, we recognized a pre-tax gain of In addition, we incurred a pre-tax settlement charge of $28.7 million, or $17.9 million after recording deferred taxes

$12.7 million in accordance with Statement of Financial on the gain.

Accounting Standards (SFAS) No. 88, Employers'Accountingfor Settlements and CurtailmentsofDefined Benefit Pension Plans 2005 Events andfor Termination Benefits. This charge reflects recognition of the portion of deferred actuarial gains and losses associated with Pre-Tax After-Tax employees who were terminated as part of the restructuring or (In millions) retired in 2006 and who elected to receive their pension benefit Merger-related costs $ (17.0) $ (15.6) in the form of a lump-sum payment. In accordance with Workforce reduction costs (4.4) (2.6)

SFAS No. 88, a settlement charge must be recognized when Income from discontinued operations lump-sum payments exceed annual pension plan service and High Desert 111.0 70.8 interest cost. The total SFAS No. 88 settlement charge incurred International investments 40.1 20.6 in 2006 includes a pre-tax charge of $8.0 million as a result of Oleander 4.9 3.0 the Nine Mile Point restructuring. We discuss the settlement Total income from discontinued charges that we recorded during 2006 in Note 7. operations 156.0 94.4 The following table summarizes the status of the Total other items $134.6 $ 76.2 involuntary severance liability for Nine Mile Point and Calvert "Incomefrom discontinuedoperations" reflects the reclassification Cliffs at December 31, 2006: of earningsfrom our High Desertfacility as required by SFAS No. 144.

(In millions)

Initial severance liability balance $19.6 Merger-RelatedCosts Amounts recorded as pension and We incurred external costs associated with the execution of the postretirement liabilities (7.3) agreement relating to our proposed merger with FPL Group.

Net cash severance liability 12.3 We discuss the terminated merger in more detail in Note 15.

Cash severance payments (3.2)

Other Workforce Reduction Costs Severance liability balance at December 31, As a result of the workforce reduction efforts initiated in 2004, 2006 $ 9.1 in 2005 we were required to record a pre-tax settlement charge The severance liability above includes $1.6 million ofcosts that the in our Consolidated Statements of Income of $4.4 million for joint owner ofNine Mile Point Unit 2 reimbursed us. 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.

90

Discontinued Operations Workforce Reduction Costs Oleander In the fourth quarter of 2004, we approved a restructuring of In March 2005, we reached an agreement in principle to sell the work forces of the Nine Mile Point and Calvert Cliffs our Oleander generating facility, a four-unit peaking plant nuclear generating stations that was effective in January 2005.

located in Florida. Our merchant energy business classified In connection with this restructuring, approximately 108 Oleander as held for sale and performed an impairment test employees received severance and other benefits under our under SFAS No. 144 as of March 31, 2005. The impairment existing benefit programs. At December 31, 2004, we accrued test indicated that the carrying value of the plant was higher the estimated total cost of this reduction in workforce of than its fair value less costs to sell, and therefore in March 2005 $9.7 million pre-tax, or $5.9 million after-tax, in accordance we recorded an impairment charge of $4.8 million pre-tax as with applicable accounting requirements.

part of discontinued operations.

In June 2005, we completed the sale of this facility for S~ynthetic Fuel Tax Credits

$217.6 million, and recognized a pre-tax gain on the sale of In 2003, we purchased a 99% ownership in a South Carolina

$1.2 million as part of discontinued operations.

facility that produces synthetic fuel. We did not recognize in our Consolidated Statements of Income the tax benefit of InternationalInvestments $35.9 million for credits claimed on our South Carolina facility In October 2005, we sold CPII. CPII held our other in 2003 pending receipt of a favorable private letter ruling from nonregulated international investments, which represented an the Internal Revenue Service (IRS). In April 2004, we received interest in a Panamanian electric distribution company and an a favorable private letter ruling. We believe receipt of the investment in a fund that holds interests in two South private letter ruling provided assurance that it is highly American energy projects. We received cash of $71.8 million probable that the credits will be sustained. Therefore, we and recognized a pre-tax gain of approximately $25.6 million, recognized the tax benefit of $35.9 million in our Consolidated or $16.1 million after-tax. An additional $3.6 million of the Statements of Income in 2004. We discuss the synthetic fuel sales price was contingent upon the collection of certain tax credits in more detail in Note J0.

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- Discontinued Operations tax gain. We recognized the remaining $1.4 million of GeothermalFclt contingent proceeds in 2006 once realization was assured In March 2004, management committed to a plan to sell our beyond a reasonable doubt. geothermal generating facility in Hawaii that met the "held for sale" criteria under SFAS No. 144. Under SFAS No. 144, we 2004 Events record assets and liabilities held for sale at the lesser of the carrying amount or fair value less cost to sell.

Pre-Tax After-Tax The fair value of the facility as of March 31, 2004, based (In millions) on the bids under consideration, was below carrying value.

Workforce reduction costs $ (9.7) $ (5.9) Therefore, we recorded a $71.6 million pre-tax, or Recognition of 2003 synthetic fuel tax $47.3 million after-tax, impairment charge during the first.

credits - 35.9 quarter of 2004. We reported the after-tax impairment charge (Loss) income from discontinued as a component of "Loss from discontinued operations" in our operations Consolidated Statements of Income. Additionally, we Hawaiian geothermal facility (75.6) (49.1) recognized $1.5 million pre-tax, or $1.0 million after-tax, of High Desert 106.9 68.4 earnings from the facility for the quarter ended March 31, International investments 16.8 9.4 2004 as a component of "Loss from discontinued operations."

Oleander 20.5 12.6 In June 2004, we completed the sale of the facility. Based Total income from discontinued operations 68.6 41.3 on the final sales price and other costs incurred over the Total other items $ 58.9 $ 71.3 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 "Incomefrom discontinued operations"reflects the reclassification facility was reflected in our merchant energy business of/earningsfrom our High Desert facility, the Oleanderfacility, reportable segment.

and our internationalinvestments as requiredby SFAS No. 144.

91

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

Regulated Electric, and Regulated Gas:

• design, construct, and operate heating, cooling, and

• Our merchant energy business is nonregulated and cogeneration facilities for commercial, industrial, and includes: governmental customers throughout North America,

- full requirements load-serving sales of energy and and capacity to utilities, cooperatives, and commercial,

• provide home improvements, service electric and gas industrial, and governmental customers, appliances, service heating, air conditioning, plumbing,

- structured transactions and risk management services electrical, and indoor air quality systems, and provide for various customers (including hedging of output natural gas marketing to residential customers in from generating facilities and fuel costs), Central Maryland.

- deployment of risk capital through portfolio During 2006, we sold six of our gas-fired facilities. In management and trading activities, addition, we own several investments that we do not consider

- gas retail energy products and services to commercial, to be core operations. These include financial investments and industrial, and governmental customers, real estate projects. During 2005, we sold our other

- fossil, nuclear, and interests in hydroelectric generating nonregulated international investments. We discuss the sales of facilities and qualifying facilities, fuel processing our gas-fired plants and our international investments in more facilities, and power projects in the United States, detail in Note 2.

- upstream (exploration and production) and Our Merchant Energy, Regulated Electric, and Regulated downstream (transportation and storage) natural gas Gas reportable segments are strategic businesses based operations, principally upon regulations, products, and services that require

- coal sourcing services for the variable or fixed supply different technology and marketing strategies. We evaluate the needs of global customers, and performance of these segments based on net income. We

- generation operations and maintenance services. account for intersegment revenues using market prices. We

• Our regulated electric business purchases, transmits, present a summary of information by operating segment on the distributes, and sells electricity in Central Maryland. next page.

• Our regulated gas business purchases, transports, and sells natural gas in Central Maryland.

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Reportable Segments Merchant Regulated Regulated Other Energy Electric Gas 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 10,188.3 1,967.7 757.0 201.1 (986.9) 12,127.2 Depreciation and amortization 221.9 194.2 48.1 24.2 - 488.4 Fixed charges 196.2 80.3 29.1 15.4 5.8 326.8 Income tax expense (benefit) 22.8 86.8 15.9 (7.1) - 118.4 Income from discontinued operations 31.9 9.4 41.3 Net income (loss) (c) 389.9 131.1 22.2 (3.5) -- 539.7 Segment assets 12,395.6 3,402.2 1,163.4 675.7 (289.8) 17,347.1 Capital expenditures 455.0 209.0 56.0 42.0 -- 762.0 Certainprior-yearamounts have been reclassifiedto conform with the currentyear ipresentation. The reclassificationsprimarilyrelate to operationsthat have been classifiedas discontinuedoperationsin the currentyear.

(a) Our merchant energy business recognizedan after-taxgain of $47.1 million on sale ofgas-firedplants and an after-taxgain of

$17.9 million on the initialpublic offering of ConstellationEnergy PartnersLLC as discussed in more detail in Note 2. Our merchant energy business, our regulatedelectric business, our regulatedgas business, and our other nonregulatedbusinesses recognized after-tax charges of $21.3 million, $0.8 million, $0.4 million, and $0.2 millionfor merger-relatedcosts and workforce reduction costs as described in more detail in Note 2.

(b) Our merchant energy business, our regulatedelectric business, our regulatedgas business, and our other nonregulatedbusinesses recognized after-tax charges of $13.0 million, $3.7million, $1.3 million, and $0.2 millionfor 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 syntheticfuel tax credits and workforce reduction costs as described in more detail in Note 2.

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4 Investments Investments in Qualifying Facilities and Power Projects We show the fair values, gross unrealized gains and losses, Our merchant energy business holds up to a 50% voting and amortized cost basis for all of our available-for-sale interest in 24 operating domestic energy projects that consist of securities, in the following tables. We use specific identification electric generation, fuel processing, or fuel handling facilities. to determine cost in computing realized gains and losses.

Of these 24 projects, 17 are "qualifying facilities" that receive certain exemptions and pricing under the Public Utility Amortized Unrealized Unrealized Fair At December 31, 2006 Cost Basis Gains Losses Value Regulatory Policies Act of 1978 based on the facilities' energy (In millions) source or the use of a cogeneration process.

Investments in qualifying facilities and domestic power Marketable equity projects held by our merchant energy business consist of the securities $ 811.0 $221.1 $(3.3) $1,028.8 following: Corporate debt and U.S. treasuries 160.1 1.9 (0.3) 161.7 AtDecember3l, 2006 2005 State municipal bonds 68.1 5.4 (0.2) 73.3 (In millions) Totals $1,039.2 $228.4 $(3.8) $1,263.8 Coal $125.7 $127.8 Amortized Unrealized Unrealized Fair Hydroelectric 55.1 55.9 At December 31, 2005 Cost Basis Gains Losses Value Geothermal 40.5 43.7 (In millions)

Biomass 46.6 48.0 Marketable equity Fuel Processing 33.7 23.8 securities $ 804.4 $112.7 $(3.8) $ 913.3 Solar 7.0 7.0 Corporate debt and Total $308.6 $306.2 U.S. treasuries 114.8 0.2 (1.4) 113.6 State municipal bonds 107.1 2.8 (0.8) 109.1 Investments in qualifying facilities and domestic power Totals $1,026.3 $115.7 $(6.0) $1,136.0 projects were accounted for under the following methods:

In addition to the above securities, the nuclear AtDecember3l, 2006 2005 decommissioning trust funds included $24.1 million at (In millions) December 31, 2006 and $12.2 million at December 31, 2005 Equity method $301.6 $299.2 of cash and cash equivalents.

Cost method 7.0 7.0 The preceding tables include $206.1 million in 2006 of Total power projects $308.6 $306.2 net unrealized gains and $110.3 million in 2005 of net unrealized gains associated with the nuclear decommissioning Our percentage voting interest in qualifying facilities and trust funds that are reflected as a change in the nuclear domestic power projects accounted for under the equity decommissioning trust funds in our Consolidated Balance method ranges from 16% to 50%. Equity in earnings of these Sheets.

power projects was $13.8 million in 2006, $3.6 million in We have unrealized losses relating to certain available-for-2005, and $18.0 million in 2004. sale investments included in our decommissioning trust funds.

Our power projects include investments of $220.5 We believe these losses are temporary in nature and expect the million in 2006 and $228.6 million in 2005 that sell electricity investments to recover their value in the future. We show the in California under power purchase agreements. fair values and unrealized losses of our investments that were in a loss position at December 31, 2006 and 2005 in the tables Investments Classified as Available-for-Sale below.

We classify the following investments as available-for-sale:

At December 31, 2006

• nuclear decommissioning trust funds, Less than 12 months or

• marketable equity securities, and 12 months more Total

• trust assets securing certain executive benefits. Description of Fair Unrealized Fair Unrealized Fair Unrealized Securities Value Losses Value Losses Value Losses This means we do not expect to hold them to maturity, (In millions) and we do not consider them trading securities. 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 The following is summary information available as of Less than 12 months or 12 months more Total December 31, 2006 about the VIEs in which we have a Description of Fair Unrealized Fair Unrealized Fair Unrealized significant interest, but are not the primary beneficiary:

Securities Value Losses Value Losses Value Losses (In millions)

Power Marketable Contract All equity Mlonetization Other securities $ 22.3 $(2.9) $ 2.3 $(0.3) $ 24.6 $(3.2) VIEs VIEs Total Corporate debt (In millions) and U.S. Total assets $746.1 $355.5 $1,101.6 treasuries 71.8 (1.1) 11.8 (0.3) 83.6 (1.4) Total liabilities 592.6 162.0 754.6 State municipal Our ownership interest - 51.5 51.5 bonds 46.0 (0.6) 11.8 (0.2) 57.8 (0.8)

Other ownership Total interests 153.5 142.0 295.5 temporarily impaired Our maximum securities $140.1 $(4.6) $25.9 $(0.8) $166.0 $(5.4) exposure to loss 65.8 92.3 158.1 The maximum exposure to loss represents the loss that we Gross and net realized gains and losses on available-for-would incur in the unlikely event that our interests in all of sale securities were as follows:

these entities were to become worthless and we were required to fund the full amount of all guarantees associated with these 2006 2005 2004 entities. Our maximum exposure to loss as of December 31, (In millions) 2006 consists of the following:

Gross realized gains $ 13.3 $12.3 $ 4.1

+ outstanding receivables, loans, and letters of credit Gross realized losses (13.0) (9.3) (7.7) totaling $94.0 million, Net realized gains (losses) $ 0.3 $ 3.0 $(3.6)

• the carrying amount of our investment totaling

$51.4 million, and Gross realized losses for 2004 include a $4.5 million pre-

• debt and performance guarantees totaling tax impairment charge we recognized on a nuclear

$12.7 million.

decommissioning trust fund investment that we believed We assess the risk of a loss equal to our maximum represented an other than temporary decline in value.

exposure to be remote.

The corporate debt securities, U.S. Government agency obligations, and state municipal bonds mature on the following Customer Contract Restructurin.

schedule:

In March 2005, our merchant energy business closed a At December 31, 2006 transaction in which we assumed from a counterparty two (In millions) power sales contracts with existing VIEs. Under the contracts, Less than 1 year $ 7.6 we sell power to the VIEs which, in turn, sell that power to an 1-5 years 74.9 electric distribution utility through 2013.

5-10 years 62.4 The VIEs previously were created by the counterparty to More than 10 years 90.1 issue debt in order to monetize the value of the original Total maturities of debt securities $235.0 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 Investments in Variable Interest Entities

$568 million at December 31, 2006.

We have a significant interest in the following variable interest The market price for power at the closing of our entities (VIE) for which we are not the primary beneficiary: transaction was higher than the contract price under the existing power sales contracts we assumed. Therefore, we Nature of Date of received compensation totaling $308.5 million, equal to the net VIE Involvement Involvement present value of the difference between the contract price under Power projects and Equity investment and Prior to 2003 the power sales contracts and the market price of power at fuel supply entities guarantees closing. We used a portion of this amount to settle Power contract Power sale agreements, March 2005

$68.5 million of existing derivative liabilities with the same monetization loans, and counterparty, and we also loaned $82.8 million to the holder of entities guarantees the equity in the VIEs. As a result, we received net cash at Oil & gas fields Equity investment May 2006 closing of $157.2 million. We also guaranteed our subsidiaries' Retail power supply Power sale agreement September 2006 performance under the power sales contracts.

We discuss the nature of our involvement with the power contract monetization VIEs in the Customer Contract Restructuringsection below.

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The table below summarizes the transaction and the net We recorded the gross compensation we received to cash received at closing: assume the power sales contracts as a financing cash inflow because it constitutes a prepayment for a portion of the market (In millions) price of power, which we will sell to the VIEs over the term of Gross compensation from original power sales the contracts and does not represent a cash inflow from current contracts counterparty equal to fair value of period operating activities. We record the ongoing cash flows power sales contracts at closing $308.5 related to the sale of power to the VIEs as a financing cash Settlement of existing derivative liabilities (68.5) inflow in accordance with SFAS No. 149, Amendment ofFASB Third-party loan secured by equity in VIE (82.8) Statement No. 133 on Derivativeand HedgingActivities.

Net cash received at closing $157.2 If the electric distribution utility were to default under its obligation to buy power from the VIEs, the equity holder could We recorded the closing of this transaction in our transfer its equity interests to us in lieu of repaying the loan. In financial statements as follows: this event, we would have the right to seek recovery of our Balance Sheet Cash Flows losses from the electric distribution utility.

Fair value of power Risk management Financing cash sales contracts liabilities inflow assumed (designated as cash-flow hedge)

Settlement of Mark-to-market Operating cash existing derivative and risk outflow liabilities management liabilities Third-party loan Other assets Investing cash outflow 96

5 Intangible Assets Goodwill The following is our, and BGE's, estimated amortization Goodwill is the excess of the cost of an acquisition over the fair expense for 2007 through 2011 for the intangible assets included value of the net assets acquired. Our goodwill balance is in our, and BGE's, Consolidated Balance Sheets at primarily related to our merchant energy business acquisitions December 31, 2006:

that occurred in 2002 and 2003. The changes in the carrying amount of goodwill for the years ended December 31, 2006 and Year Ended December 31, 2007 2008 2009 2010 2011 2005 are as follows: (In millions)

Estimated amortization expense-Nonregulated businesses $41.6 $36.3 $29.0 $20.8 $15.2 Balance at Goodwill Balance at Estimated amortization expense-2006 January 1, Acquired Other(a) December 31, BGE 19.3 16.7 13.4 12.0 9.9 (In millions) Total estimated amortization Goodwill $147.1 $11.1 $(0.6) $157.6 expense-Constellation Energ $60.9 $53.0 $42.4 $32.8 $25.1 Balance at Goodwill Balance at Unamortized Energy Contracts 2005 January 1, Acquired Other December 31, (In millions) As discussed in Note 1, unamortized energy contract assets and liabilities represent the remaining unamortized balance of Goodwill $144.8 $2.3 $- $147.1 nonderivative energy contracts acquired or derivatives designated (a) Other represents purchase price adjustments.

as normal purchases and normal sales, which we previously Goodwill is not amortized; rather, it is evaluated for recorded as mark-to-market energy or risk management assets impairment at least annually. We evaluated our goodwill in 2006 and liabilities.

and 2005 and determined that it was not impaired. For tax During 2005, we acquired several pre-existing purposes, $128.5 million of our goodwill balance is deductible. nonderivative contracts that had been originated by other parties in prior periods when market prices were lower than current Intangible Assets Subject to Amortization levels. We received approximately $530 million in cash and other Intangible assets with finite lives are subject to amortization over consideration and recorded a liability in "Unamortized energy their estimated useful lives. The primary assets included in this contracts." In addition, during 2005, we designated as normal category are as follows: purchases and normal sales contracts that we had previously recorded as cash-flow hedges in "Risk management liabilities."

At December 31, 2006 2005 This resulted in a reclassification of $888.5 million from "Risk Accumul- Accumul- management liabilities" to "Unamortized energy contract Gross ated Gross ated liabilities."

Carrying Amortiz- Net Carrying Amortiz- Net Amount ation Asset Amount ation Asset We present separately in our Consolidated Balance Sheets (In millions) the net unamortized energy contract assets and liabilities for Software $392.3 $(182.6) $209.7 $364.7 $(156.5) $208.2 these contracts. The table below presents the gross and net Permits and carrying amount and accumulated amortization of the net licenses 60.4 (5.9) 54.5 49.4 (12.6) 36.8 Operating liability that we have recorded in our Consolidated Balance manuals and Sheets:

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 At December 31 2006 2005 Total $517.5 $(212.8) $304.7 $482.4 $(189.4) $293.0 Accumul- Accumul-ated ated BGE had intangible assets with a gross carryingamount of$191.3 Carrying Amortiz- Net Carrying Amortiz- Net Amount anon Liability Amount ation Liability million and accumulatedamortization of$109.2 million at (In millions)

December31, 2006 and $181.4 million and accumulated Unamortized amortization of $98.7 million at December31, 2005 that are energy included in the table above. Substantially all of BGE's intangible contracts, net $(1,642.0) $ 464.5 $(1,177.5)$(1,449.2) $ 37.8 $(1,411.4) assets relate to software.

The table below presents the estimated net favorable impact We recognized amortization expense related to our on our operating results for the amortization for these assets and intangible assets as follows: liabilities over the next five-years:

Year Ended December 31, 2006 2005 2004 Year Ended December31, 2007 2008 2009 2010 2011 (In millions) (In millions)

Nonregulated businesses $37.2 $30.6 $25.0 Estimated amortization $342.8 $255.4 $178.0 $166.6 $41.8 BGE 18.6 26.3 41.4 Total Constellation Energy $55.8 $56.9 $66.4 97

6Regulatory Assets (net)

As discussed in Note 1, the Maryland PSC and the FERC We exclude deferred fuel costs from rate base because their provide the final determination of the rates we charge our existence is relatively short-lived. These costs are recovered in the customers for our regulated businesses. Generally, we use the following year through our fuel rates.

same accounting policies and practices used by nonregulated companies for financial reporting under accounting principles Electric Generation-Related Regulatory Asset generally accepted in the United States of America. However, As a result of the deregulation of electric generation, BGE ceased sometimes the Maryland PSC or FERC orders an accounting to meet the requirements for the application of SFAS No. 71 for treatment different from that used by nonregulated companies to the previous electric generation portion of its business. In determine the rates we charge our customers. When this accordance with SFAS No. 101, Regulated Enterprises-happens, we must defer certain regulated expenses and income in Accounting for the DiscontinuationofApplication of FASB our Consolidated Balance Sheets as regulatory assets and Statement No. 71, and EITF 97-4, Deregulationof the Pricingof liabilities. We then record them in our Consolidated Statements Electricity-IssuesRelated to the Application ofFASB Statements of Income (using amortization) when we include them in the No. 71 and 101. BGE wrote-off all of its individual, rates we charge our customers. generation-related regulatory assets and liabilities. BGE We summarize regulatory assets and liabilities in the established a single, generation-related regulatory asset to be following table, and we discuss each of them separately below. collected through its regulated transmission and distribution business, which is being amortized on a basis that approximates At December31, 2006 2005 the pre-existing individual regulatory asset amortization (In millions) schedules.

Deferred fuel costs A portion of this regulatory asset represents income taxes Rate stabilization deferral $ 326.9 $ - recoverable through future rates that do not earn a regulated rate Other 37.8 16.2 of return. These amounts were $89.4 million as of December 31, Electric generation-related regulatory asset 154.8 173.6 2006 and $97.9 million as of December 31, 2005. We will Net cost of removal (161.3) (148.7) continue to amortize this amount through 2017.

Income taxes recoverable through future Another portion of this regulatory asset represents the rates (net) 67.1 70.9 decommissioning and decontamination fund payment for federal Deferred postretirement and uranium enrichment facilities that do not earn a regulated rate of postemployment benefit costs 19.3 22.6 return on the rate base investment. These amounts were $5.5 Deferred environmental costs 10.0 14.9 million at December 31, 2006 and $8.6 million at December 31, Workforce reduction costs 4.9 7.3 2005. Prior to the deregulation of electric generation, these costs Other (net) (8.0) (2.5) were recovered through the electric fuel rate mechanism, and Total regulatory assets (net) 451.5 154.3 were excluded from rate base. We will continue to amortize this Less: Current portion of regulatory assets amount through 2008.

(net) 62.5 -

Long-term portion of regulatory assets Net Cost of Removal (net) $ 389.0 $ 154.3 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 Deferred Fuel Costs accepted in the United States of America and is widely used in Rate Stabilization Deferral the energy, transportation, and telecommunication industries.

In June 2006, Senate Bill 1 was enacted in Maryland, which Historically, under the group depreciation method, the imposes a rate stabilization measure that caps rate increases by anticipated costs of removing assets upon retirement were BGE for residential electric customers at 15% from July 1, 2006 provided for over the life of those assets as a component of to May 31, 2007. As a result, BGE is recording a regulatory asset depreciation expense. However, effective January 1, 2003, we on its Consolidated Balance Sheets equal to the difference adopted SFAS No. 143, AccountingforAsset Retirement between the costs to purchase power and the revenues collected Obligations.In addition to providing the accounting from customers, as well as related carrying charges based on requirements for recognizing an estimated liability for legal short-term interest rates from July 1, 2006 to May 31, 2007.

obligations associated with the retirement of tangible long-lived During 2006, BGE deferred $326.9 million of electricity assets, SFAS No. 143 precludes the recognition of expected net purchased for resale expenses and carrying charges as a regulatory future costs of removal as a component of depreciation expense asset related to the rate stabilization plan. BGE will amortize the regulatory asset to earnings over a period not to exceed ten years or accumulated depreciation.

BGE is required by the Maryland PSC to use the group once collection from customers begins.

depreciation method, including cost of removal, under regulatory accounting. For ratemaking purposes, net cost of removal is a Other component of accumulated depreciation and is included as a net As described in Note 1, deferred fuel costs are the difference reduction to BGE's rate base investment. In accordance with between our actual costs of purchased energy and our fuel rate SFAS No. 71, BGE continues to accrue for the future cost of revenues collected from customers. We reduce deferred fuel costs removal for its regulated gas and electric assets by increasing its as we collect them from or refund them to our customers.

regulatory liability. This liability is relieved when actual removal costs are incurred.

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Income Taxes Recoverable Through Future Rates (net) these costs (the amount we had incurred through October 1995)

As described in Note 1, income taxes recoverable through future and are amortizing $6.4 million of these costs (the amount we rates are the portion of our net deferred income tax liability that incurred from November 1995 through June 2000) over 10-year is applicable to our regulated business, but has not been reflected periods in accordance with the Maryland PSC's orders. We in the rates we charge our customers. These income taxes applied for and received rate relief for an additional $5.4 million represent the tax effect of temporary differences in depreciation of clean-up costs incurred during the period from July 2000 and the allowance for equity funds used during construction, through November 2005. These costs are being amortized over a offset by differences in deferred tax rates and deferred taxes on 10-year period that began in January 2006.

deferred investment tax credits. We amortize these amounts as the temporary differences reverse. Workforce Reduction Costs The portions of the costs associated with our Voluntary Special Deferred Postretirement and Postemployment Benefit Early Retirement Program and workforce reduction programs Costs that relate to BGE's gas business are deferred as regulatory assets Deferred postretirement and postemployment benefit costs are in accordance with the Maryland PSC's orders in prior rate cases.

the costs we recorded under SFAS No. 106, Employers' As a result of a 2005 gas base rate case, the remaining regulatory Accountingfor PostretirementBenefits Other Than Pensions, and assets associated with workforce reductions totaling $7.3 million SFAS No. 112, Employers'Accountingfor Postemployment Benefits, as of December 31, 2005 are being amortized over a 3-year in excess of the costs we included in the rates we charge our period that began in January 2006. These remaining regulatory customers. We began amortizing these costs over a 15-year assets were previously amortized over 5-year periods beginning in period in 1998. January and February 2002.

Deferred Environmental Costs Other (Net)

Deferred environmental costs are the estimated costs of Other regulatory assets are comprised of a variety of current investigating and cleaning up contaminated sites we own. We assets and liabilities that do not earn a regulatory rate of return discuss this further in Note 12. We amortized $21.6 million of due to their short-term nature.

7Pension, Postretirement, Other Postemployment, and Employee Savings Plan Benefits We offer pension, postretirement, other postemployment, and Pension Benefits employee savings plan benefits. BGE employees participate in We sponsor several defined benefit pension plans for our the benefit plans that we offer. We describe each of our plans employees. These include basic qualified plans that most separately below. Nine Mile Point offers its own pension, employees participate in and several nonqualified plans that are postretirement, other postemployment, and employee savings available only to certain employees. A defined benefit plan plan benefits to its employees. The benefits for Nine Mile Point specifies the amount of benefits a plan participant is to receive are included in the tables beginning below. using information about the participant. Employees do not We use a December 31 measurement date for our pension, contribute to these plans. Generally, we calculate the benefits postretirement, other postemployment, and employee savings under these plans based on age, years of service, and pay.

plans. In 2006, the FASB issued SFAS No. 158, which was Sometimes we amend the plans retroactively. These adopted on December 31, 2006. We discuss SFAS No. 158 in retroactive plan amendments require us to recalculate benefits more detail in Note 1. The following table summarizes our related to participants' past service. We amortize the change in defined benefit liabilities and their classification in our the benefit costs from these plan amendments on a straight-line Consolidated Balance Sheets: basis over the average remaining service period of active employees.

At December31, 2006 2005 We fund the qualified plans by contributing at least the (in millions) minimum amount required under IRS regulations. We calculate Pension benefits $468.6 $401.4 the amount of funding using an actuarial method called the Postretirement benefits 441.5 327.9 projected unit credit cost method. The assets in all of the plans at Postemployment benefits 57.0 54.7 December 31, 2006 and 2005 were mostly marketable equity Total defined benefit obligations 967.1 784.0 and fixed income securities.

Less: Amount recorded in accrued expenses and other* 38.8 - Postretirement Benefits Total noncurrent defined benefit We sponsor defined benefit postretirement health care and life obligations $928.3 $784.0 insurance plans that cover the majority of our employees.

• Amount recordedas currentportion ofdefined benefit liability in Generally, we calculate the benefits under these plans based on 2006is based on the expected cash payments associatedwith age, years of service, and pension benefit levels or final base pay.

unfundedplans during the next 12 months. ConstellationEnergy We do not fund these plans. For nearly all of the health care did not recordthe currentportion ofits defined benefit obligation plans, retirees make contributions to cover a portion of the plan priorto the December 2006 implementation of SFAS No. 158.

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costs. For the life insurance plan, retirees do not make We were required to remeasure the additional minimum contributions to cover a portion of the plan costs. pension liability prior to calculating the impact of adopting Effective in 2002, we amended our postretirement medical SFAS No. 158 on December 31, 2006. We recorded the plans for all subsidiaries other than Nine Mile Point. Our additional minimum pension liability adjustments as follows:

contributions for retiree medical coverage for future retirees who Increase (Decrease) were under the age of 55 on January 1, 2002 are capped at the Pension Accumulated Other 2002 level. We also amended our plans to increase the Medicare Liability Intangible Comprehensive Loss eligible retirees' share of medical costs. Adjustment Asset

• Pre-tax After-tax In 2003, the President signed into law the Medicare (In millions)

Prescription Drug Improvement and Modernization Act of 2003 Cumulative through 2004 $ 359.6 $40.6 $(319.0) $(192.8)

(the Act). This legislation provides a prescription drug benefit for 2005 121.4 (6.1) (127.5) (77.1)

Medicare beneficiaries, a benefit that we provide to our Medicare 2006 (131.1) (5.9) 125.2 75.6 eligible retirees. Our actuaries concluded that prescription drug Total $ 349.9 $28.6 $(321.3) $(194.3) benefits available under our postretirement medical plan are Includedin "Otherassets" in our ConsolidatedBalance Sheets.

"actuarially equivalent" to Medicare Part D and thus qualify for the subsidy under the Act. In 2005, the Center for Medicare and Upon adoption of SFAS No. 158, we reversed the Medicaid Services accepted our application to receive a tax intangible asset associated with the minimum pension liability reimbursement for eligible prescription drug costs, and we began adjustment, increased our pension and postretirement liabilities, to receive the subsidy in 2006. The actual subsidy offsets a and reduced equity. The following table summarizes the impact portion of our share of the cost of the underlying postretirement of the adoption of SFAS No. 158 at December 31, 2006:

prescription drug coverage. This legislation reduced our Increase (Decrease)

Accumulated Postretirement Benefit Obligation by Postrefirement Accumulated Other

$42.6 million at January 1, 2005 and our annual postretirement Pension Benefit Intangible Comprehensive Loss benefit expense in 2005 by $5.4 million. This subsidy reduced Liability Liability Asset Pre-tax After-tax (In millions) our 2006 cash medical costs by $1.8 million, or by 7%.

December 31, 2006 $152.5 $99.7 $(28.6) $(280.8) $(169.5)

Pension Liability Adjustments Our pension accumulated benefit obligation has exceeded the SFAS No. 158 reducedour deferred income tax liabiliy by $111.3 million.

fair value of our plan assets since 2001. At December 31, 2006 Obligations and Assets and 2005, our pension obligations were greater than the fair As a result of workforce reduction initiatives in the generation value of our plan assets for our qualified and our nonqualified business, pension and postretirement special termination benefits pension plans as follows: were recorded in 2006 and 2005. We discuss the workforce reduction initiatives further in Note 2.

Qualified Plans Non-Qualified At December31, 2006 Nine Mile Other Plans Total We show the change in the benefit obligations and plan (In millions) assets of the pension and postretirement benefit plans in the Accumulated benefit following tables. Postretirement benefit plan amounts are obligation $107.5 $1,306.0 $63.8 $1,477.3 presented net of expected reimbursements under Medicare Fair value of assets 54.6 1,106.6 - 1,161.2 Part D.

Unfunded obligation $ 52.9 $ 199.4 $63.8 $ 316.1 Pension Postretirement Benefits Benefits Qualified Plans Non-Qualified 2006 2005 2006 2005 At December 31, 2005 Nine Mile Other Plans Total (In millions)

(In millions) Change in benefit Accumulated benefit obligation (1)

Benefit obligation at January 1 $1,678.6 $1,513.2 $460.4 $423.2 obligation $127.1 $1,325.1 $56.3 $1,508.5 Service cost 49.0 44.8 7.7 7.6 Fair value of assets 84.9 1,022.2 - 1,107.1 Interest cost 89.3 83.9 23.7 23.8 Unfunded obligation $ 42.2 $ 302.9 $56.3 $ 401.4 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 projectedbenefit obligationforpension benefits and accumulatedpostretirement benefit obligationfor postretirementbenefits.

(2) Benefits paidinclude annuitypayments, lump-sum distributions,and transfers to nonqualifieddeferred compensationplans.

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Pension Postretirement As a result of adopting SFAS No. 158, at December 31, Benefits Benefits 2006 the following is a summary of amounts we have recorded in 2006 2005 2006 2005 (In millions)

"Accumulated other comprehensive income" and of expected Change in plan assets amortization of those amounts over the next twelve months:

Fair value of plan assets at January 1 $1,107.1 $1,084.4 $ - $ - Estimated Actual return on plan assets 141.1 76.2 - - Amortization Pension Postretirement Next 12 Employer contribution(1) 55.2 53.0 26.7 29.8 At December 31, 2006 Benefits Benefits Months Plan participants' contributions - - 8.3 7.4 (In millions)

Benefits paid(2) (142.2) (106.5) (35.0) (37.2)

Unrecognized net actuarial Fair value of plan assets at loss $475.7 $116.6 $37.1 December 31 $1,161.2 $ 1,107.1 $ - $

Unrecognized prior service (1) Includes benefitpayments for unfundedplans. cost 26.7 (29.7) 1.7 (2) Benefits paid include annuitypayments, lump-sum distributions,and Unrecognized transition transfersto nonqualifieddeferred compensationplans. obligation - 12.8 2.1 Total $502.4 $ 99.7 $40.9 Net Periodic Benefit Cost and Amounts Recognized in Other Comprehensive Income Expected Cash Benefit Payments We show the components of net periodic pension benefit cost in The pension and postretirement benefits we expect to pay in the following table: each of the next five calendar years and in the aggregate for the subsequent five years are shown below. These estimated benefits Year Ended December 31, 2006 2005 2004 are based on the same assumptions used to measure the benefit (In millions) obligation at December 31, 2006, but include benefits Components of net periodic pension benefit attributable to estimated future employee service.

cost Service cost $ 49.0 $ 44.8 $ 40.1 Postretirement Benefits Interest cost 89.3 83.9 82.3 Before After Expected return on plan assets (96.6) (100.2) (97.9)

Pension Medicare Medicare Amortization of unrecognized prior service Benefits* Part D Subsidy Part D cost 5.7 5.7 5.8 (In millions)

Recognized net actuarial loss 37.3 25.1 14.3 2007 $105.5 $ 30.8 $ 2.7 $ 28.1 Amount capitalized as construction cost (13.4) (7.4) (4.5) 2008 97.7 31.9 2.9 29.0 Net periodic pension benefit cost (1) $ 71.3 $ 51.9 $ 40.1 2009 100.3 33.0 3.1 29.9 (1) Net periodicpension benefit cost excludes SFAS No. 88 settlement charge 2010 111.5 33.8 3.2 30.6 of $12.7 million, and termination benefits of $4.2 million in 2006,SFAS 2011 108.4 34.6 3.4 31.2 No. 88 settlement charge of$4.4 million in 2005, and SFAS No. 88 2012-2016 688.5 182.7 18.9 163.8 settlement charge of $2.8 million and termination benefits of$2.4 million

• Excludes transfers to nonqualifieddeferred compensationplans in 2004. BGEs portion of our netperiodicpension 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 Assumptions BGE employees. We made the assumptions below to calculate our pension and postretirement benefit obligations and periodic cost.

We show the components of net periodic postretirement benefit cost in the following table: Pension Postretirement Assumption Benefits Benefits Impacts Year Ended December 31, 2006 2005 2004 2006 2005 2006 2005 Calculation of (In millions) Benefit Components of net periodic postretirement Obligation and benefit cost Discount rate 6.00% 5.50% 6.00% 5.50% Periodic Cost Service cost $ 7.7 $ 7.6 $ 6.5 Expected return on Interest cost 23.7 23.8 22.6 plan assets 8.75 9.0 NIA N/A Periodic Cost Amortization of transition obligation 2.1 2.1 2.1 Rate of Benefit Recognized net actuarial loss 6.6 6.4 3.1 compensation Obligation and Amortization of unrecognized prior service cost (3.5) (3.5) (3.5) increase 4.0 4.0 4.0 4.0 Periodic Cost Amount capitalized as construction cost (8.2) (7.7) (7.0)

Our discount rate is based on a bond portfolio analysis of Net periodic postretirement benefit cost (1) $28.4 $28.7 $23.8 high quality corporate bonds whose maturities match our (1) Net periodicpostretirementbenefit cost excludes SFAS No. 106 expected benefit payments. Our 8.75% overall expected long-terminationbenefits of $3.5 million in 2006and$1.2 million in 2004.

term rate of return on plan assets reflects our long-term BGE'portion of our net periodicpostretirement benefit cost, excluding amounts capitalized, was $166million in 2006,$17.4 million in 2005, investment strategy in terms of asset mix targets and expected and $15.1 million in 2004. 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 Contributions and Benefit Payments long-term returns applied to our targeted asset allocation. We contributed an additional $52 million to our qualified Annual health care inflation rate assumptions also impact pension plans in March 2006, even though there was no IRS the calculation of our postretirement benefit obligation and required minimum contribution in 2006. We expect to periodic cost. We assumed the following health care inflation contribute $125 million to our pension plans in 2007. Our non-rates to produce average claims by year as shown below: qualified pension plans and our postretirement benefit programs are not funded. We estimate that we will incur approximately At December31, 2006 2005 $3.8 million in pension benefits for our non-qualified pension Next year 8.5% 9.0% plans and approximately $28 million for retiree health and life Following year 8.0% 8.0% insurance costs net of Medicare Part D during 2007.

Ultimate trend rate 5.0% 5.0%

Year ultimate trend rate reached 2014 2010 Other Postemployment Benefits A one-percent increase in the health care inflation rate from We provide the following postemployment benefits:

the assumed rates would increase the accumulated postretirement

• health and life insurance benefits to eligible employees determined to be disabled under our Disability benefit obligation by approximately $32.1 million as of December 31, 2006 and would increase the combined service Insurance Plan, and interest costs of the postretirement benefit cost by

• income replacement payments for Nine Mile Point union-represented employees determined to be disabled, approximately $2.2 million annually.

and A one-percent decrease in the health care inflation rate from the assumed rates would decrease the accumulated

• income replacement payments for other employees determined to be disabled before November 1995 postretirement benefit obligation by approximately $26.8 million (payments for employees determined to be disabled after as of December 31, 2006 and would decrease the combined service and interest costs of the postretirement benefit cost by that date are paid by an insurance company, and the cost approximately $1.8 million annually. is paid by employees).

We recognized expense associated with our other postemployment benefits of $9.6 million in 2006, $9.2 million Qualified Pension Plan Assets in 2005, and $10.8 million in 2004. BGE's portion of expense The asset allocations for our qualified pension plans were as associated with other postemployment benefits was $5.6 million follows:

in 2006, $5.4 million in 2005, and $8.2 million in 2004.

We assumed the discount rate for other postemployment At December31, 2006 2005 benefits to be 5.50% in 2006 and 5.25% in 2005. This Equity securities 64% 59%

assumption impacts the calculation of our other postemployment Debt securities 28 32 benefit obligation and periodic cost.

Other 8 9 Total 100% 100%

Employee Savings Plan Benefits The category "Other" primarily represents investments in We sponsor defined contribution savings plans that are offered to financial limited partnerships. Our long-term pension plan all eligible employees. The savings plans are qualified investment strategy is to seek an asset mix of 58% equity, 30% 401(k) plans under the Internal Revenue Code. In a defined fixed income, and 12% other investments. We rebalance our contribution plan, the benefits a participant is to receive result portfolio periodically when the sum of equity and other from regular contributions to a participant account. Matching investments differs from 70% by three percentage points or contributions to participant accounts are made under these more, we change an outside investment advisor, or we make plans. Matching contributions to these plans were:

contributions to the trust. * $20.0 million, of which BGE contributed $5.4 million, We determine expected return on plan assets using a in 2006, market-related value of plan assets that recognizes asset gains and * $18.6 million, of which BGE contributed $5.1 million, losses ratably over a five-year period. 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, business. Additionally, we can borrow directly from the banks commercial paper, and bank lines of credit. Short-term or use the facilities to allow the issuance of commercial paper borrowings mature within one year from the date of issuance. with the exception of the $1.0 billion 364-day facility, which We pay commitment fees to banks for providing us lines of only supports $500.0 million of letters of credit and the $200 credit. When we borrow under the lines of credit, we pay million 364-day facility, which only supports letters of credit.

market interest rates. These facilities can issue letters of credit up to approximately $4,050 million. Letters of credit issued under all Constellation Energy of our facilities totaled $1,648 million at December 31, 2006 Constellation Energy had committed bank lines of credit under and $2,486 million at December 31, 2005. The decrease in credit facilities of $4,550 million at December 31, 2006 for letters of credit issued is primarily due to changes in collateral short-term financial needs as follows: requirements with counterparties as a result of commodity

• $1.0 billion 364-day credit facility expiring in price changes.

October 2007, In 2005, our merchant energy business executed several

• $200 million 364-day credit facility expiring in short-term repurchase agreements that resulted in $0.7 million December 2007, of net short-term borrowings which matured in January 2006.

• $1.5 billion five-year revolving credit facility expiring in March 2010, BiE

• $1.1 billion five-year revolving credit facility expiring BGE had no commercial paper outstanding at December 31, in November 2010, and 2006 or 2005.

• $750.0 million five-year revolving credit facility BGE has a $400.0 million five-year revolving credit expiring in November 2010. facility expiring in 2011. BGE can borrow directly from the We enter into these facilities to ensure adequate liquidity banks or use the agreements to allow the issuance of to support our operations. Currently, we use the facilities to commercial paper.

issue letters of credit primarily for our merchant energy 9Long-Term Debt and Preference Stock Long-term Debt lien of BGE's mortgage, along with the stock of Safe Harbor Long-term debt matures in one year or more from the date of Water Power Corporation and Constellation Enterprises, Inc.

issuance. We detail our long-term debt in our Consolidated BGE is required to make an annual sinking fund payment Statements of Capitalization. As you read this section, it may be each August 1 to the mortgage trustee. The amount of the helpful to refer to those statements. payment is equal to 1% of the highest principal amount of bonds outstanding during the preceding 12 months. The trustee uses ConstellationEnergy these funds to retire bonds from any series through repurchases On October 31, 2006, CEP entered into a $200.0 million or calls for early redemption. However, the trustee cannot call secured revolving credit facility. The credit facility will mature on the two remaining outstanding bonds for early redemption:

October 31, 2010. The amount available for borrowing at any + 7V2% Series, due 2007 one time is limited to the borrowing base, which is initially set at + 65/8% Series, due 2008

$75.0 million. At December 31, 2006, CEP had $22.0 million of borrowings outstanding under this ,facility. As discussed in BGE's Other Long- Term Debt Note 13, in 2006, CEP executed floating-to-fixed interest rate In October 2006, BGE issued $300.0 million of 5.90% Notes, swaps related to $16.5 million of its outstanding debt. due October 1, 2016 and $400.0 million of 6.35% Notes, due In May 2006, we issued $122.0 million of tax-exempt October 1, 2036. We used the proceeds from these issuances for variable rate notes to refinance tax-exempt pollution control general corporate purposes, including refinancing the following loans. We used $75.0 million of the net proceeds to refinance a long-term debt of BGE:

6.00% pollution control revenue refunding loan in June 2006 + $300.0 million of 5.25% Notes, due December 15, and in July 2006 we used the remaining $47.0 million of 2006, proceeds to refinance a 5.55% pollution control revenue * $121.4 million of 7.5% First Refunding Mortgage refunding loan. Bonds, due January 15, 2007, and

• $10.0 million of 6.70% Medium-term Notes, Series D, BGE due December 1, 2006.

BGE's FirstRefunding MorZaae Bonds On July 1, 2000, BGE transferred $278.0 million of tax-BGE's first refunding mortgage bonds are secured by a mortgage exempt debt to our merchant energy business related to the lien on all of its assets. The generating assets BGE transferred to transferred generating assets. At December 31, 2006, BGE subsidiaries of Constellation Energy also remain subject to the remains contingently liable for the $147.8 million outstanding balance of this debt.

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We show the weighted-average interest rates and maturity while under variable rates. The bonds can also be converted to a dates for BGE's fixed-rate medium-term notes outstanding at fixed rate at ComfortLink's option.

December 31, 2006 in the following table.

Weighted-Average Maturity Debt Compliance and Covenants Series Interest Rate The credit facilities of Constellation Energy and BGE discussed Dates in Note 8 have limited material adverse change clauses that only E 6.66% 2007-2012 consider a material change in financial condition and are not G 6.08% 2008 directly affected by decreases in credit ratings. If these clauses are Some of the medium-term notes include a "put option." invoked, the lending institutions can decline to make new These put options allow the holders to sell their notes back to advances or issue new letters of credit, but cannot accelerate BGE on the put option dates at a price equal to 100% of the existing amounts outstanding. The long-term debt indentures of principal amount. The following is a summary of medium-term Constellation Energy and BGE do not contain material adverse notes with put options. change clauses or financial covenants.

Certain credit facilities of Constellation Energy contain a Series E Notes Principal Put Option Dates provision requiring Constellation Energy to maintain a ratio of (In millions) debt to capitalization equal to or less than 65%. At 6.75%, due 2012 $59.5 June 2007 December 31, 2006, the debt to capitalization ratio as defined in 6.75%, due 2012 25.0 June 2007 the credit agreements was 48%.

6.73%, due 2012 25.0 June 2007 The credit agreement of BGE contains a provision requiring BGE to maintain a ratio of debt to capitalization equal BGE Deferrable Interest SubordinatedDebentures to or less than 65%. At December 31, 2006, the debt to On November 21, 2003, BGE Capital Trust II (BGE Trust II), capitalization ratio for BGE as defined in this credit agreement a Delaware statutory trust established by BGE, issued was 49%. At December 31, 2006, no amounts were outstanding 10,000,000 Trust Preferred Securities for $250 million ($25 under these agreements.

liquidation amount per preferred security) with a distribution Failure by Constellation Energy, or BGE, to comply with rate of 6.20%. these covenants could result in the acceleration of the maturity of BGE Trust II used the net proceeds from the issuance of the debt outstanding under these facilities. The credit facilities of common securities to BGE and the Trust Preferred Securities to Constellation Energy contain usual and customary cross-default purchase a series of 6.20% Deferrable Interest Subordinated provisions that apply to defaults on debt by Constellation Energy Debentures due October 15, 2043 (6.20% debentures) from and certain subsidiaries over a specified threshold. The BGE BGE in the aggregate principal amount of $257.7 million with credit facility also contains usual and customary cross-default the same terms as the Trust Preferred Securities. BGE Trust II provisions that apply to defaults on debt by BGE over a specified must redeem the Trust Preferred Securities at $25 per preferred threshold. The indenture pursuant to which BGE has issued and security plus accrued but unpaid distributions when the 6.20% outstanding mortgage bonds provides that a default under any debentures are paid at maturity or upon any earlier redemption. debt instrument issued under the indenture may cause a default BGE has the option to redeem the 6.20% debentures at any time of all debt outstanding under such indenture.

on or after November 21, 2008 or at any time when certain tax Constellation Energy also provides credit support to or other events occur. Calvert Cliffs, Ginna, and Nine Mile Point to ensure these plants BGE Trust II will use the interest paid on the 6.20% have funds to meet expenses and obligations to safely operate and debentures to make distributions on the Trust Preferred maintain the plants.

Securities. The 6.20% debentures are the only assets of BGE Trust II. Maturities of Long-Term Debt BGE fully and unconditionally guarantees the Trust Our long-term borrowings mature on the following schedule:

Preferred Securities based on its various obligations relating to the trust agreement, indentures, 6.20% debentures, and the Constellation Nonregulated preferred security guarantee agreement. Year Energy Businesses BGE For the payment of dividends and in the event of (In millions) liquidation of BGE, the 6.20% debentures are ranked prior to 2007 $ 600.0 $ 20.5 $ 121.4 preference stock and common stock. 2008 - 6.5 294.6 2009 500.0 1.2 11.5 Revolving CreditAgreement 2010 - 22.3 -

On December 18, 2001, BGE's subsidiary, District Chilled 2011 - 36.5 22.0 Water Partnership (ComfortLink) entered into a $25.0 million Thereafter 1,942.9 260.4 1,267.2 loan agreement with the Maryland Energy Financing Total long-term debt at Administration (MEFA). The terms of the loan exactly match December 31, 2006 $3,042.9 $347.4 $1,716.7 the terms of variable rate, tax exempt bonds due December 1, 2031 issued by MEFA for ComfortLink to finance the cost of At December 31, 2006, we had long-term loans totaling building a chilled water distribution system. The interest rate on $384.3 million that mature after 2006, which contain certain put this debt resets weekly. These bonds, and the corresponding options under which lenders could potentially require us to repay loan, can be redeemed at any time at par plus accrued interest the debt prior to maturity, or which are periodically remarketed 104

and could require repayment following any unsuccessful Preference Stock remarketing. As a result of these provisions, at December 31, Each series of BGE preference stock has no voting power, except 2006, $136.9 million is classified as current portion of long-term for the following:

debt at BGE. + the preference stock has one vote per share on any charter amendment which would create or authorize any Weighted-Average Interest Rates for Variable Rate Debt shares of stock ranking prior to or on a parity with the Our weighted-average interest rates for variable rate debt were: preference stock as to either dividends or distribution of assets, or which would substantially adversely affect the At December31, 2006 2005 contract rights, as expressly set forth in BGE's charter, of NonregulatedBusinesses (including the preference stock, each of which requires the ConstellationEnergy) affirmative vote of two-thirds of all the shares of Loans under credit agreements 3.69% 4.71% preference stock outstanding; and Tax-exempt debt 3.63% 2.77% + whenever BGE fails to pay full dividends on the Fixed-rate debt converted to floating* 6.26% 4.72% preference stock and such failure continues for one year, BGE the preference stock shall have one vote per share on all Remarketed floating rate series mortgage matters, until and unless such dividends shall have been bonds -% 3.14% paid in full. Upon liquidation, the holders of the

• As discussedin Note 13, we have enteredinto interest rateswaps preference stock of each series outstanding are entitled to relatingto $450.0 million of ourfixed-rate debt. receive the par amount of their shares and an amount equal to the unpaid accrued dividends.

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10 Taxes The components of income tax expense are as follows:

Year Ended December31, 2006 2005 2004 (Dollaramounts 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 Certainprioryear amounts have been reclassifiedto conform to the currentyear presentation ofdiscontinuedoperations.

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%

Certainprioryear amounts have been reclassifiedto conform to the currentyear's presentation ofdiscontinuedoperations.

• 2004 includes credits associatedwith 2003 production at our South Carolinafacilitythat were recognizedin the second quarterof2004 upon receipt ofa favorablePrivateLetter 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%).

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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 Certainprioryear amounts have been reclassifiedto conform to the currentyear'spresentation.

Synthetic Fuel Tax Credits 2003 and 2004 tax years and the IRS did not disallow any of Our merchant energy business has investments in facilities that the previously recognized synthetic fuel credits.

manufacture solid synthetic fuel produced from coal as defined The IRC provides for a phase-out of synthetic fuel tax under the Internal Revenue Code (IRC) for which we can credits if average annual wellhead oil prices increase above claim tax credits on our Federal income tax return through certain levels. To determine the amount of the phase-out, we 2007. We recognize the tax benefit of these credits in our are required to compare average annual wellhead oil prices per Consolidated Statements of Income when we believe it is barrel as published by the IRS (reference price) to a Gross highly probable that the credits will be sustained. The synthetic National Product inflation adjusted oil price for the year, also fuel process involves combining coal material with a chemical published by the IRS. The reference price is determined based reagent to create a significant chemical change. A taxpayer may on wellhead prices for all domestic oil production as published request a private letter ruling from the IRS to support its by the Energy Information Administration (EIA). For 2006, we position that the synthetic fuel produced undergoes a estimate the tax credit reduction would begin if the reference significant chemical change and thus qualifies for synthetic fuel price exceeds approximately $55 per barrel and would be fully tax credits. phased out if the reference price exceeds approximately We own a minority ownership in four synthetic fuel $68 per barrel.

facilities located in Virginia and West Virginia. These facilities Based on monthly EIA published wellhead oil prices for have received private letter rulings from the IRS. In 2004, the the ten months ended October 31, 2006 and November and IRS concluded its examination of the partnership that owns December NYMEX prices for light, sweet, crude oil (adjusted these facilities for the tax years 1998 through 2001 and the IRS for the 2006 difference between EIA and NYMEX prices), we did not disallow any of the previously recognized synthetic fuel estimate a 38% tax credit phase-out in 2006. We recorded the credits. effect of this phase-out estimate as a reduction in tax credits of In 2003, we purchased 99% ownership in a South $44.3 million during 2006.

Carolina facility that produces synthetic fuel. We did not Based on forward market prices and volatilities as of recognize in our Consolidated Statements of Income the tax February 22, 2007, we estimate a 21% tax credit phase-out for benefit of $35.9 million for credits claimed on our South the year 2007. The expected amount of synthetic fuel tax Carolina facility in 2003 pending receipt of a favorable private credits phased-out may change materially from period to period letter ruling. In 2004, we received a favorable private letter as a result of continued changes in oil prices.

ruling. We believe receipt of the private letter ruling provides While we believe the production and sale of synthetic fuel reasonable assurance that it is highly probable that the credits from all of our synthetic fuel facilities meet the conditions to will be sustained. Therefore, we recognized the tax benefit of qualify for tax credits under the IRC, we cannot predict the

$35.9 million in our Consolidated Statements of Income timing or outcome of any future challenge by the IRS, during 2004. In 2006, the IRS concluded its examination of legislative or regulatory action, or the ultimate impact of such the partnership that owns the South Carolina facility for the 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 limitations. Income tax returns filed in other jurisdictions are Our consolidated federal income tax returns for the for the tax also subject to audit for additional tax periods. Although the years 2002 through 2004 are currently under examination by final outcome of current and future tax audits is uncertain, we the IRS. Our consolidated federal income tax returns for the believe that adequate provisions for income taxes have been 2001 and prior tax years are closed under the statute of made for potential liabilities resulting from such matters.

11I Leases There are two types of leases--operating and capital. Capital We recognized expense related to our operating leases as leases qualifyi as sales or purchases of property and are reported follows:

in our Consolidated Balance Sheets. Our capital leases are not material in amount. All other leases are operating leases and are Fuel and reported in our Consolidated Statements of Income. We purchased expense all lease payments associated with our regulared energy Operating business. Lease expense and future minimum payments for expenses expenses Total long-term, noncancelable, operating leases are not material to (In millions)

BGE's financial results. We present information about our 2006 $162.6 $24.7 $187.3 operating leases below. 2005 103.2 24.8 128.0 2004 11.0 23.1 34.1 Outgoing Lease Payments At December 31, 2006, we owed future minimum We, as lessee, lease some facilities and equipment. The lease payments for long-term, noncancelable, operating leases as agreements expire on various dates and have various renewal follows:

options. We also enter into certain power purchase agreements which are accounted for as operating leases. Under these Power agreements, we are required to make fixed capacity payments, Purchase Yea r Agreements Other Total as well as variable payments based on actual output of the (In millions) plants. We record these payments as "Fuel and purchased 2007 $162.0 $ 24.0 $186.0 energy expenses" in our Consolidated Statements of Income. 2008 121.5 19.6 141.1 We exclude from our future minimum lease payments table the 2009 62.3 18.9 81.2 variable payments related to the output of the plant due to the 2010 59.4 17.8 77.2 contingency associated with these payments. 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 addition, our merchant energy business enters into long-term We have made substantial commitments in connection with contracts for the capacity and transmission rights for the our merchant energy, regulated electric and gas, and other delivery of energy to meet our physical obligations to our nonregulated businesses. These commitments relate to: customers. These contracts expire in various years between

• purchase of electric generating capacity and energy, 2007 and 2019.

• procurement and delivery of fuels, Our merchant energy business also has committed to

• the capacity and transmission and transportation rights long-term service agreements and other purchase commitments for the physical delivery of energy to meet our for our plants.

obligations to our customers, and Our regulated electric business enters into various long-

• long-term service agreements, capital for construction term contracts for the procurement of electricity. These programs, and other. contracts expire between 2007 and 2009. As discussed in Our merchant energy business enters into various long- Note 1, the cost of power under these contracts is fully term contracts for the procurement and delivery of fuels to recoverable, and therefore is excluded from the table on the supply our generating plant requirements. In most cases, our next page.

contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. These contracts expire in various years between 2007 and 2020. In 108

Our regulated gas business enters into various long-term Guarantees contracts for the procurement, transportation, and storage of Our guarantees do not represent incremental Constellation gas. Our regulated gas business has gas transportation and Energy Group obligations; rather they primarily represent storage contracts that expire between 2007 and 2028. These parental guarantees of subsidiary obligations. The following contracts are recoverable under BGE's gas cost adjustment table summarizes the maximum exposure based on the stated clause discussed in Note 1, and therefore are excluded from the limit of our outstanding guarantees at December 31, 2006:

table below.

At December31, 2006 Stated Limit Our other nonregulated businesses have committed to gas (In millions) purchases and to contributions of additional capital for Competitive supply guarantees $10,001.8 construction programs and joint ventures in which they have Nuclear guarantees 917.8 an interest. BGE guarantees 263.3 We have also committed to long-term service agreements Other non-regulated guarantees 75.2 and other obligations related to our information technology Power project guarantees 19.2 systems. Total guarantees $11,277.3 At December 31, 2006, we estimate our future obligations to be as follows: At December 31, 2006, Constellation Energy had a total of $11,277.3 million in guarantees in outstanding related to Payments loans, credit facilities, and contractual performance of certain of 2008- 2010- its subsidiaries as described below.

2007 2009 2011 Thereafter Total (In millions)

• Constellation Energy guaranteed $10,001.8 million on Merchant Energy: behalf of our subsidiaries for competitive supply Purchased capacity activities. These guarantees are put into place in order 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 to allow our subsidiaries the flexibility needed to Long-term service conduct business with counterparties without having to agreements, capital, post other forms of collateral. While the face amount and other 15.8 10.1 5.5 23.9 55.3 of these guarantees is $10,001.8 million, our calculated Total merchant energy 3,249.4 2,632.9 753.2 1,444.3 8,079.8 Corporate and Other: fair value of obligations for commercial transactions Long-term service covered by these guarantees was $2,190.6 million at agreements, capital, December 31, 2006. If the parent company was and other 33.0 17.0 4.1 - 54.1 Regulated:

required to fund these subsidiary obligations, the total Purchase obligations amount based on December 31, 2006 market prices and other 54.4 40.9 - 2.2 97.5 would be $2,190.6 million. For those guarantees Total future obligations $3,336.8 $2,690.8 $757.3 $1,446.5 $8,231.4 related to our mark-to-market energy or risk management liabilities, the fair value of the obligation TerminationofMerger Agreement with FPL Group, Inc.

is recorded in our Consolidated Balance Sheets.

In connection with the termination of the merger agreement

• Constellation Energy guaranteed $917.8 million with FPL Group, there are certain contingencies relating to primarily on behalf of our nuclear generating facilities potential cash payments. We discuss these contingencies in mostly due to nuclear insurance and for credit support Note 15.

to ensure these plants have funds to meet expenses and obligations to safely operate and maintain the plants.

Long-Term Power Sales Contracts

• BGE guaranteed the Trust Preferred Securities of We enter into long-term power sales contracts in connection

$250.0 million of BGE Trust II, an unconsolidated with our load-serving activities. We also enter into long-term investment, as discussed in Note 9.

power sales contracts associated with certain of our power

+ BGE guaranteed two-thirds of certain debt of Safe plants. Our load-serving power sales contracts extend for terms Harbor Water Power Corporation, an unconsolidated through 2019 and provide for the sale of energy to electricity investment. At December 31, 2006, Safe Harbor distribution utilities and certain retail customers. Our power Water Power Corporation had outstanding debt of sales contracts associated with our power plants extend for

$20.0 million. The maximum amount of BGE's terms into 2014 and provide for the sale of all or a portion of guarantee is $13.3 million.

the actual output of certain of our power plants. All long-term

• Constellation Energy guaranteed $62.7 million on contracts were executed at pricing that approximated market behalf of our other nonregulated businesses primarily rates, including profit margin, at the time of execution.

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.

109

We believe it is unlikely that we would be required to Kane and Lombard perform or incur any losses associated with guarantees of our The EPA issued its record of decision for the Kane and subsidiaries' obligations. Lombard Drum site located in Baltimore, Maryland on September 30, 2003, which specified the clean-up plan for the Contingenies site, consisting of enhanced reductive dechlorination, a soil Revenue Sufficiency Guarantee Costs management plan, and institutional controls. An EPA order In April 2006, the FERC issued an order requiring the requiring cleanup of the site by 18 parties, including Midwest Independent System Operator (MISO) to Constellation Energy, became effective in November 2006.

retroactively re-allocate revenue sufficiency guarantee costs The EPA estimates that total clean-up costs will be (RSGs) for the period April 2005 to present based on the approximately $7 million. Our share of site-related costs will be FERC's finding that MISO violated its tariff and incorrectly 11.1% of the total. We recorded a liability in our Consolidated allocated RSGs among market participants. The re-allocation Balance Sheets for our share of the clean-up costs that we of RSGs would result in some participants recognizing believe is probable.

additional expense and others receiving refunds.

In May 2006, the MISO filed a motion with FERC Spring Gardens seeking a stay of the FERC order. The motion was granted by In December 1996, BGE signed a consent order with the FERC delaying the implementation of the original order until Maryland Department of the Environment that requires it to after the issuance of an order on rehearing. In May 2006, we implement remedial action plans for contamination at and and other market participants filed requests for rehearing around the Spring Gardens site, located in Baltimore, with FERC. Maryland. The Spring Gardens site was once used to In October 2006, FERC issued an order on rehearing that manufacture gas from coal and oil. Based on remedial action reversed the original retroactive re-allocation of RSGs. Based on plans and cost modeling performed in late 2006, BGE this order we estimate the impact of the RSG re-allocation, if estimates its probable clean-up costs will total $43 million.

any, to be immaterial to our financial results. However, further BGE has recorded these costs as a liability in its Consolidated requests for rehearing and appeals have been submitted and we Balance Sheets and has deferred these costs, net of accumulated cannot predict the ultimate timing or outcome of any such amortization and amounts it recovered from insurance action. companies, as a regulatory asset. Based on the results of studies at this site, it is reasonably possible that additional costs could Environmental Matters exceed the amount BGE has recognized by approximately Solid and Hazardous Waste $3 million. Through December 31, 2006, BGE has spent The Environmental Protection Agency (EPA) and several state approximately $40 million for remediation at this site.

agencies have notified us that we are considered a potentially BGE also has investigated other small sites where gas was responsible party with respect to the clean-up of certain manufactured in the past. We do not expect the clean-up costs environmentally contaminated sites. We cannot estimate the of the remaining smaller sites to have a material effect on our final clean-up costs for all of these sites, but the current financial results.

estimated costs for, and current status of, each site is described in more detail below. Air Quality In late July 2005, we received two Notices of Violation 68th Street Dum= (NOVs) from the Placer County Air Pollution Control In 1999, the EPA proposed to add the 68th Street Dump in District, Placer County California (District) alleging that the Baltimore, Maryland to the Superfund National Priorities List, Rio Bravo Rocklin facility located in Lincoln, California had which is its list of sites targeted for clean-up and enforcement, violated certain District air emission regulations. We have a and sent a general notice letter to BGE and 19 other parties combined 50% ownership interest in the partnership which identifying them as potentially liable parties at the site. In owns the Rio Bravo Rocklin facility. The NOVs allege a total March 2004, we and other potentially responsible parties of 38 violations between January 2003 and March 2005 of formed the 68th Street Coalition and entered into consent either the facility's air permit or federal, state, and county air order negotiations with the EPA to investigate clean-up options emission standards related to nitrogen oxide, carbon monoxide, for the site under the Superfund Alternative Sites Program. In and particulate emissions, as well as violations of certain May 2006, a settlement among the EPA and 19 of the monitoring and reporting requirements during that time potentially responsible parties, including BGE, with respect to period. The maximum civil penalties for the alleged violations investigation of the site became effective. The settlement range from $10,000 to $40,000 per violation. Management of requires the potentially responsible parties, over the course of the Rio Bravo Rocklin facility is currently discussing the several years, to identify contamination at the site and allegations in the NOVs with District representatives. It is not recommend clean-up options. BGE is fully indemnified by a possible to determine the actual liability, if any, of the wholly-owned affiliate of Constellation Energy for costs related partnership that owns the Rio Bravo Rocklin facility.

to this settlement, as well as any clean-up costs. The clean-up costs will not be known until the investigation is closer to Litigation completion. However, those costs could have a material effect In the normal course of business, we are involved in various on our financial results. legal proceedings. We discuss the significant matters below.

110

Western Power Markets Energy in these actions. To date, most asbestos claims against City of Tacoma v. AEP, et al,-The City of Tacoma, on us have been dismissed or resolved without any payment and a June 7, 2004, in the U.S. District Court, Western District of small minority have been resolved for amounts that were not Washington, filed a complaint against over 60 companies, material to our financial results. The remaining claims are including Constellation Energy Commodities Group, Inc. currently pending in state courts in Maryland and (CCG). The complaint alleges that the defendants engaged in Pennsylvania.

manipulation of electricity markets resulting in prices for power BGE and Constellation Energy do not know the specific in the western power markets that were substantially above facts necessary to estimate its potential liability for these claims.

what market prices would have been in the absence of the The specific facts we do not know include:

alleged unlawful contracts, combinations and conspiracy in + the identity of the facilities at which the plaintiffs violation of Section 1 of the Sherman Act. The complaint allegedly worked as contractors, further alleges that the total amount of damages is unknown,

• the names of the plaintiffs' employers, but is estimated to exceed $175 million. On February 11, + the dates on which and the places where the exposure 2005, the Court granted the defendants' motion to dismiss the allegedly occurred, and action based on the Court's lack of jurisdiction over the claims

• the facts and circumstances relating to the alleged in question. The plaintiff has appealed the dismissal of the exposure.

action to the Ninth Circuit Court of Appeals. We believe that Until the relevant facts are determined, we are unable to we have meritorious defenses to this action and intend to estimate what our, or BGE's, liability might be.

defend against it vigorously. However, we cannot predict the Although insurance and hold harmless agreements from timing, or outcome, of this case, or its possible effect on our contractors who employed the plaintiffs may cover a portion of financial results. any awards in the actions, the potential effect on our, or BGE's, financial results could be material.

Mercury Since September 2002, BGE, Constellation Energy, and several Storage of Spent NuclearFuel other defendants have been involved in numerous actions filed The Nuclear Waste Policy Act of 1982 (NWPA) required the in the Circuit Court for Baltimore City, Maryland alleging federal government through the Department of Energy (DOE),

mercury poisoning from several sources, including coal plants to develop a repository for, and disposal of, spent nuclear fuel formerly owned by BGE. The plants are now owned by a and high-level radioactive waste. The NWPA and our contracts subsidiary of Constellation Energy. In addition to BGE and with the DOE required the DOE to begin taking possession of Constellation Energy, approximately 11 other defendants, spent nuclear fuel generated by nuclear generating units no consisting of pharmaceutical companies, manufacturers of later than January 31, 1998. The DOE has stated that it will vaccines, and manufacturers of Thimerosal have been sued. not meet that obligation until 2017 at the earliest.

Approximately 70 cases, involving claims related to This delay has required that we undertake additional approximately 132 children, have been filed to date, with each actions related to on-site fuel storage at Calvert Cliffs and Nine claimant seeking $20 million in compensatory damages, plus Mile Point, including the installation of on-site dry fuel storage punitive damages, from us. capacity at Calvert Cliffs. In January 2004, we filed a I In rulings applicable to all but six of the cases, involving complaint against the federal government in the United States claims related to approximately 50 children, the Circuit Court Court of Federal Claims seeking to recover damages caused by for Baltimore City dismissed with prejudice all claims against the DOE's failure to meet its contractual obligation to begin BGE and Constellation Energy. Plaintiffs may attempt to disposing of spent nuclear fuel by January 31, 1998. The case is pursue appeals of the rulings in favor of BGE and Constellation currently stayed, pending litigation in other related cases.

Energy once the cases are finally concluded as to all defendants. In connection with our purchase of Ginna, all of We believe that we have meritorious defenses and intend to Rochester Gas & Electric Corporation's (RG&E) rights and defend the remaining actions vigorously. However, we cannot obligations related to recovery of damages for DOE's failure to predict the timing, or outcome, of these cases, or their possible meet its contractual obligations were assigned to us. However, effect on our, or BGE's, financial results. we have an obligation to reimburse RG&E for up to

$10 million in recovered damages for such claims.

Asbestos Since 1993, BGE and certain Constellation Energy subsidiaries Nuclear Insurance have been involved in several actions concerning asbestos. The We maintain nuclear insurance coverage for Calvert Cliffs, actions are based upon the theory of "premises liability," Nine Mile Point, and Ginna in four program areas: liability, alleging that BGE and Constellation Energy knew of and worker radiation, property, and accidental outage. These exposed individuals to an asbestos hazard. In addition to BGE policies contain certain industry standard exclusions, including, and Constellation Energy, numerous other parties are but not limited to, ordinary wear and tear, and war.

defendants in these cases. In November 2002, the President signed into law the Approximately 522 individuals who were never employees Terrorism Risk Insurance Act ("TRIA") of 2002, which was of BGE or Constellation Energy have pending claims each extended by the Terrorism Risk Insurance Extension Act of seeking several million dollars in compensatory and punitive 2005. Under the TRIA, property and casualty insurance damages. Cross-claims and third-party claims brought by other companies are required to offer insurance for losses resulting defendants may also be filed against BGE and Constellation 111

from Certified acts of terrorism. Certified acts of terrorism are The sellers of Nine Mile Point retain the liabilities for determined by the Secretary of the Treasury, in concurrence existing and potential claims that occurred prior to with the Secretary of State and Attorney General, and primarily November 7, 2001. In addition, the Long Island Power are based upon the occurrence of significant acts of Authority, which continues to own 18% of Unit 2 at Nine international terrorism. Our nuclear liability, nuclear property Mile Point, is obligated to assume its pro rata. share of any and accidental outage insurance programs, as discussed later in liabilities for retrospective premiums and other premium this section, provide coverage for Certified acts of terrorism. assessments. RC&E, the seller of Ginna, retains the liabilities If there were an accident or an extended outage at any for existing and potential claims that occurred prior to June 10, unit of Calvert Cliffs, Nine Mile Point or Ginna, it could have 2004. If claims under these policies exceed the coverage limits, a substantial adverse impact on our Financial results. the provisions of the Price-Anderson Act would apply.

Nuclear Liability Insurance Nuclear Property Insurance Pursuant to the Price-Anderson Act, we are required to insure Our policies provide $500 million in primary coverage at each against public liability claims resulting from nuclear incidents nuclear plant-Calvert Cliffs, Nine Mile Point, and Ginna. In to the full limit of public liability. This limit of liability consists addition, we maintain $1.77 billion of excess coverage at Ginna of the maximum available commercial insurance of and $2.25 billion in excess coverage under a blanket excess

$300 million and mandatory participation in an industry-wide program offered by the industry mutual insurer at both Calvert retrospective premium assessment program. The retrospective Cliffs and Nine Mile Point. Under the blanket excess policy, premium assessment is $100.6 million per reactor, increasing Calvert Cliffs and Nine Mile Point share $1.0 billion of the the total amount of insurance for public liability to total $2.25 billion of excess property coverage. Therefore, in approximately $10.8 billion. Under the retrospective the unlikely event of two full limit property damage losses at assessment program, we can be assessed up to $503 million per Calvert Cliffs and Nine Mile Point, we would recover incident at any commercial reactor in the country, payable at $4.5 billion instead of $5.5 billion. This coverage currently is no more than $75 million per incident per year. This purchased through the industry mutual insurance company. If assessment also applies in excess of our worker radiation claims accidents at plants insured by the mutual insurance company insurance and is subject to inflation and state premium taxes. cause a shortfall of funds, all policyholders could be assessed, Claims resulting from non-certified acts of terrorism are limited with our share being up to $92.6 million.

to the commercial insurance discussed above, regardless of the Losses resulting from non-certified acts of terrorism are number of nuclear plants affected. In addition, the U.S. covered as a common occurrence, meaning that if non-certified Congress could impose additional revenue-raising measures to terrorist acts occur against one or more commercial nuclear pay claims.. power plants insured by our nuclear property insurance company within a 12-month period, they would be treated as Worker Radiation Claims Insurance one event and the owners of the plants where the acts occurred We participate in the American Nuclear Insurers Master would share one fuall limit of liability (currently $3.24 billion).

Worker Program that provides coverage for worker tort claims filed for radiation injuries. Effective January 1, 1998, this Accidental Nuclear Outag Insurance program was modified to provide coverage to all workers whose Our policies provide indemnification on a weekly basis for nuclear-related employment began on or after the losses resulting from an accidental outage of a nuclear unit.

commencement date of reactor operations. Waiving the right Coverage begins after a 12-week deductible period and to make additional claims under the old policy was a condition continues at 100% of the weekly indemnity limit for 52 weeks for coverage under the new policy. We describe the old and and then 80% of the weekly indemnity limit for the next new policies below: 1 10 weeks. Our coverage is up to $490.0 million per unit at

• All nuclear worker claims reported on or after Calvert Cliffs and Ginna, $420.0 million for Unit 1 of Nine January 1, 1998 are covered by a new insurance policy. Mile Point, and $401.8 million for Unit 2 of Nine Mile Point.

The new policy provides a single industry aggregate This amount can be reduced by up to $98.0 million per unit at limit of $200 million for occurrences of radiation Calvert Cliffs and $84.0 million for Nine Mile Point if an injury claims against all those insured by this policy outage of more than one unit is caused by a single insured prior to January 1, 2003 and $300 million for physical damage loss.

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.

112

Non-NuclearProperty Insurance State and Attorney General, and primarily are based upon the Our conventional property insurance provides coverage of occurrence of significant acts of international terrorism. Our

$1.0 billion per occurrence for Certified acts of terrorism as conventional property insurance program also provides coverage defined under TRIA and Terrorism Risk Insurance Extension for non-certified acts of terrorism up to an annual aggregate limit Act of 2005. Certified acts of terrorism are determined by the of $1.0 billion. If a terrorist act occurs at any of our facilities, it Secretary of the Treasury, in concurrence with the Secretary of could have a significant adverse impact on our financial results.

13 Hedging Activities and Fair Value of Financial Instruments SFAS No. 133 Hedging Activities which is realized through gross settlement at the contract price.

We are exposed to market risk, including changes in interest rates We recognized into earnings $13.4 million pre-tax gain in 2006 and the impact of market fluctuations in the price and and $19.4 million pre-tax loss in 2005 related to cash-flow hedge transportation costs of electricity, natural gas, and other ineffectiveness.

commodities. In addition, during 2006, we de-designated contracts previously designated as cash-flow hedges for which the Commodity Prices forecasted transaction originally hedged is probable of not MerchantEnergy Business occurring, and as a result we recognized a pre-tax loss of Our merchant energy business uses a variety of derivative and $35.3 million. The majority of the pre-tax loss associated with non-derivative instruments to manage the commodity price risk de-designated contracts in 2006 resulted from the initial public of our competitive supply activities and our electric generation offering of CEP and the sale of our gas-fired plants. During facilities, including power sales, fuel and energy purchases, gas 2005, we terminated a contract previously designated as a cash-purchased for resale, emission credits, weather risk, and the flow hedge. The forecasted transaction originally hedged was market risk of outages. In order to manage these risks, we may probable of not occurring and as a result we recognized a pre-tax enter into fixed-price derivative or non-derivative contracts to loss of $6.1 million.

hedge the variability in future cash flows from forecasted sales of Our merchant energy business also enters into natural gas energy and purchases of fuel and energy. The objectives for storage contracts under which the gas in storage qualifies for fair entering into such hedges include: value hedge accounting treatment under SFAS No. 133. We

• fixing the price for a portion of anticipated future recognized a $27.7 million pre-tax net gain for 2006 and electricity sales at a level that provides an acceptable $2.2 million pre-tax net loss for 2005 due to hedge return on our electric generation operations, ineffectiveness. In addition, we recognized an $8.9 million pre-

• fixing the price of a portion of anticipated fuel purchases tax gain related to the change in value for the portion of our fair for the operation of our power plants, value hedges excluded from ineffectiveness testing. We record

• fixing the price for a portion of anticipated energy changes in fair value of these hedges related to our retail purchases to supply our load-serving customers, and competitive supply operations as a component of "Fuel and

+ fixing the price for a portion of anticipated sales of purchased energy expenses" in our Consolidated Statements of natural gas to customers. Income. We record changes in fair value of these hedges related The portion of forecasted transactions hedged may vary to our wholesale competitive supply operations as a component based upon management's assessment of market, weather, of"Nonregulated revenues" in our Consolidated Statements of operational, and other factors. Income.

At December 31, 2006, our merchant energy business had designated certain fixed-price forward contracts as cash-flow Regulated Gas Business hedges of forecasted sales of energy and forecasted purchases of BGE uses basis swaps in the winter months (November through fuel and energy for the years 2007 through 2015 under SFAS March) to hedge its price risk associated with natural gas No. 133. Our merchant energy business had net unrealized pre- purchases under its market-based rates incentive mechanism and tax losses on these cash-flow hedges recorded in "Accumulated under its off-system gas sales program. BGE also uses fixed-to-other comprehensive income" of $2,227.1 million at floating and floating-to-fixed swaps to hedge its price risk December 31, 2006 and $517.1 million at December 31, 2005. associated with its off-system gas sales. The fixed portion We expect to reclassify $1,522.1 million of net pre-tax represents a specific dollar amount that BGE will pay or receive, losses on cash-flow hedges from "Accumulated other and the floating portion represents a fluctuating amount based comprehensive income" into earnings during the next twelve on a published index that BGE will receive or pay. BGE's months based on the market prices at December 31, 2006. regulated gas business internal guidelines do not permit the use However, the actual amount reclassified into earnings could vary of swap agreements for any purpose other than to hedge price from the amounts recorded at December 31, 2006, due to future risk. The impact of these swaps on our, and BGE's, financial changes in market prices. Additionally, for cash-flow hedges results is immaterial.

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, 113

Reyeulated Electric Business During 2004, to optimize the mix of fixed and floating-rate BGE uses basis swaps to hedge its price risk associated with debt, we entered into interest rate swaps qualifying as fair value electricity purchases. BGE's regulated electric business internal hedges relating to $450 million of our fixed-rate debt maturing guidelines do not permit the use of swap agreements for any in 2012 and 2015, and converted this notional amount of debt purpose other than to hedge price risk. The impact of these to floating-rate. The fair value of these hedges was an unrealized swaps on our, and BGE's, financial results is immaterial. 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 Interest Rates management liabilities" and a decrease in our "Long-term debt."

We use interest rate swaps to manage our interest rate exposures We had no hedge ineffectiveness on these interest rate swaps.

associated with new debt issuances, to manage our exposure to fluctuations in interest rates on variable rate debt, and to Fair Value of Financial Instruments optimize the mix of fixed and floating-tate debt. The swaps used The fair value of a financial instrument represents the amount at to manage our exposure prior to the issuance of new debt and to which the instrument could be exchanged in a current manage the exposure to fluctuations in interest rates on variable transaction between willing parties, other than in a forced sale or rate debt are designated as cash-flow hedges under SFAS liquidation. Significant differences can occur between the fair No. 133, with the effective portion of gains and losses, net of value and carrying amount of financial instruments that are associated deferred income tax effects, recorded in "Accumulated recorded at historical amounts. We use the following methods other comprehensive income" in our Consolidated Statements of and assumptions for estimating fair value disclosures for financial Common Shareholders' Equity and Comprehensive Income and instruments:

Consolidated Statements of Capitalization, in anticipation of

• cash and cash equivalents, net accounts receivable, other planned financing transactions. We reclassify gains and losses on current assets, certain current liabilities, short-term the hedges from "Accumulated other comprehensive income" borrowings, current portion of long-term debt, and into "Interest expense" in our Consolidated Statements of certain deferred credits and other liabilities: because of Income during the periods in which the interest payments being their short-term nature, the amounts reported in our hedged occur. Consolidated Balance Sheets approximate fair value, The swaps used to optimize the mix of fixed and floating-

• investments and other assets: the fair value is based on rate debt are designated as fair value hedges under SEAS quoted market prices where available, and No. 133. We record any gains or losses on swaps that qualify, for

• long-term debt: the fair value is based on quoted market fair value hedge accounting treatment, as well as changes in the prices where available or by discounting remaining cash fair value of the debt being hedged, in "Interest expense," and we flows at current market rates.

record any changes in fair value of the swaps and the debt in We show the carrying amounts and fair values of financial "Risk management assets and liabilities" and "Long-term debt" instruments included in our Consolidated Balance Sheets in the in our Consolidated Balance Sheets. In addition, we record the following table.

difference between interest on hedged fixed-rate debt and floating-rate swaps in "Interest expense" in the periods that the Ar December 31, 2006 2005 swaps settle. Carrying Fair Carrying Fair Amount Value Amount Value-

"Accumulated other comprehensive income" includes net (In millions) unrealized pre-tax gains on interest rate cash-flow hedges Investments and terminated upon debt issuance totaling $12.5 million at other assets-December 31, 2006 and $15.4 million at December 31, 2005.

Constellation We expect to reclassify $0.6 million of pre-tax net gains on these Energy $1,468.8 $1,469.3 $1,362.1 $1,362.3 cash-flow hedges from "Accumulated other comprehensive Fixed-rate income" into "Interest expense" during the next twelve months.

long-term We had no hedge ineffectiveness on these swaps.

debt:

During 2006, in order to manage the exposure to Constellation fluctuations in interest rates on variable rate debt, CEP entered Energy 4,383.8 4,513.8 4,169.3 4,379.3 into a pay fixed-rate and receive floating-rate swap relating to BCE 1,716.7 1,712.6 1,364.6 1,376.4

$16.5 million of its outstanding debt. "Accumulated other Variable-rate comprehensive income" includes net unrealized pre-tax gains on long-term interest rate cash-flow hedges totaling $0.1 million at debt:

December 31, 2006. We had no hedge ineffectiveness on these Constellation swaps.

Energy 723.2 723.2 699.3 699.3 BGE - - 97.4 97.4 114

4 Stock-Based Compensation Under our long-term incentive plans, we granted stock options, During 2006, no stock options were granted to employees performance and service-based restricted stock, performance- in anticipation of the proposed merger with FPL Group, which based units, and equity to officers, key employees, and members was terminated in October 2006. We discuss the termination of of the Board of Directors. Under the plans, we can grant up to a the merger in more detail in Note 15.

total of 18,000,000 shares. At December 31, 2006, we had stock We use the historical data related to stock option exercises options, restricted stock, performance unit and equity grants in order to estimate the expected life of our stock options. We outstanding as discussed below. We may issue new shares, reuse also use historical data in order to estimate the volatility factor forfeited shares, or buy shares in the market in order to deliver (measured on a daily basis) for a period equal to the duration of shares to employees for our equity grants. BGE officers and key the expected life of option awards. We believe that the use of employees participate in our stock-based compensation plans. historical data to estimate these factors provides a reasonable The expense recognized by BGE in 2006, 2005, and 2004 was basis for our assumptions. The risk-free interest rate for the not material to BGE's financial results. 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 Non-Qualified Stock Options based on our current estimate for dividend payout at the time of Options are granted with an exercise price equal to the market grant. We disclose the pro-forma effect on net income and value of the common stock at the date of grant, become vested earnings per share for the periods prior to adoption of SFAS over a period up to three years (expense recognized in tranches),

No. 123R in Note 1.

and expire ten years from the date of grant. The fair value of our Summarized information for our stock option grants is as stock-based awards were estimated as of the date of grant using follows:

the Black-Scholes option pricing model based on the following weighted- average assumptions:

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 millionfully vested optionsgrantedin December2005, which would have been cancelledupon a change in controlif our proposedmerger with FPL Group would have been consummated andfor which an expected life ofoneyear was used to value the grant.Excluding this grant,we used a weighted-averageexpected 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 We recorded compensation expense related to our restricted about stock options during 2006, 2005 and 2004: stock awards of $24.5 million in 2006, $28.2 million in 2005, and $17.0 million in 2004. Summarized share information for 2006 2005 04 our restricted stock awards is as follows:

(In millions)

Stock Option Expense 2006 2005 2004 Recognized $ 6.7 $ 14.4 $ 1.0 (Shares in thousands)

Stock Options Exercised: Outstanding, beginning of year 1,272 1,223 752 Cash Received for Exercise Granted 511 485 1,002 Price 35.5 35.3 23.7 Released to participants (502) (359) (467)

Intrinsic Value Realized by Canceled (74) (77) (64)

Employee 27.6 109.8 10.5 Outstanding, end of year 1,207 1,272 1,223 Realized Tax Benefit 10.9 43.4 4.2 Weighted-average fair value of Fair Value of Shares that Vested 82.6 232.0 59.0 restricted stock granted (per share) $58.68 $51.23 $38.83 As of December 31, 2006, we had $2.8 million of unrecognized compensation cost related to the unvested portion Total fair value of shares for of outstanding stock option awards, of which $2.5 million is which restriction has lapsed expected to be recognized during 2007. (in millions) $ 27.6 $ 19.0 $ 18.8 The following table summarizes additional information about stock options outstanding at December 31, 2006 (stock As of December 31, 2006, we had $16.2 million of options in thousands): unrecognized compensation cost related to the unvested portion of outstanding restricted stock awards expected to be recognized Weighted- within a two-year period. At December 31, 2006, we have Outstanding Exercisable Average recorded in "Common shareholders' equity" approximately Range of Aggregate Aggregate Remaining $31.7 million and approximately $21 million at December 31, Exercise Stock Intrinsic Stock Intrinsic Contractual Prices Options Value Options Value Life 2005 for the unvested portion of service-based restricted stock (In millions) (In millions) (In years) granted from 2001 until 2006 to officers and other employees

$20.00 - $30.00 621 $ 24.8 621 $24.8 6.2 that is contingently redeemable in cash upon a change in control.

$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 Performance-Based Units

$50.00 - $60.00 3,718 50.4 2,536 30.0 6.7 In accordance with SFAS No. 123R, we recognize compensation 6,051 $129.4 4,401 $95.4 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 Restricted Stock Awards

$1 in value and cliffvests at the end of a three-year service and In addition to stock options, we issue common stock based on performance period. The level ofpayout is based on the meeting certain service goals. This stock vests to participants at achievement of certain performance goals at the end of the three-various times ranging from one to five years if the service goals year period and will be settled in cash. We recorded are met. In accordance with SFAS No. 123R, we account for our compensation expense of $24.0 million in 2006, $7.0 million in service-based awards as equity awards, whereby we recognize the 2005, and $2.9 million in 2004 for these awards. No awards value of the market price of the underlying stock on the date of were settled during the year, and as of December 31, 2006 we grant to compensation expense over the service period either had $9.9 million of unrecognized compensation cost related to ratably or in tranches (depending if the award has cliff or graded the unvested portion of outstanding performance-based unit vesting).

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.

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I5 Merger and Acquisitions Termination of Merger Agreement with FPL Group, Inc. operations for these working interests in our merchant energy On October 24, 2006, Constellation Energy and FPL Group business segment since the date of acquisition.

agreed to terminate the Agreement and Plan of Merger the parties had entered into on December 18, 2005. In connection Acquisition of Cogenex with the termination of the merger agreement, Constellation In April 2005, we acquired Cogenex Corporation from Alliant Energy acquired certain development rights from FPL Group Energy Corporation. We include Cogenex with our other relating to a wind power project in Western Maryland. nonregulated businesses and have included their results in our Pursuant to the terms of the termination agreement, if consolidated financial statements since the date of acquisition.

Constellation Energy announces its entry into certain types of Cogenex is a North American energy services firm providing transactions on or prior to September 30, 2007, including a consulting and technology solutions to industrial, institutional, merger or stock sale resulting in a third party owning 35% or and governmental customers. We acquired 100% ownership of more of the voting securities of Constellation Energy, it will be Cogenex for $34.9 million. We acquired cash of $14.4 million as required to pay FPL Group a fee. The fee is $425 million if a part of the purchase.

transaction is announced on or prior to June 30, 2007 and $210 Our final purchase price allocation for the net assets million if a transaction is announced between July 1,2007 and acquired is as follows:

September 30, 2007.

We incurred merger costs during the year ended At April 1, 2005 December 31, 2006 totaling $18.3 million pre-tax. Our total (In millions) pre-tax merger-related costs were $35.3 million. Cash $ 14.4 Other Current Assets 12.4 Acquisitions of Working Interests in Gas Producing Fields Total Current Assets 26.8 In the first quarter of 2006, we acquired working interests in gas Net Property, Plant and Equipment and oil producing properties for approximately $100 million in Other Assets 34.9 cash. We purchased leases, producing wells, and related Total Assets Acquired 61.7 equipment. We have included the results of operations in our Current Liabilities (8.0) merchant energy business segment since the date of acquisition. Deferred Credits and Other Liabilities (18.8)

In June 2005, we acquired working interests in gas Net Assets Acquired $ 34.9 producing fields in Texas and Alabama for approximately

$211 million in cash and the assumption of below-market We believe that the pro-forma impact of the Cogenex natural gas swaps and other liabilities totaling approximately acquisition would not have been material to our results of

$18 million. The Texas asset acquisition was for approximately a operations in 2005.

70% working interest and the Alabama asset acquisition was for a 100% working interest. We have included the results of I 6Related Party Transactions-BGE Income Statement In addition, Constellation Energy charges BGE for the BGE is obligated to provide market-based standard offer service to costs of certain corporate functions. Certain costs are directly all of its electric customers for varying periods. Bidding to supply assigned to BGE. We allocate other corporate function costs BGE's market-based standard offer service to electric customers based on a total percentage of expected use by BGE. We believe will occur from time to time through a competitive bidding this method of allocation is reasonable and approximates the cost process approved by the Maryland PSC. BGE would have incurred as an unaffiliated entity.

Our wholesale marketing, risk management, and trading The following table presents the costs Constellation Energy operation will supply a substantial portion of BGE's market- charged to BGE in each period.

based standard offer service obligation to residential electric customers through May 31, 2007, as well as a portion of BGE's Year ended December 31, 2006 2005 2004 market-based standard offer service obligations for all electric (In millions) customers from June 1, 2007 through May 31, 2009. Charges to BGE $148.8 $130.3 $99.8 The cost of BGE's purchased energy from nonregulated subsidiaries of Constellation Energy to meet its standard offer Balance Sheet service obligation was as follows: BGE participates in a cash pool under a Master Demand Note agreement with Constellation Energy. Under this arrangement, Year Ended December31, 2006 2005 2004 participating subsidiaries may invest in or borrow from the pool (In millions) at market interest rates. Constellation Energy administers the Electricity purchased for pool and invests excess cash in short-term investments or issues resale expenses $1,062.0 $805.9 $948.9 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 shareamounts) (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 ofthe quarterly earningsper share amounts may not equal the totalfor the year due to the effects ofrounding and dilution as a result ofissuing 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 reclassificationof our High Desertfacility to discontinuedoperations,we have reclassifiedcertain amounts previously reported in ourfirst, second, and third quarterForm 10-Qs. The following is a reconciliation ofamountspreviously reportedto amounts currentlypresentedfor those items.

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For the quarterended March 31, 2006 June 30, 200 06 September 30, 2006 Discontinued Discontinueed Discontinued

\s Reported Operations Reclassified As Re ported Operations Reclassified As Reported Operations Reclassified millions, except per sA'areamounts)

Revenues $4,897.5 $(38.3) $4,859.2 $4,421.9 $(43.1) $4,378.8 $5,433.7 $ (40.3) $5,393.4 Income from Operations 222.5 (18.5) 204.0 208.7 (30.4) 178.3 559.9 (29.0) 530.9 Income from Continuing Operations 113.0 (11.4) 101.6 93.1 (19.1) 74.0 324.4 (18.0) 306.4 Earnings Per Share from Continuing Operations-Diluted 0.63 (0.07) 0.56 0.52 (0.11) 0.41 1.79 (0.10) 1.69 2005 Quarterly Data-Constellation Energy 2005 Quarterly Data-BGE Earnings Per Share Income from from Continuing Continuing Operations Operations and Before and Before Cumulative Cumulative Earnings Effects of Earnings P1er Effects of Applicable Changes in Share of Earnings Income Changes in to Accounting Common Income Applicable from Accounting Common Principles- Stock- from to Common Revenues Operations Principles Stock Diluted Diluted Revenues Ooerations Stock i(In (In millions, except per share amounts) (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 quarterlyearnings per share amounts may not equal the totalfor the year due to the effects of rounding and dilution as a result ofissuing common shares during theyear.

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 reclassificationof our High Desertfacility to discontinued operations,we have reclassified certain amountspreviously reported in ourfirst, second, and third quarterForm 1O-Qs. The following is a reconciliationofamounts previously reported to amounts currently presentedfor those items.

119 million*

For the quarterended 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)

Revenues $ 3,572.0 $ (39.4) $ 3,532.6 $ 3,478.5 $ (40.5) $ 3,438.0 $4,922.4 $ (42.5) $ 4,879.9 Income from Operations 221.9 (28.1) 193.8 209.8 (26.8) 183.0 317.0 (29.6) 287.4 Income from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles 118.6 (17.8) 100.8 117.8 (16.7) 101.1 184.1 (18.6) 165.5 Earnings Per Share from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles-Diluted 0.67 (0.10) 0.57 0.66 (0.09) 0.57 1.02 (0.10) 0.92 120

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None.

Item 9A. Controls and Procedures Evaluationof Disclosure Controlsand 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.

InternalControlOver FinancialReporting 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. FinancialStatements 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.

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PART III The information required by this item with respect BGE meets the conditions set forth in General to executive officers of Constellation Energy Group, Instruction I(1)(a) and (b) of Form 10-K for a reduced pursuant to instruction 3 of paragraph (b) of Item 401 of disclosure format. Accordingly, all items in this section Regulation S-K, is set forth following Item 4 of Part I of related to BGE are not presented. this Form 10-K under Executive Officers ofthe Registrant.

Item 10. Directors and Executive Officers of the Item 11. Executive Compensation Registrant The information required by this item will be set forth The information required by this item with respect to under Executive and DirectorCompensation and Report of directors will be set forth under Election ofDirectors in the Compensation Committee in the Proxy Statement and Proxy Statement and incorporated herein by reference. incorporated herein by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters The additional information required by this item will be set forth under Stock Ownership in the Proxy Statement and incorporated herein by reference.

Equity Compensation Plan Information The following table reflects our equity compensation plan information as of December 31, 2006:

(a) (b) (c)

Number of securities Number of securities remaining to be issued upon Weighted-average available for future issuance exercise of exercise price of under equity compensation outstanding options, outstanding options, plans (excluding securities Plan Category warrants, and rights warrants, and rights reflected in item (a))

(In thousands) (In thousands)

Equity compensation plans approved by security holders 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

ManagementLong- 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 Transactionsand 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 ofPricewaterhouseCoopersLLP as Independent RegisteredPublic Accounting Firmfor 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 Column C Column D Column E Additions Balance Charged Charged to at to costs Other Balance at beginning and Accounts- (Deductions)- end of Description of period expenses Describe Describe period (In millions)

Reserves deducted in the Balance Sheet from the assets to which they apply:

Constellation Energy Accumulated Provision for Uncollectibles 2006 $ 47.4 $29.7 $ $(28.2)(A) $ 48.9 2005 43.1 30.9 (26.6)(A) 47.4 2004 51.7 22.2 (30.8)(A) 43.1 Valuation Allowance Net unrealized (gain) loss on available for sale securities 2006 0.6 - (19.1)(B) (18.5) 2005 0.1 -- 0.5(B) 0.6 2004 - 0.1(B) 0.1 Net unrealized (gain) loss on nuclear decommissioning trust funds 2006 (110.3) -- (95.8)(B) (206.1) 2005 (73.3) -- (37.0)(B) -- (110.3) 2004 (13.7) -- (59.6)(B) -- (73.3)

BGE Accumulated Provision for Uncollectibles 2006 13.0 18.1 (15.0)(A) 16.1 2005 13.0 14.1 (14.1)(A) 13.0 2004 10.7 16.3 (14.0)(A) 13.0 (A) Represents principally net amounts charged off as uncollectible.

(B) Represents amounts recorded in or reclassified from accumulated other comprehensive income.

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 ofthe Board, ChiefExecutive 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 Title Date Principal executive officer and director:

By Is! M. A. Shattuck III Chairman of the Board, Chief Executive February 27, 2007 M. A. Shattuck III Officer, President and Director Principal financial and accounting officer:

By /s/ E. F. Smith Executive Vice President, Chief February 27, 2007 E. F. Smith Financial Officer, and Chief Administrative Officer Directors:

/s/ Y. C. de Balmann Director February 27, 2007 Y. C. de Balmann

/s/ D. L. Becker Director February 27, 2007 D. L. Becker

/s/ J. T. Brady Director February 27, 2007 J. T. Brady

/s/ J. R. Curtiss Director February 27, 2007 J. R Curtiss

/s/ F. A. Hrabowski, III Director February 27, 2007 F. A. Hrabowski, III

/s/ N. Lampton Director February 27, 2007 N. Lampton

/s/ R. J. Lawless Director February 27, 2007 R. J. Lawless

/s/ M. D. Sullivan Director February 27, 2007 M. D. Sullivan 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.

Presidentand Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of Baltimore Gas and Electric Company, the Registrant, and in the capacities and on the dates indicated.

Signature Title Date Principal executive officer and director:

By /s/ K. W. DeFontes, Jr. President, Chief Executive February 27, 2007 K. W. DeFontes, Jr. Officer, and Director Principal financial and accounting officer and director:

By /s/ E. F. Smith Senior Vice President, Chief February 27, 2007 E. F. Smith Financial Officer, and Director Directors:

/s/ M. A. Shattuck III Director February 27, 2007 M. A. Shattuck III 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 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 1-1910.)

• 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