ML031770145
| ML031770145 | |
| Person / Time | |
|---|---|
| Site: | Nine Mile Point  |
| Issue date: | 06/17/2003 |
| From: | Wolniak D Constellation Energy Group |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| -nr, NMPIL 1736 | |
| Download: ML031770145 (162) | |
Text
P.O. Box 63 Lycoming, New York 13093 Costellaton Energy Group Nine Mile Point Nuear Station June 17, 2003 NMP1L 1736 U. S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555
Subject:
Nine Mile Point Unit Nos. 1 and 2 Docket Nos. 50-220 and 50410 Facility Operating License Nos. DPR-63 and NPF-69 2002 Annual Financial Reports of Constellation Energy Group and Long Island Power Authority Gentlemen:
Pursuant to Section 50.71(b) of the regulations of the Nuclear Regulatory Commission (IOCFR§50.71(b)), enclosed are copies of the 2002 Annual Financial Reports of Constellation Energy Group and the Long Island Power Authority.
Very truly yours, Denise J. Wo General Supervisor Licensing DJW/IAAMJm Enclosures cc: Mr. H. J. Miller, NRC Regional Administrator, Region I (without Enclosures)
Mr. G. K. Hunegs, NRC Senior Resident Inspector (without Enclosures)
Mr. P. S. Tam, Senior Project Manager, NRR (2 copies, without Enclosures)
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THERE'S NEW ENERGY IN WHAT WE DO Constellation Energy Group, a Fortune 500 company based in Baltimore, is the nation's leading competitive supplier of electricity to large commercial and industrial customers. We market energy nationally and manage the associated risks. We own and operate a diversified fleet of generation plants throughout the United States. We also deliver electricity and natural gas through the Baltimore Gas and Electric Company (BGE), our regulated utility in Central Maryland. In 2002, the combined revenues of our integrated energy company totaled $4.7 billion.
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IN OUR CONSTELLATION, WE HAVE NEW ENERGY AND IT'S EXCITING We spent 2002 getting our business in shape. No doubt the environment was worse than we expected, the weather better than expected, and the accounting profession entered the fray to make everything more complicated than expected. Nonetheless, we were steadfast in our determination to deliver, and more importantly, to expand on a strategy in which we have a great deal of confidence.
We lived by the idea that we had to earn our right to grow. announced an additional dividend increase of 8 percent, making That meant some tough decisions and hard work. It also meant it an annual rate of $1.04 per share, up from $0.96 per share.
changing or stopping some of the things we were doing and When I look back on the challenges we and the rest of the focusing on what we do best. industry faced in 2002, I'm very proud that we produced such The results of our efforts are gratifying: a strong balance strong financial results and increased the dividend. To see the sheet, a solid utility business, a fast-growing competitive supply real strength of our performance, you have to look at what business, and an enhanced focus on our customers. In addition, happened beyond the company.
we continued our leadership in full disclosure and delivered As we all know, 2002 was a very difficult year, especially strong financial results. for the energy sector. The Dow Jones Utility Index was down 27 percent. Valuations were affected by the weak energy Solid Earnings Growth business environment, the fact that many companies had Against a backdrop of lowered earnings expectations in our earnings decreases year over year, the credibility issues industry, we reported solid earnings growth. Our reported associated with trading and accounting scandals, and a true earnings per share were $3.20 in 2002, compared with credit and liquidity crisis for many of our peers.
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$0.57 in 2001. Our 2002 reported earnings include some Sharpening Our Focus benefit from special items-primarily non-core asset sales. We were one of the first companies to recognize these shifting Our 2001 reported earnings included special items as well- market dynamics, and we acted quickly.
primarily losses due to contract termination and workforce We increased our focus on generating and selling energy reduction costs. As detailed on the financial highlights page, and we sold $708 million of non-core assets-businesses and our earnings for 2002-excluding special items-were operations not directly involved in our core business. We
$2.52 per share versus $2.41 per share in 2001. continued to invest in our risk management processes and Our 2002 earnings reflect a negative impact of $0.32 for a strengthen our control procedures. I believe this has put us in shift from mark-to-market to accrual accounting for certain the forefront of the industry. It also has allowed us to avoid many parts of our competitive supply business, which was precipi- of the issues that befell our competition.
tated by changes in the way we do business. This approach More importantly, we knew that a strong and stable balance was validated by the Emerging Issues Task Force of the sheet would mean the difference between success and failure.
Financial Accounting Standards Board issuance of EITF 02-3 By selling non-core assets and extending the maturity of late last year. $2.5 billion of debt, we have constructed one of the best balance Despite the implementation of this conservative policy, we sheets in the industry and positioned our company to grow.
were still able to grow our earnings-excluding special items- We constructively renegotiated our contract with the 4.6 percent relative to 2001 earnings per share. California Department of Water Resources, which allowed us to resolve a significant uncertainty and provide greater visibility into Performing Well in a Challenging Environment our earnings. We also made great progress in integrating our For the year, our stock closed up 4.8 percent over the 2001 new acquisitions-Nine Mile Point and NewEnergy-into the closing price. Assuming reinvestment of dividends, our total Constellation family.
return to shareholders in 2002 was 8.5 percent. We also And finally, we sharpened our focus on the right business doubled our dividend in 2002. And in January 2003, we model. Namely, we worked aggressively to develop further a 2
competitive supply business that balances our generation We also have a platform that we believe can grow faster than and regulated distribution businesses and enhances our the industry averages. The employees at Constellation worked growth potential. very hard last year to create this platform in the face of much adversity in the industry. Their commitment, dedication, and Where We're Headed focus are the main reasons for our success.
Through our competitive supply platform, we serve as the energy cost manager for utilities and large commercial and Our Thanks industrial customers throughout the country. We moved to I want also to pay tribute to two retiring Directors who have expand that business platform with the acquisitions of made significant contributions to this company for many years.
NewEnergy from AES, and Fellon-McCord and Alliance Energy First, Chris Poindexter, my predecessor as Chairman and CEO, Services from Allegheny Energy. has retired from the Board of Directors. His 35 years of service We have a significant share of a large but fragmented to this company span from the early years of building the market. In fact, by our estimates, we are the largest provider of Calvert Cliffs Nuclear Power Plant to his courageous power and energy cost management to wholesale, commercial stewardship of the company through the deregulation process.
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I I* I and industrial customers in deregulated energy markets. And His loyalty and impact on Constellation will be a permanent we're seeing great opportunities to continue to grow our share. legacy. Bev Byron, retiring in April, has been on the Board of We believe we have a strong competitive advantage in our Directors for 10 years. Her insight and commitment to our customer relationships, our physical assets, our intellectual company have made a real difference.
capital, and our five years' experience in modeling, evaluating, assuming, and managing the unique risks associated with energy supply and cost management. Sincerely, Why We'll be Successful In simple terms, we generate and we sell energy. Most importantly, we meet our customers' energy needs.
One of the key elements of our future success will be this customer focus. Managing the risk and complexity of energy use and cost is a unique skill that is highly valued by our large customer base.
We also will be successful by continuing to focus on opera-tional productivity. Process improvement has become part of our Mayo A. Shattuck IlIl culture, and we have reaped large savings from a number of Chairman of the Board, President and Chief Executive Officer initiatives throughout the company. With our launch of Six Sigma March 7, 2003 in 2002, we have institutionalized the notion that we must keep getting better and more efficient at everything that we do.
Finally, we will be successful because we have a business model that allows for strong, stable, and predictable cash flow.
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THERE'S NEW ENERGY IN'OURjB 4 We bildig hvete bockswe eed o bcomne the first-choice prdce,and the more tan 50 million megawatt hours that
~ Wehavethe building blocks we'need to becm hh 0 sfi provider for customers ethe cmpa seeking energy it' a wit'sithse solutions. 'r cutywantn w.e'll b fnote eeArnd the mrkt.e Whether its a company withsites across the country nfing We meet energy needs. value. Th to deal with one energy company '... or a utility that doesn't own '.generating, buying, and supplying energy, managing'its use and!
power plants ... or a manufacturer who depends upon a reliable -'cost, and developingefficiencies for our wholesale and industrial energy supply ..-.or a Maryland homeowner who wants heat 'and commercial custo'mers.
'-when it's cold, air bonditioning when it's hot, and power when For us competitive energy supply is a physical delivery the switch is flipped -we have capabiities to meet their business We take a physical product that we produce or buy' energy'needs. '-' enhance it with value-added service i and deliver it or provid for its delivey to customers hese custome gu
- Meeting customer needs and adding value lated utilities with no generation assets electric co-operatives Competitive energy supply isthe growth engine of our company. . municipalities power arketers and large commercial and In 2003, we plan to sell more than 100 million megawatt hours -industrial customers with sites and companies throughout'-
the 50 million megawatt hours our energy generation' business the nited States and parts of Canada
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Diversified generation. Steve Gross is Reliable delivery. BGE, our regulated, plant manager of our new High Desert energy delivery business, is the strong and power plant, an 830-megawatt, natural dependable foundation of our company.
gas, combined-cycle plant that will We deliver energy safely and reliably to come on line this summer. It's one of 1.2 million electric and 600,000 natural gas California's first major generating plants customers inCentral Maryland. And we do it in more than 10 years. It's also a great No. 1 in competitive energy supply for large efficiently while keeping customers happy.
strategic addition to our fleet, which is customers. We believe our share of this market BGE ranks among the best-the top diversified geographically and by fuel is the largest of any company serving large 25 percent of regulated utilities-in terms source. With High Desert, our total commercial and industrial customers. We're of operating and maintenance costs. In owned generating capacity nationwide estimating that the market will grow from its current addition, the company was named a will be more than 12,000 megawatts. 170,000 megawatts to 190,000 megawatts by 2005. J.D. Power customer satisfaction leader Our goal is to increase our leading market share by among eastern utilities.
being among the best at meeting customers' growing needs for energy and energy services.
Generating best in class It is also a productivity leader. In 2002, BGE-along with our Our beginnings in power generation trace back to one of the generation business-achieved process improvements that first electric companies in the United States. With more than helped the company save $68 million. In 2003, it will be taking 100 years of experience, we know how to generate electricity. its Achieving Operational Excellence program to the next level Through the many changes in our industry and business, a through Six Sigma, a disciplined approach to continuous constant for us has been to continuously grow and improve. improvement. BGE and other parts of our company will be using All of our power plants now sell energy into the competitive Six Sigma to focus on reducing costs, improving quality and marketplace. In 2003, we expect to generate 50 million megawatt reliability, lowering administrative and operational cycle times, hours, the most we've ever generated in one year. And we're and improving overall customer satisfaction.
aiming to be best in class. By 2004, we expect most of our facilities to be among the best 25 percent of generators in Putting us in a good position terms of production costs. We are well positioned. Through the strategic sale of non-core assets and decisive action in the capital markets, we now have Delivering bottom-line productivity one of the strongest balance sheets in our industry. In 2002, With more than 185 years of energy industry experience, we reduced our net debt by $500 million and our debt-to-capital Baltimore Gas and Electric (BGE) has a solid franchise in ratio to 52 percent. We plan on reducing net debt by another an economically healthy area. $400 million in 2003.
It has a good customer mix-50 percent residential, Our people are the real source of our new energy. They have 40 percent commercial, and 10 percent industrial-and a the expertise and ability to execute our strategy, and the drive to steady growth rate with the annual addition of more than make us the first-choice provider for customers seeking energy 20,000 electric and natural gas customers. solutions.
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':THERE'S. ENERGY I)y IN OUR-~~
We hav h rec we need to becom thefrthoc rvdr We candel ive-r energy and value a dd:e dservices to for customers seeKing energy.solutions. ' ' -:- ` Customers throughout North America.'Our national fleet of reach acces ivestode~gulate u markes and o ',Aeneratin~gplant and our compeitive energy supply operations cutomers who can choose their e'nergy suppliers' t also givs aestrategically located inand near deregulated marKets across,
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Our reach extends to the bottom line. As the preferred supplier of electricity to the Illinois Manufacturers' Association (IMA),
we have helped more than 500 of its member companies save approximately
$25 million inenergy costs since 1999.
Jim Belden (left), a sales and marketing director with our competitive energy supply business, and Kurt Wiebe, vice Our reach extends into all areas of a president of the IMA, are part of the team customer's operations. At Boston University, that has helped make that happen. The we serve more than 700 accounts by supplying key has been delivering on our promise- Our reach also extends to the skies.
electrical energy to dormitories, classrooms, supplying cost-efficient energy with When Lockheed Martin needed a reliable laboratories, athletic facilities, outdoor lighting, excellent customer service. supply of low-cost energy and a way and many other areas of its campus along the to track its energy use, we provided banks of the historic Charles River. the solution.
Throughout the United States Gaining high-value customer relationships Our reach helps make us the argest supplier of competitive We improved our reach during 2002 with the acquisitions of power to utility, municipal, and commercial and industrial NewEnergy from AES, and Fellon-McCord and Alliance Energy customers throughout the United States. Services from Allegheny Energy. Those companies came with We provide energy and services directly to large commercial key expertise and resources, and some high-value customer and industrial customers. We also provide energy and services relationships. They also came with offices strategically located in to wholesale customers who then distribute the energy to their states where customers have the most flexibility in choosing own customers. energy suppliers. Those states include California, Illinois, In the Northeast, our energy reaches into New York, New Kentucky, Maryland, Massachusetts, New York, Ohio, Oklahoma, Jersey, Massachusetts, Rhode Island, New Hampshire, and Pennsylvania, and Texas.
Maine. That reach allows us to be one of the largest suppliers to companies like National Grid. All along the energy value chain Our reach also allows us to serve The Rouse Company, Our reach also extends across the energy value chain. Between which has more than 50 upscale retail properties totaling the creation and consumption of energy, there is a long chain of 45 million square feet in major markets throughout the United valuable transactions. Its many activities and processes include:
States. It is one of the nation's premier real estate development .t purchasing the fuel to produce energy, generating energy, and management companies. With the energy services we and delivering energy to customers who use it.
provide, The Rouse Company can view and monitor energy selling and delivering energy to wholesale customers who costs, usage, efficiency, and other energy statistics for all then sell it to their own retail customers who use it.
its properties.
In Maryland, our reach extends to 1.2 million electric and . serving as an energy procurement and management 600,000 natural gas customers of Baltimore Gas and Electric. function for large commercial and industrial customers.
Our regulated business ensures that the energy the region .4 selling energy to other energy marketers who use it to meet needs is delivered safely and reliably. their customers' needs.
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TH ERE'S NEW ENERGY INOUR APOC We have the approach we need to become the first-choice The approach we tak enerating and selling energy starts prvdrfr c-ustom"ers seeking energy solutions., . ih a balanced str'ategy. Oprtn nboth reguaeqn Our approac isbasically how We'run'our business. We, deregulated business environments provides us stable earnings generate and sell ener y, we ocus on customers, and we ,w. od growth opportunities.
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Getting our energy to where it's needed, when it's needed. PJM isthe largest compet-itive wholesale electricity market inthe world.
It is responsible for the transmission of bulk energy through seven eastern states and the District of Columbia. Recognized as the premier regional transmission organization inthe United States, PJM has about 200 members-and we've been a part of it since its inception. Providing energy ... and more. National Grid owns five distribution utilities serving 3.2 million With more than 6,000 megawatts of generating electric customers in New York, Massachusetts, Rhode Island, and New Hampshire, and capacity inthe region, we've gained skills and 540,000 natural gas customers in New York. In conjunction with deregulation, the company expertise intransmitting large amounts of sold its generation. So now it must buy most of the energy it delivers. In addition to being one energy through PJM. Now we're using our of National Grid's largest suppliers-providing 3,000 megawatts of power-we also handle skills and expertise in other areas of the many of the operational, administrative, and risk management aspects of serving the country where we serve large customers. company's load requirements and administering its power purchase agreements.
Even greater balance Managing risk conservatively We sell a mix of energy that we generate and that we purchase. Risk management is in our DNA. Our combination of skills That balance of owned and contracted generation gives us differentiates us from the rest of our industry.
greater flexibility and helps diversify risk. From our unique relationship with Goldman Sachs from Increasing our participation along the energy value chain 1997 to 2001, we've gained skills and expertise in risk gives our strategy even greater balance. We are disciplined and management, economic forecasting, and modeling. From focused on opportunities that offer growth potential or stable and our more than 185 years in the utility business, we've gained predictable earnings. skills and expertise in customer service, demand forecasting and management, and energy generation, transmission, Customers are at the heart of our business and delivery.
Our core skills are generating, purchasing, delivering, and Added to that is our intellectual capital-built with five years selling energy. But our core mission is meeting customers' of experience evaluating, assuming, and managing the unique energy needs. Our customers have complex needs that aren't risks associated with energy cost management and load-easily met by the standard, one-size-fits-all, large blocks of shaping. We believe that experience is what differentiates power that are typically traded in the wholesale energy markets. us from everyone else.
We analyze energy usage patterns and suggest alternative We evaluate and manage the risk our customers want to production and operational possibilities to lower energy costs. minimize. And we take a distinctly conservative approach. We We also plan, generate, buy, and manage energy-often sell energy-either producing it ourselves or buying it from acting as an extension of our customers' administrative and others-and we physically deliver it along with value-added procurement functions. services to our customers.
In short, we sell energy and value-added, cost-management Providing these services also earns a premium. It's an services. This requires a special expertise. And our customers important part of our approach that enables us to grow earnings, often don't want to invest what's needed to build and maintain even at a time when other energy providers are struggling.
that capability in-house.
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THERE'S NEWENERGY -IN`UR-comui es is an ur mi-ssio--n. ..o^c;a- and 4 - -- 0>
Being,thoughtful and caring stewards of our environment and Since 1991, we've prevented the release of or th n.-
communities important isan part of our mission. Social and -': -B~~~~~~~~~~~~~~~~~.expning'oughffl 40 million tns tons off carbon dioxide arbn ant emissions perrseadofour ioxdeemisins capct,runing year by eafossirontad-u terlaeo rvned iSnel19,w' oeta 0
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environmental responsibility is one of our foundational values. £7 expanding our nuciear plant capacity, running our fossi-fueled--
We benefit from doing business in the communities where our. plants more efficiently, and using less fuel. As a partner in the employees and customers live. In turn, the communities should U.S. Environmental Protection Agency's Energy STAR Buildings :
benefit from our presence. Being a good corporate citizen is the Program, we've also conserved enough energy to prevent the right thing to do. Italso miakes good business sense.:- release of alos 10,0os of carbon dxi. Ou olist continue reducing emissions of carbon dioxide per megawatt of.
Our environmental stewardship -eectricity produced. . .- .
-'All of our efforts center on our commitment to helping meet the The diverse fuel mix we use to generate electricity also -
nation's energy needs, while also decreasing the environmental supports our environmental stewardship: More than half of the Y impact of energy production. The U.S. Department of Energy's: power we generate in 2003 will come from emission-free nuclear Climate Challenge Program is the world's largest and most power, with the rest from coal, oil, gas, and ren ewable sources.
,successful initiative on global climate change. It features We're also ahead of the industry by installing selective catalytic voluntary individual utility programs and industry-wide initiatives reduction technology at our two largest coal-fired power plants, to reduce, avoid, or sequester greenhouse gases. And we're an allowing us to remove 90 percent of ozone-contributing gases.
active participant.
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Kennedy Krieger Institute. The Living Classrooms Foundation. Offering internationally recognized Kennedy hands-on education and job training Krieger Institute is dedicated to The Chesapeake Bay Foundation. As the programs, Living Classrooms motivates helping children from around the foremost conservation organization diverse, at-risk students to succeed world cope with disorders of the dedicated solely to saving the Chesapeake academically, in the workplace, and intheir brain and achieve their full potential Bay, the foundation's motto, Save the Bay, lives. With an emphasis on math, science, by participating as fully as possible in defines its mission throughout the 64,000- language arts, history, economics, and family, school, and community life. A square-mile watershed. Its nationally ecology, the programs provide opportu-pioneer in special education, research, recognized environmental education nities for students to apply the lessons and training, Kennedy Krieger's teams program works to prevent pollution, and techniques to maritime settings, of specialists use a family-centered restore habitat, and increase fisheries. community revitalization projects, and approach to ensure quality care. other challenging environments.
The real winners of the Constellation Energy Classic.
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P&;-r, T Renewable energy school. We also support programs that provide opportunities for We have ownership interests in 19 renewable energy projects students to develop into resourceful leaders, informed voters, throughout the country. These plants use solar, geothermal, and knowledgeable consumers-all with understanding and biomass, hydro, and waste coal energy sources to produce respect for one another.
power. Also, the U.S. Department of Energy's National Energy In addition, we encourage our employees to join with us in Technology Laboratory selected us as one of five companies to financially supporting institutions of higher learning through manage a national Biomass & Alternate Methane Fuels Energy our Matching Gifts Program.
Savings Performance Contract for federal facilities. Our economic development support focuses on community Our efforts have received numerous awards, including U.S. revitalization and efforts to promote job creation and retention.
Environmental Protection Agency WasteWise Partner of the We also support various arts and cultural programs.
Year, U.S. Department of Energy Clean City Award, and Clean Air Partners Award for Ozone Action Days Program. Constellation Energy Classic We're using our new sponsorship of the Constellation Energy Our community commitment Classic-a professional golf tournament-to add to our We have a commitment to community partnerships. In 2002, support of our communities and the environment. More than we contributed $4 million to educational, environmental, and 80 golfers from the Champions Tour-formerly known as the economic development programs. Senior PGA TOUR -will participate in this September event.
Education is the foundation of personal and economic All proceeds will be donated to three charities.
growth. When individuals are gainfully employed and live The Kennedy Krieger Institute and Living Classrooms productive lives, there are many benefits-to the individuals, Foundation both will receive funds to help in their work providing their communities, businesses within those communities, the children with needed care and preparing students to become quality of life, and the overall economy. productive members of our communities. The Chesapeake Bay So our support of education goes primarily to two basic Foundation will receive funds to support its efforts to preserve types of programs. We support programs that provide students and enhance the health and vitality of Chesapeake Bay.
with the skills they need to enter the workforce when they finish I1
THLERE'SNEW ENERGY.
INOU R A ConversationWithMayo A.Shattucdkll-*
What do you see as our major accomplishments n 2002 We're focusingon te cmeiieeeg upybsns and ouri major Challenges for2003? -while ohrcmaisaelvigttmrkpac.What Our promise ast year~ was that we Would focus on crisp makes our strategy the right one?,
-execution and earn the~ right to grow. Iam very proud to report Tere'sn&oquestion that some companies inthe competitive, that we delivered on those promises. We met or exceeded our, energy marketplace have made major.errors. Some have left F guidlance to Wall Street for the last five quarters, something very, and others are now scrambling for their very existence. Overall,
-few of the energy companies we monitor managed to'do. .I-the competitive andsaehas changed dramatically.
eraps mrimotn,we put ourselves in the toito hat has no oeaa-nd what will not go away-is the
-- being able to c'ontrol our own destiny as our industry continues to, customer need for energy and energy services. We estimate evolve. Recognizinthatrn banc shet wuld mean the -that the market in which customers can choose their energy--
difference6 between success and failure,: we acted aggressivelyt suppliiers iscurrently1170,000 megawatts, and we believe-it wiill improve our balance sheet bysiig$0 Ilo nnncr grow to190,000 megawatts by 2005.Right now,we're the, assets and issuin'g $2.5 billion-'of lohg-term debt.lThese actions K ation's argesit competitive suppiier of energy-and energy-have given us one of the best balance sheets in the industry: related services to utility, municipal, commerci, and industrial
~Anfiall, w shrpeedour-focus on the right businesS Customers Our goal istinraeour market share.:'
mdel, namely, rigas eegcost manager or Utilities The energy. cost management serv'ices we provide require a
-and arge commercial and industrial custoes emoved to level of priethat our customers do not sesand don't
--.expand that business latform with,theacustin of want to bu ild in-house. We differentiate ourselves b ine finaly,
- shaped bjxp:une erse Newnery,and Fellon-McCord and Alliance Energy Services.._ standing our customers' needs, structuring contracts that meet Te balance in earnings growth potential provided by a large those needs, pricing them appropriatey, and becoming an scalable competitive spply buiespromises to deliver more itgadofurcens' operations. Said simply-stble and rictable earnings and cash flow. -- we manage our partners'energy needs.)
In200 we mst contiue to earn t rgtogowDigIsafgmnemrkt, and we see a real opportunity t tawill require executing on our pian+~-growing our competitive .grow this business both organicaly and through niche acqus supply buisiness, achieving productivity gains, maintaining a 'tions as others leave the business 7i disciplined approach toeplomn fcptl n ute_~,,
enhancing ououtoe c fuaialadfute.
Constellation Energ does no faetepolm ayWhat makes us best in class itemofinncialdisclosure?.
other energy companies do: Why is'that?: One of my first priorities last year was tfoster a new culture of Some companies are suffering froml-ifctdpolm.W : pens inwhich we provide bes-ncasdslsr n haveavoied tose itfalls. We hay a balanced strategy that betrisight into how we make money.'-.
combines the strong, predictable earnings'of our.regulated Wev aeasbtnI investmeint inpeople,' as well as in~
business with the growth of' our competitive supply business.~j systems to help us track and understand our,biusines n the 7 direction in which.it's headed. As aresult, we area abeto give' Wye generate and sell energy along with value-added services to customers. Ours is a phscldlvr buiesyucn . curate guidanc on 6 and present detailed financialmoesf clearly see what we're doing:.' hww ake mnygingnvstors and analysts the infor-Ontop of that, our. performance has been key. WYe recog-. mation they need taprrIately value our cmay nized terality of the competitive nergy marketple ary on, --
and we took decisive action. The results give us some -signif- What mrakes us risk management experts?
icant advantages--a strong balance sheet and cash flow, solid Wehave intellectual capital and expertise inthis area that few st t-radcredit raings, an integrated maniagement q cncam edvlpdorsil ieooi oeatn n Linvestmentegre ra k
- - anagmentexpetis4-allof wichposition us iskeam,and modeling and establsea orld-class riskmangmn tegm~adritbstk full ianagmn t -a our smarthii-exetseisneg emad forecasting a aaement, to achieve long-term earnings growth. Add to that our focus on operation during our association with Goldman Sachs. Our j fiined~ approach to the use capital, and. you can see wh, 'h we -- >of and generation, transmission,and distribution, comes from:-
s'ucc'eeded where othersi may hiave faltered.. - moethafi 185 years in thie utility business. '
. - the ast five years evaluating, modeling, W~~~~~~~~~evespent
!InJanuary, we increased our dividend by 8 percent. What assum-ing, and managing the unique challenges associated, with is our dividenpoi?thcopeenryedsfou cutmes We have continued ustoiprv ndourblace henetirotpotnte Ris maa eents lof aufudmtal copoetrfsh When I look back on the challenges we faced in 2002,- I'm very to inve-st both in personnel and systems to rigorously test and 1 that allowed-": optimize theway we quantify and manage risk.,-_~
proud that we produced the strong financial results at attractive'returns, and raise our dividend. Very few companies management of this company. We have achief risk officer who inour sector can make the same claim. : -reports directly toie enior managers experienced in i---:ur goal is to provide a competitive total return to our share managing risk, and a very programmed process structured wit holders through a combination of stock-pride appreciation and strong interna an externa contos Ible al of this pusus W belive strng eaningsgrot ,wl rv tck divideds. athfoernofheidustry.- -
price appreciation, and we plan to supplement that return with -*-- -
sustainable dividend , -. Hw ilyospn most of your time in 2003?
- -. (focus will be on executing our strategy. We're a national,,
~~~My w ay You hae th rigt popl ithrgtpositions Wht omaynwith operations'all over the country:AAd there.
core coMetencies do we need on our management team? :are a lot of opportunities to kedvntg ofgoderis If you look at the members of our leadership team, you'll see drivers We have experienced persionnel focused on operational their ba'ckgeounds are both impre sve and diverse. Every -e xcellence. if we execute our strategy, we'll be able to deliver person ison the team because they are strong leaders top-tier some very significant earnings growth.
performer in their fields, and they bring to the table the right -
mix of skills and experience we need to be successful in this business. More importantly, they're here because they are'sbolid templayers Whose particular talents complement the others 13
Board of Directors MAayo A: Shattuck lii Dou)as .Bc James T.Brady -Frank P.Bramble, r Beverly B.Byron' EdwardA.rok Chairman. President Chairmnan and Chief Managing Director, Vice Chairman, For'Mer .Retired Vice Chairman, and Chief Executive.- Executive officer~Sylvan Mid-Atlantic of - MBNA Corporation Cogesoa, Constellation Officeir Constellation Learning Systems, Inc.- Ballantrae. Age 54 u. osfEnerg Grup Energy Group Age 37 International, Ltd. Dire ctor since 2002 Representatives Age 64 Age 48 Director since 9,98** Age 62 Age 70 Director since 988~
Drcosice 194Direct or since 1998' Director since 1993~
(Retiring April 2003)
,committees of the Board' Executive Committee, Committee on Management: Nominating and Corporate -.
Mayo A. Shattuck 1ll, Chairperson Michael D.Sullivan, Chairp~erson - Governance Committee; Frank R Bramble, Sr., Douglas L. Becker -McalD ulvn hipro Edward A. Crooke.& Frank Br'amble, Sr. DulsLBce Edward J. Kelly I . dd J. Kelly IFak rml, r Robert J. Lawless Robert J. LawlessEdadJKel l¶ Committee on Nuclear Po'wer
- - ~~~~~Robert J. Lawless Audit Committee 'Jamres R. Crtiss, Chairperson James T.Brady, Chairperson Beverly B. Byron.
Freeman A. Hrabowki I EwarA.Cok-Nancy Lampton Roger W.Gale 14
James R.;- Roger W.GaleD rea . - Ewr el l Nancy Lamplon Robert J. Lawless MichaelD.Slia Partner GFEnergy LLC Hrabowski IllCaraIPeiet Chimna ChairmaCharmn,President Chairman, Life
_Curtiss; Esq. -
Partner iso Age 56 President, University ::and Chief Executive Executive Officer and Chief Executive- Source, Inc. -
StraWn Director'since 1995' of Maryland - Officer Mercantile - 'American Life and Officer McCormick & Age 63:
~L Balimore County Bankshares Corporation -Accident Insurance company Inc.; Director since 1992 Age 49 Director since 1994* Ag 52 Age 49 Compan of Kentucky Age 56 Director since 1994* Dire ctor since 2002 Age 60 -. -Director since 2002 Dirtector since 1994*
-
- a Director of a company subiii a lce ote Constellation Energy Group Board of Directors in May 1999 F~~iorme6rly
- Formerly a BGE Director was electedf to the ConstellationEegGruBodofDecrsi April 1999 at the formation of the holdingcopn4 15
Executive Team Constellation Energy's executive team is diverse in experience, background, and point of view. Those who are steeped in the knowledge and experience of Constellation work side-by-side with those who have been recruited for their expertise gained around the world. Together they combine the right mix of energy industry tradition and competitive business savvy necessary for today's changing energy landscape.
MaoA. Shatc Il Thomas V. Brooks' ". Frank .' Heinz:,'- 'Michael J. Wallace Chaira ofth oad President, Constellatiob iPresidentand Chief msd n&stelation o
`Presiden and Chief' Power Source Executve Officer BGE Generation Group "7=-.
-' ---, - ~~~~~~~~~~~~~Executive Officer 48 dC onnstellation ' 40,ji e o selto 59, joined BGE* in1996 55, joine Co s lat n
-- Energy as President and ,.Energy in2001 as ice asVcPridnEegyn202Port CEO, and was elected President, Business assuming eadership of thsh aco-fude
- ~~~~~~~~~~~~Chairmancof the Board in 'Development & Strategy, its Gas Division in 1997; and Managing Director,
- July 2002. From 1999 to ~~~~~~~~~~~~~~~~~and was elected to his 'elected Executive Vice BarntnEeg 2001, hwas Co-head of .current position in2001.' President, GEUtility Partners, LLC, anenergy'
- - ~~~~~~~~~~~~~~Deutsche Bank's Global Pnortoti he was Oprations Group in industry strategic Investment Bakada Vice President Goldman 1998, and becam BE consulting irm.
member othBorofhe Sachs, working with 'President in2000.Prior Previously h held Bank's Global orporates
-r ad Constellation to a'develop -to this he erved 13 several executive Institutions Division) Other it pwrmkeig- 'yassChrman positions:t
- . positi~~onsheld while at : -business; prvousl , Maryland Public Service, ,Uniconn/CoEdf Deutsche Ba'nk included srved as director, Enron Commission.' Prvosglni,icidn Senior Chairman of the Board of CaPital & Trade -lbinude Execuiv e ~idtand ce
-Deutsche Banc Alex. Brown .Resources, joining them ietrMrl rsdent
' H also CEO ofCliet hePrivte and 'hen the boughtAERX, mployment Security served as its Chief Asset Management Group Inc. a conmpany he .:Administration; Speil, ula fi adld:
~~~~~~Americas, and Global Head of hepdfud Tht Assistant to Maryland its nuclear fle't
-the Private Banking Division. specialized inemission LiueatGvro -
Prvo6lhwas Vic crdittrading. Blair Lee lll,and2 1 - ~~~~~~~~~~~~~~~~~~Chairmanof Bankers Trust . ~BaItimrCt't
- -, . . -~ ~ ~ ~ ~ ~ ~ ~ ~ ~~~~~~~~~~~~~~~~~~~2
I, -
_ _E _w ^ Y ^ . s.8w ' ~~~~~~~~~~~~~~~~~~~~~~~~~~l C, Th EFoln S a n_ _ -i -
_Fnac se 8_- ~~ ~ ~ ~ ~ ~ L]~ ~~~l Pes- uii s acusito by an T 9wsnm(
11969; in201. Pnorto EnegyAssitant beame Energy i 2001. PiorKto hEergen 20. efone 1988; Rame Asslinstat 196 inr199 was:o Enrgy in2002P1 t 43, joined Constellation 51, jined Corfstellation -43, joined Constellation 45, joined BGE* in, 3 joined BGE* in 'P44, joined Constellationi
[53w joined B3GE* in this she was Senior Vice -his t he Was Senior Vice this she was Vice`- I ~Treasurer and Director General Supervisor in this he was Senior Vice Treasurer-Assistant rSecretary in 1983; PeietadCOo President and Grnup 'President and Corporate of Financial ' '-'he Gas Construction PeintoHuan 1
elected Vice President, Armstrong Holdings, Head-Ogilvy Public . 'Group Gene'ral Counsel ~-Management in 1995; - Diision, and in1996 Resources at Tellabs,
,.Accounting ~Inc.-
Previouly she Relations, managing its 'fo The St.Paul § . joined Constellation -was promoted to Inc., aglobal teleo k__Economics in1988 spent 15 years with ,energy and environment Companies, Inc. She ower e s Director of Gas Business manufacture ViCe President, General Motors (GM), patie Previously -.-was also AssistanitVice --formation in'1997, Development. In 1997 Previously, he held Customer Service & starting inth'e New York , 'he served as snostf PridtadAscae.4.' srvgastseir hewsnamed Project human resource v-*.;- -
1,,
TeNaua Group Counsel of 'financial officer; became Manager--Corporateli.,--- management positions f.Vice Accounting in President, Customer Service &
1991; Treasurers Office; positions included other mmera Resources Defense ':'USF&G Corporation" ' § Treasurer-GM of Canada Council Prs~- -utlisaqiiinb
- Managing Director- '
iac n reasurer, Restructuring Project; t_
n19 a ae at Platinu m Technology Inc 'and Syse fDistribution in1993 Umtd Vic Prsden Secretary for U.S - h t Pu opanies 'Constellation Power Manager, Corporate Software Associates ice President, Retail ..-of Finance for,GMAC, Senator Christopher in1998. Previousy, she: _Source Hol6dinigs in2000 Strategy & Development, Inc., and spent 14 year fServices in 1998; Vice" Assistant Treasurer for' Dodd (D-CT); and National Public Radio's
' held associate posiions~
in two intemational law
~ and was' elected to his . :adin 2002 wai elected
" curr-ent position in2001.:-, to his current position.
'with Amoco Corporation inavariety of ~ 1 President, Corporate -,GM; and CFO for GM s firms, Hogan & Hatson 1 " .'-'management positions,"
Strategy&Dvlpet DepiCassSses Eioof"onn' '- .
in 1999; and assumred ",division. ':Edition" and then 'and OMeIveny &Mye_rs. - including touryasa his current position - ' ' Foreign News Editor. '4 ' ietro uan in 1999. _
_ __ I _ '4NorwabasedIn
- . Stavanger, Norway ..
Energy Group, Ic b th holding company for Baltimore Gas and Electn.' Company (BGE) and its subsndianes. -
On Apnil 30:
-1999 Consteffi i3 BEn 51oindCnstiiaio 3ioiedCostelition 43 - -oinedConsteilatn
WE'RE TAKING THE NEXT STE UNDERSTANDING OURFOM 1-S-E Qrft aN~rOR SFILNG
- H Weave a disc~~~~~~~~~~~~~~~~tl.
os tbaUke.
infull leader ~ onit Er K Fiv~~~~~~e ear o,e ere amongstefrt acroationtouepan Englishtoprv ey to make our financial information easier, to understand.
Now, we're taking'-the nex step.
-- Th'e information.on the next ew. pages is intended to help make our Fom1--~-u nulrpr equired
- - ~~~~~~to be filed with the Securities-and Exchange Commission-m~rore.welcomn ndlSs complex.
L V~~~~~~~~~~ery-simrply, we want v'ou to know nd understand.what we d6.'
It'sabout all giving investors: the information they need
'4< our continued leadership i providing information tat all,
~~~~~~~It's sharehold ers can better udesad I I~~~~~~~~~~~~~~~~~~~~~~~
I~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~
I - -
FULL .DISCLOSURE: AND TRANSPARENCY :
It has never been more important for coimpanies to provideq-6~ .~- ' --
insight ittheir business and o hymk
- iiesosbetter money. The.buzzword you often hear today is transparency. At ~
Constellation ~ ~ ~ ~ ~~k.- t 1tw zp:Constellation Energy, we View it as a priority to offeroour investors r Engy_ -
the informrationi they need to understand what dr,ie our business, - El This- yar we'vechosen to include the complete Form10-K in our _________
C-1n1iteIasoE-Mary11asmets I~~~~~~~~~~~~~~~~O.t.EeGbc C.
ye 20 02' AnulRpr The Form 10 Ki-a stanrdard docmn htWE ARE ENERGY.
~~~~~~~~~~~~~~~~~~~~~~~~GENERA MARKETING. DELIVERY.
allI U.S. publicly held cmaesrerequired to fIle annuLally withlik.n the Securiie an xcage Comimission (SEC). The document p___uiliy___C____L.d is availableto investors and anyone else who wishes to review.it.:,
-While the Form 10-K isicoimplex, it iswhere investors canTfind
'detailed and comnprehenrsiveinomtnaou a company ani Its You'll ind all ot our SEC filingsrihonheleto'p oprtions.T 6helpmake the inancial information Iritis'docuen ieste-otlao cr easier for you to find rn nd we he 'eoped a Form nest or f 10-~K overview and glo6sary of terms, both o'f Which follow on-the
-etfew pages., -
7 I-~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~
[ ~~~~~~~~~~~~-
-j - - -
' j-,j -~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~7
~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~19~~~~~~_
BREAKING DOWN OUR FORM 10-K The information contained in the Form 10-K is broken down *> Part IV: a listing of exhibits, certain executive and board of into Parts, which are further broken down into Items. Our Form directors' signatures, and executive officer certifications.
10-K has four parts:
Over the next few pages, we provide summaries of some
'> Part I: in-depth descriptions of our businesses. of the major topics included in Parts I and 11,and where you
- >Part I: our financial performance, the information in which can find them. We're doing that for Parts I and 11because cnfn hm er on htfrPrsIad1 eas inPart or investors arefinancaly usually perfo most rmaine ,ste interested. they contain the most detailed information about our business.
.4 Part Ill: directs readers to our proxy statement for the details on our board of directors and executive officers and their compensation.
PART I: OUR BUSINESSES Part I of our Form 10-K provides details about our and our other nonregulated businesses. Also included is infor-businesses- our merchant energy business, our regulated mation about environmental matters, employees, properties, energy delivery utility Baltimore Gas and Electric Company, and executive officers.
Item Sect:.o Business Overview Copn decitioan brief background.
.Oeaigsegmgent deas Merchant B B
- ,, =,-Energy Batimore Gs It Discussion of fuel sources we use to generate el ectrcity-;
.~~. energy prtn statistcs for the last five s b dc a s and Electric
- Electric'and~gas operating statistics'for the last fiveyars Compa
-Other + Descnpti6f6Urf6n Busoneuses uohffnrgltdbs~se Evi -* Discussion of the environmental maiers affecing the c n Properties ]f a
_____________1~ 4 Ofice mdfacilitiesA eownades Exeutive ofConstellation IL -~
office
'-~<
ages current posito
~-'~--' ~.0 adre 20 i I
PART II: OUR FINANCIAL PERFORMANCE Part 11contains management's discussion of our results of W4Introductory Items: the basics.
operations and financial condition. It compares 2002 results 64 Management's Discussion and Analysis: the context.
to 2001, and 2001 results to 2000. The sections in Part 11 -4 Financial Statements: the numbers.
include: **. Notes to the Financial Statements: the details.
INTRODUCTORY ITEMS The basics. Here's information about our common stock, prices and dividends, and historical financial data.
,- -item
- 'e-Marke or. Dn h. rtad d a idnand sto6k prick rlast two es Registrant's ' -
Common Equity
>and Related
-hareholder Matters I
- ~~~~~~~~~~~~
Selected .4 Sum~~~~-mary '& 6reand financal conditions of6 of oprains Coselation Energy and Baltimo as anid Electr FiniancialDt and financial tatistics for the pas five years.~
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.
1~~~~~ Item s - eto Maaeets fntoutoi4 OvervieWf our company.
Di cussion ___
and Analysis of Acc tini ccm co en ti ci Policies andrsul oondition Financial Condition and Results of DiScion of the significant eand 20011that impacted our company
,, Opratuions °f f tSignificant Events tegn of - ve trategy,'which focuses on maintaining a bala ofsabili dro
- - Business"~ . Discussion of the ~eir'Th icha we rate,in general.and iet oe E', - -, .
nvironmnt 1 1states'.'nd
! -' howreg' d h`th-'r, - ' oth factors affec our b'siness:
ureaningsbroen o.wAThediscuo dn as foll t
'_Results of
- Operations -- Ou r&eal netc incrne7 -*
- -Our nfet incomie for or mercant nErgybusines
=-
C, 'r,, Our net income forBaltimore Gas and Electric's and gas businesses.,
electric&egulated
'Our net irn&oreur ote nneglted tbusinesses-` '-2
.4 Our non-6perating income and expenses
- J - . Financ .i CahfI shflow d sfothelast three years..,z, .
voi1etaUition
. Cred
..- -- atings fr Constellation Er nd Baltimore Gas and Electric C I . Capital requirements for the last three years and estimates forthe next two LIIIIi1I.4,-., How weexpect tofund our capital requirements X-2 Financiai obligations over the next five years and beyond
'--,- '- Maket DiWl c>ssion of ou'r market risk including interest rate comoiy ri credit risk equ
_ . -. . F. _ _ , j . - .price risk.% , .>-3;w t-,-,','t - ;0 . '*.Discussion of XOW wmAnaetos.ik 21
OUR FINANCIAL STATEMENTS The numbers. We provide separate financial statements for Constellation Energy and Baltimore Gas and Electric. This section also includes our management and auditor reports on our financial information.
I L.-,; '_ -Z f-T-_ `_.! - . -, i , I:; -- 7t7 r. 7 7 Item . -; - -qe - ;. 1 -. '_'}-
- ~ 77~~-.7- 4 ,~ ,, I I ~' 'Tr'-
I Financial Report of- i . Management's report on how the financial statemeints are prepared signed by Chairman of the Statements and Supplementary
-Management. J Board, President aid Chief Executive Officer Mayo A.Shattuck I and by SeniorVice President &
Chief financial Officer E.Follin S ;r ith Data Report ,.. External audit report of PricewateouseCoopers L nepnd =-- ..
C .'Rvue, expenses income,- and earnigs for the last three y e Statements (separate statements included for Constellation Energy and Baltimore Gas and Electric) of Incom'- [ -
IIisiitedr Assets iabilities and&euity for the ast two years
-Balance Sheets, - ..-(separate'statements included for Constellation Energy and Baltimore Gas and Electric);-
e ',Consolidaoed ** Cash flos from operati investinrg and financing activities for-the last t Statements of.-- ' - ' :-(separate statements included for Constellation Energy and Baltimor Gas and Eletricy-CashFlows:
Consolidatid. Changes in common stock retained earnings t ensive incom r n.Statements of., > ; ¢ M-t,'§lstreya5Tt-Common, attre er Shareholders' Equity - .
and Comprehensive --
Income -
F ~~~~~.4 Logtr detpeeec tc n omns~~~ utdalfrels
-Consolidated -l .tLog-termydebty
-. prefeence stock, and comrnon sharrhsiders' equitydeta i Statements of - J Capitalization NOTES TO OUR FINANCIAL STATEMENTS The details. We explain the processes, events, actions, projects, issues, and specifics that produce the amounts reflected in our 1
financial statements.
m, JZLll I
Item - , Section;:. L
'I :, ~~
.9 -
-, - , -,, -3
,t - _ ,-" - "'
I Notesto -- -- Note 1.
Consolidated ':Significant .' ffecontin ton earnings ehdsofthat ~u~K2 that use-'z----
we -V.
applying fair-value a6couhting to stock optionsand stock grants Financial Accounting Policies '.:' Recently
- adoptedorissuedaccountingrulesestablishedbysta arseaers.j-1 ^t-Statements - -- _- - - - . I- - I., --
- - Note i .--
2<....- . I2' . Workforce reduction mpairment losses andoter speciai p d ater am Impairment Losses,-
Workforce Reduction;n Contract Termination, an(
Other Special Items -
j
.; 1A 200 an 20004
-f,.00 L.
I-- _______________
Note 3. 4 *,-<R1evenue, exp)ense, net income,san~dother.fihancia informto fo eotbeoeaig2 0u Information by- - 'X-t= segm'ents and othernonre'gulated businesses for the last three years Operating Segment -
22 I I
NOTES TO OUR FINANCIAL STATEMENTS (continuted)
EM t
r t--
is=
item
s r --...
M.
Notes to 0.,- ,' i t4t
,,__1 L --..Te cti 6o
_--;r5 . ..
L
-;, -)H I
.s--
I? ...4 --.-
Note 4. '0 Real estate, power project and financial investments for the last two years' -
i,, .'; Consolidated --;:. , '-Investments'. , '-
rr.:-- Financial.'- '-' ~~~~~~~~~3' ' . .3.3" _
s:' ' Statements , '`.Note5.`1 ,- ..e --ass'etflor' the Wt two-ye6rs'.
- '- :':-,=., .
$ . :v.:-
.:Regulatory Assets f ... , .. , . n Iz I
- g wE = r E .r V ir
,-,; ' ', -is i's ' ..'.Note 6..t-i ,. + Pension and postretirement benefits obligation, asset, funded status, and assumption details l ,- , t - . , . Penson;i-f about our employee benefit planis for the last two years '
i: -
- b
. Y O Postretiment,Other - Information on other' posteniployment benefits.
It te -^ r;D - ! s Q p g Postemployrrent,'and- se Employee savings plan information and company matching contributions F.t -:- .; .: . -.- :. ~,i:.-.,-E- ~.,.
,. J S: , X,,, -Employee Savings ,: .ft :s_...-3.-..;
< *,x,'.--,;,T,,>'
'J,v 6,,'+-=4,i'-
'r' 5,.,,,
,:;':i '.
f'.'. -;f ;>C=*;
.3 j~~~~~~~~~~~~~~~~~~~~~~~~~~~~~.3
-- - :::: -:- -.. Plan Benefits dF.
F s -- i-t.;: ' . ,- a ,:, -Note 7. 331 24 Short-tem = aa paper tstoaidi available bank lines-of credit for r j , ..0 - ..} 'Short-Term kConstellatio'nEnleig'y, Baltimore '.Gas and Electric' and '..3 ouri--- . ionregulated businesses. 7>-
.b . . : - ,. .. :. - - Borrowings '- i r r~~~-
.3. - _
'Jt-3.:_b-x ,3 r.; 3.
. _
- i i -
.333.3.._-;-
5 f.-A
~-
f " ' ' XA ' ' , :
67
- , I
- ,- '- . ': i
. :. ' Note 8. -' + Long term debt and preference stock'details for Constellation'Energy Baltimore Gas and Electric Long-Term - . and our'nonregulated businesses L}; -
- t. f *- ^
f
, Detand - ..- SJ=~
k z :E: ' ;
-. -. < i .,-- -- :
' ! s 5 3 i
'. .< Note 9.'.: .' ta detai lastthree years 1ncome sfor.the FT.
- _ J F r:, SU Le', '
S rs ' t' O' ' S '
. ., 1 Tax es
' ' ' ',; ." Q
". 'a
' Cc Not 10. . Lease i o r lastent th yea s,for the next fiveyeasnd for beyond 2007.'_ Z2 f ' ' ' ,', w i
-,Leases t' -; L -l ' ,,= e3. 3~
-:_*' 3
- ,-- .- -~-<
F '- -
- : . .-;. , - -- .. V3- , .3 3-%:-
ft ' ' + £i f _ .S
r: .t
- f ' '
1i
, .-Note ' .,o4Comnitments for the next five years and beyond 2007 .
B V t s w Commitments, - +4 Financial gua'rantees we've miade for our-businesses.-- --
_..-Guarantees, and ' Environmental issues and legal proceedings involving our company
,_ : j-: o: i' - . , L d.+ fuel storage is§ues and insurance coverage.
_, ', ': f
',r ., -,-' ,_:; - , - '
Contingencies . Nuclear j - '; ',. "E .. 'D D ' -: : g'+Issues concerning lornia power urchase agreemnents@_
- . . . 0
.;; - i; i_.r, ..
to mnag intres rat exosure and electricity price fluctuations,"and results of thdse-29, he-3Note 12. 2~~~t maag interetrate=
,,} : ,, , ' t e - ;. ; 00 .
Hedging Activities --, ', actionsover the last two years.",,m F=
f ;': '? '_' X .f
. -, Fair.Value of I 0 Inforuiuation on the fair value 'of our'financial instruments.-..
?Financial Instruments ' -Soc1 .opion..,
-Note~4 ' ':P2-:. and=, v a,.ards. for-the last th-ee.years stocki _f*Wt k- f ,. ,,,', :_ r _ _.._ __.__ _-_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _.-_ _ _ _ _.-_-_:.i__, ,-'
f, : , ,. , .. \, I 5: ' . 'f :: - - :1
's:--Note 13 t nd-' stc awa s r ?{
§.
Y
, _t AS
- )
D i, .;
z a
I
- 1
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- I
_ . _ i Y ,> x } j I
--Comnpensation
-- :f a :-0 ' 1 -ote 14.-.eption of and financial info'rmation' on AllianceFellonMcCord NewEnergy and Nine Mile Point
-'- - - 'l : ' ' '-D' l acquisitions . - acquisitions X : .=: .: Li
= t ,-> g: =, ~~~7 7,* =7-,1=;,,
77fw@= ,, ,,-,,
f '
&. S .
m '
I
' ffi.Note 15. ,- N. Relationships'and interactions anong our 'subsidiaries - their effect on our income statement and f- - 0 ' ; . ia
'- Related Part-. ba ance'sh ett.:,. ,. . , ,, ,,,. , ,
tiS ;' 'I . Transactions-BGE -1
' f -0'- -' ': '3:'1
- I
. - =
r
}; t": - C- 't1 5 i Note 16. . 1;.+ Quarterly revenue, inicome,and earnings for Constellation Energy and Baltimore Gas and -
3Electric ;, the last two years.;-*2< =-,, F ,, ; -.-,;
F -"
'0 '
- - xs
}
4 Ouarterly Financial '.j -Jv,, over --
E f . f - g \. .
- - Data - \.3 .3 ,i 3, 3. =3 - = _______________________- ______
- E =,,;, D . . L
- __ - - - --- I
- i. . - . ... . . - . ]_s z _ ,4 o fl 'm--si_ '5 ;aSS; ]
23
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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, 2002 Commission IRS Employer file number Exact name of registrant as specified in its charter Identification No.
1-12869 CONSTELIATION ENERGY GROUP, INC. 52-1964611 1-1910 BALTIMORE GAS AND ELECTRIC COMPANY 52-0280210 MARYLAND (States of incorporation) 750 E. PRATT STREI ET BALTIMORE, MARYLAND 21202 (Address of principal executive offices) (Zip Code) 410-234-5000 (Registrants' telephone number, including area code)
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
Name of Each Exchange on Thde of each dass Which Registered New York Stock Exchange, Inc.
Constellation Energy Group, Inc. Common Stock-Without Par Value j Chicago Stock Exchange, Inc.
J Pacific Exchange, Inc.
7.16% Trust Originated Preferred Securities ($25 liquidation amount per preferred security) issued by BGE Capital Trust I, fully and unconditionally guaranteed, based on several obligations, by Baltimore Gas and Electric Company
} New York Stock Exchange, Inc.
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
Not Applicable Indicate by check mark whether the registrants () 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 3 No Cl.
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 10-K or any amendment to this Form 10-K.
Indicate by check mark whether Constellation Energy Group, Inc. is an accelerated filer Yes No M.
Indicate by check mark whether Baltimore Gas and Electric Company is an accelerated filer Yes I No FxI.
Aggregate market value of Constellation Energy Group, Inc. Common Stock, without par value, held by non-affiliates as of June 28, 2002 was approximately $4,791,476,554 and February 28, 2003 was approximately $4,293,890,795 based upon New York Stock Exchange composite transaction closing price.
CONSTELLATION ENERGY GROUP, INC. COMMON STOCK, WITHOUT PAR VALUE 164,764,752 SHARES OUTSTANDING ON FEBRUARY 28, 2003.
DOCUMENTS INCORPORATED BY REFERENCE Part of Form 10-K Document Incorporated by Reference III Certain sections of the Proxy Statement for Constellation Energy Group, Inc. for the Annual Meeting of Shareholders to be held on April 25, 2003.
Baltimore Gas and Electric Company meets the conditions set forth in General Instruction (l)(a) and (b) of Form 0-K and is therefore filing this Form in the reduced disclosure format.
TABLE OF CONTENTS Pawe Forward Looking Statements ............. ............................................... I PART I Item I-Business .............................................................................. I Overview . ........................................................................... I Merchant Energy Business ............. ............................................... 3 Baltimore Gas and Electric Company ................................................... 9 Other Nonregulated Businesses . ....................................................... 13 Consolidared Capital Requirements ............... ..................................... 13 Environmental Matters ............................................................... 13 Employees .......................................................................... 16 Item 2-Properties .............................................................................. 16 Item 3-Legal Proceedings . ..................................................................... 18 Item 4-Submission of Matters to a Vote of Security Holders ......................................... 18 Executive Officers of the Registrant (Instruction 3 to Item 401(b) of Regulation S-K) ............ 18 PART 11 Item 5-Market for Registrant's Common Equity and Related Shareholder Matters ..... ................. 20 Item 6-Selected Financial Data .................................................................. 21 Item 7-Management's Discussion and Analysis of Financial Condition and Results of Operations .......... 23 Item 7A-Quantitative and Qualitative Disclosures About Market Risk ................................. 61 Item 8-Financial Statements and Supplementary Data ............ .................................. 62 Item 9-Changes in and Disagreements with Accountants on Accounting and Financial Disclosure .... ..... 117 PART Il Item 10-Directors and Executive Officers of the Registrant ........................................... 117 Item I I-Executive Compensation ............................................................... 117 Item 12-Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters .................................................................. 117 Item 13-Certain Relationships and Related Transactions ............................................ 117 Item 14-Internal Controls and Procedures . ....................................................... 117 PART IV Item 15-Exhibits, Financial Statement Schedules and Reports on Form 8-K ............................ 118 Signatures .................................................................................. 123 Constellation Energy Group, Inc. Certifications ..................................................... 126 Baltimore Gas and Electric Company Certifications ................................................. 128
Forward Looking Statements
- the inability of BGE to recover all its costs We make statements in this report that are considered associated with providing electric retail forward looking statements within the meaning of the customers service during the electric rate freeze Securities Exchange Act of 1934. Sometimes these period, statements will contain words such as "believes,"
- the effect of weather and general economic and "expects," "intends," "plans," and other similar words. business conditions on energv supply, demand, These statements are not guarantees of our future and prices, performance and are subject to risks, uncertainties, and
- regulatory or legislative developments that affect other important factors that could cause our actual deregulation, transmission or distribution rates performance or achievements to be materially different and revenues, demand for energy, or increase from those we project. These risks, uncertainties, and costs, including costs related to nuclear power factors include, but are not limited to: plants, safety, or environmental compliance,
- the timing and extent of changes in commodity
- the actual outcome of uncertainties associated prices and volatilities for energy including coal, with assumptions and estimates using judgment natural gas, oil, electricity and emission when applying critical accounting policies and allowances, preparing financial statements, including factors
- the timing and extent of deregulation of, and that are estimated in determining the fair value competition in, the energy markets in North of energy contracts, such as the ability to America, and the rules and regulations adopted obtain market prices and in the absence of on a transitional basis in those markets, verifiable market prices the appropriateness of
- the conditions of the capital markers, interest models and model inputs (including, but not rates, availability of credit, liquidity, and general limited to, estimated contractual load economic conditions, as well as Constellation obligations, unit availability, forward Energy and BGE's ability to maintain their commodity prices, interest rates, correlation and current credit ratings, volatility factors),
- the effectiveness of Constellation Energy and
- changes in accounting principles or practices, BGE's risk management policies and procedures
- the ability to attract and retain customers in and the ability of their counterparties to satisfy our competitive supply business and to their financial and performance commitments, adequately forecast their energy usage,
- the liquidity and competitiveness of wholesale
- losses on the sale or write down of assets due markets for energy commodities, to impairment events or changes in
- operational factors affecting the start-up or management intent with regard to either ongoing commercial operations of our holding or selling certain assets, and generating facilities (including nuclear facilities)
- cost and other effects of legal and and BGE's transmission and distribution administrative proceedings that may not be facilities, including catastrophic weather related covered by insurance, including environmental damages, unscheduled outages or repairs, liabilities.
unanticipated changes in fuel costs or Given these uncertainties, you should not place availability, unavailability of gas transportation undue reliance on these fonvard looking statements.
or electric transmission services, workforce Please see the other sections of this report and our issues, terrorism, liabilities associated with other periodic reports filed with the SEC for more information on these factors. These forward looking catastrophic events, and other events beyond statements represent our estimates and assumptions only our control, as of the date of this report.
Changes may occur after that date, and neither Constellation Energy nor BGE assume responsibility to update these forward looking statements.
PART I Constellation Energy maintains a website at Item 1. Business constellation.com where copies of our annual reports on Form 10-K, quarterly reports on Form IO-Q, current Overview reports on Form 8-K, and any amendments may be Constellation Energy Group, Inc. (Constellation obtained free of charge. These reports are posted on our Energy) is a North American energy company that website the same day they are filed with the SEC. The conducts its business through various subsidiaries website address for BGE is bge.com. Both website including a merchant energy business and Baltimore addresses are inactive textual references and the contents Gas and Electric Company (BGE).
of these websites are not part of this Form 10-K.
1
I ~~~~~~~~~~~~~~~~~~~~~~~~~~~
Constellation Energy was incorporated in For a discussion of recent events that have Maryland on September 25, 1995. On April 30, 1999, impacted Constellation Energy, please refer to Item 7.
Constellation Energy became the holding company for Managements Discussion andAnalysis-Significant Events BGE and its subsidiaries through a share exchange. section. For a discussion of Constellation Energy's Reference in this report to "we" and "our" are to strategy, please refer to Item 7. Managements Discussion Constellation Energy and its subsidiaries, collectively. and Analysis-Strategy section. For a discussion of the References in this report to the "utility business" are to seasonality of our business, please refer to Item 7.
BGE. Managements Discussion and Analysis-Business Our merchant energy business is a competitive Environment section.
provider of energy solutions for large customers in North America. It has electric generation assets located Operating Segments in various regions of the United States and provides The percentages of revenues, net income, and assets energy solutions to meet customers' needs. Our attributable to our operating segments are shown in the merchant energy business focuses on serving the full tables below. We present information about our energy and capacity requirements of, and providing operating segments, including certain special items, in other risk management activities for various customers, Note 3 to Consolidated FinancialStatements. Effective such as utilities, municipalicies, cooperatives, retail July 1, 2000, the financial results of the electric aggregators, and large commercial and industrial generation portion of our business are included in the customers. merchant energy business segment. Prior to that date, Our merchant energy business includes: the financial results are included in the regulated
- fossil, nuclear, and hydroelectric generating electric segment.
facilities and interests in qualifying facilities and power projects in the United States, Unaffiliated Revenues
- origination of structured transactions (such as Merchant Regulated Regulated Other Energy Flectric Gas Nonregulated load-serving, tolling contracts, and power purchase agreements), and risk management 2002 35% 42% 12% 11%
services (hedging of output from generating 2001 16 53 17 14 facilities and fuel costs), 2000 1 57 16 16
- electric and gas retail energy services to large commercial and industrial customers, and Net income(l)
- generation and consulting services. Merchant Reguated Regulated Other Energy Electric Gas Nonregulated BGE is a regulated electric and gas public transmission and distribution utility company with a 2002 67% 29% 8% (4)%
service territory that covers the City of Baltimore and 2001 75 22 10 (7) all or part of ten counties in central Maryland. BGE 2000 68 34 9 (1 1) was incorporated in Maryland in 1906.
Total Assets Our other nonregulated businesses:
- design, construct, and operate single-site Other Nonregulated heating, cooling, and cogeneration facilities for Merchant Reuated Regulated & Corp.
commercial and industrial customers, Energy Electric Gas Items
- provide home improvements, service heating, 2002 63% 25% 8% 4%
air conditioning, plumbing, electrical, and 2001 57 27 8 8 indoor air quality systems, and provide electric 2000 56 26 9 9 and natural gas retail marketing, and (1) Excludes special items included in operations and a
- own and operate a district cooling system for cumulative effect of change in accounting principle commercial customers in the City of Baltimore, as discussed in more detail in Item 8. Financial Maryland.
Statements and Supplementary Data.
In addition, we own several investments that we do not consider to be core operations. These include financial investments, real estate projects, and interests in a Latin American distribution project and in a fund that holds interests in two South American energy projects. We decided to sell certain non-core assets and accelerated the exit strategies of other projects. We sold certain non-core assets in 2002 and closed our retail merchandise stores in December 2002.
2
Merchant Energy Business PJM Plafform Introduction We own 6,485 MW of fossil, nuclear and hydroelectric Our merchant energy business integrates electric generation capacity in the PJM region. The output of generation assets with the marketing and risk these plants is managed by our origination and risk management of energy and energy-related commodities, management operation and is hedged through a allowing us to manage energy price risk over geographic combination of power sales to wholesale and retail regions and over time. Constellation Power Source, our market participants.
origination and risk management operation, dispatches BGE transferred all of these facilities to our the energy from our generating facilities, manages the merchant energy generation subsidiaries on July 1, 2000 risks associated with selling the output and obtaining as a result of the implementation of electric customer the fuel, and structures transactions to meet customers' choice and competition among suppliers in Maryland, energy and risk management requirements. Generation except for the Handsome Lake project that commenced capacity supports our origination and risk management operations in mid-2001. The assets transferred from operation by providing a source of reliable power supply BGE are subject ro the lien of BGE's mortgage.
that provides a physical hedge for some of our load- These facilities include the Calvert Cliffs Nuclear serving activities. Power Plant (two units), which is our largest generating Our merchant energy business: station. In March 2000, Calvert Cliffs became the first
- provides service to distribution utilities, nuclear power plant in the United States to achieve municipalities, and large commercial and license renewal. The Nuclear Regulatory Commission industrial customers with approximately 18,700 (NRC) approved a twenty-year license renewal for both megawatts (MW) of peak load in the aggregate, units of Calvert Cliffs, extending the license for Unit I
- owns approximately 11,300 MW of generation to 2034 and for Unit 2 to 2036.
capacity, and Our merchant energy business provides standard
- has under construction an 830 MW natural offer electric service to BGE as discussed in the gas-fired combined cycle generating facility in Baltimore Gas and Electric Company section. Our California. merchant energy business meets the load-serving We analyze the results of our merchant energy requirements of this contract using the output from the business as follows: PJM facilities and from purchases in the wholesale
- PJM Platform-our fossil, nuclear, and market. For 2002, the peak load supplied to BGE was hydroelectric generating facilities and load- approximately 5,425 MW.
serving activities in the PJM Interconnection (PJM) region for which the output is primarily Plants with Power Purchase Agreements used to serve BGE. We own 2,530 MW of nuclear and natural gas
- Plants with Power Purchase Agreements-our generation capacity, and have under construction an generating facilities with long-term power 830 MW natural gas-fired facility that will commence purchase agreements, including our Nine Mile operation in 2003, with power purchase agreements for Point Nuclear Station (Nine Mile Point) their output. These facilities include Nine Mile Point, nuclear generating facility and our new which is our second largest generating station. We Oleander and University Park generating purchased 100% of Unit 1 (609 MW) and 82% of facilities. Unit 2 (941 MW) in November 2001. The remaining
- Competitive Supply-our wholesale business interest in Nine Mile Point Unit 2 is owned by a that provides load-serving activities to subsidiary of the Long Island Power Authority. Unit I distribution utilities (primarily in Texas and entered service in 1969 and Unit 2 in 1988. Nine Mile New England), other wholesale origination and Point is located within the New York Independent risk management services, and electric and gas System Operator (NYISO) region.
retail energy services to large commercial and We sell 90 percent of our share of the Nine Mile industrial customers. Point plant's output back to the sellers at an average
- Other-our other gas-fired generating facilities, price of nearly $35 per megawatt-hour (MWH) under investments in qualifying facilities and domestic agreements that terminate between 2009 and 2010. The power projects, and our generation and agreements for the output of both units are unit consulting services. contingent (if the output is not available because the We present details about our generating properties plant is not operating, there is no requirement to in Item 2. Properties. provide output from other sources). The remaining 10% of Nine Mile Point's output is managed by our origination and risk management operation and sold into the wholesale market.
3
_ -_ ~_ - ..-.. ,_ -
After termination of the power purchase Competitive Supply agreements, a revenue sharing agreement will begin and We are a leading supplier of energy through load-continue through 2021. Under this agreement, which serving activities in North America to wholesale applies only to Unit 2, a strike price is compared to the customers and large commercial and industrial customers and assist them in managing their energy market price for electricity. If the market price exceeds needs. Our competitive supply activities include the the strike price, then 80% of this excess amount is 800 MW Rio Nogales natural gas-fired generating shared with the sellers. The revenue sharing agreement facility that commenced operation in mid-2002 and is is unit contingent and is based on the operation of the used to manage our Texas portfolio.
unit.
We have an operating agreement with the Long Origination of Structured Transactions Island Power Authority subsidiary to exclusively operate We structure transactions that serve the full energy and Unit 2. The Long Island Power Authority subsidiary is capaciry requirements of various customers outside the PJM region such as distribution utilities, municipalities, responsible for 18% of the operating costs (and cooperatives, and retail aggregators that do not own decommissioning costs) of Unit 2 and has sufficient generating capacity or in-house supply representation on the Nine Mile Point management functions to meet their own load requirements. We also committee which provides certain oversight and review structure transactions that serve the full energy and functions. capacity requirements and other operational and The license on Nine Mile Point's Unit I expires in administrative processes for large commercial and 2009 and in 2026 on Unit 2. We have commenced a industrial customers.
license extension initiative for both units with the These activities typically occur in regional markets objective of obtaining up to 20 years of additional in which end user customers' electricity rates have been operations. We expecr to submit the license exrension deregulated and thereby separated from the cost of application to the NRC in the fall of 2003. generation supply. These markets include: New England, the Mid-Atlantic, Texas, the Midwest, the Our other facilities with power purchase West, and certain areas of Canada. Contracts with these agreements consist of: customers generally extend from one to ten years, but
- the Oleander project, which commenced some can be longer. We currently have approximately operations in mid-2002, and 18,700 MW of load under contract for 2003.
- the Universiry Park project, which commenced In 2002, we acquired NewEnergy and Alliance as operations in mid-2001. discussed in Item 7. Managements Discussion and We have sold portions of the output of these Analysis-Significant Events section. These acquisitions facilities ranging from 50% to 100% under tolling expand our business in the competitive supply market contracts for terms ending in 2005 through 2009. by providing electricity, natural gas, transportation, and Under these tolling contracts, our respective other energy related services to large commercial and counterparties will pay a fixed amount per month and industrial customers throughout the United States.
To meet our cusromers' load-serving requirements, have the right, but not the obligation, to purchase our merchant energy business obtains energy from power from us at prices linked to the variable fuel and various sources, including:
other costs of production.
- our generation assets (including our new Rio We are currently leasing and supervising the Nogales gas-fired facility),
construction of the High Desert Power Project, an
- tolling contracts, which provide us the right, 830 MW natural-gas fired combined cycle generating but not the obligation, to purchase power at a facility in Victorville, California. The project is price linked to the variable cost of production, scheduled for completion in mid-2003. including fuel, with generation companies that We signed a long-term power sales agreement with generally extend from several months to several the State of California. The contract is a "tolling" years but can be longer, structure, under which the California Department of
- bilateral power purchase agreements with third Water Resources (CDWR) will pay a fixed amount of parties, or
- regional power pools.
$12.1 million per month and provides the CDWR the right, but not the obligation, to purchase power from Risk Management Activities the High Desert Power Project at a price linked to the Our origination and risk management operation actively variable cost of production. During the term of the uses energy and energy-related commodities in order to contract, which runs for seven years and nine months manage our portfolio of energy purchases and sales to from the commercial operation date of the plant, the customers through structured transactions, to obtain High Desert Power Project will provide energy market intelligence, and to take advantage of arbitrage opportunities that exist across different markets. These exclusively to the CDWR. The capacity payment is activities involve the use of a variety of instruments, proportionately reduced if the plant's availability is less including:
than 95%. We discuss the High Desert project in more
- forward contracts (which commit us to detail in Item 7. Managements Discussion and Analysis- purchase or sell energy commodities in the Significant Events section. future),
4
- swap agreements (which require payments to or Fuel Sources from counterparties based upon the difference Our power plants use diverse fuel sources. Our fuel mix between two prices for a predetermined based on capacity owned at December 31, 2002 and contractual (notional) quantity), our generation based on actual output by fuel type in
- option contracts (which convey the right to buy 2002 were as follows:
or sell a commodity, financial instrument, or index at a predetermined price), and Fuel Capacity Owned Generation
- futures contracts (which are exchange traded Nuclear .............. 28.6% 53.4%
standardized commitments to purchase or sell a Coal ................. 24.2 35.7 commodity or financial instrument, or make a Natural Gas ........... 25.6 3.3 cash settlement, at a specified price and future Oil .................. 6.7 1.3 date). Renewable and Active portfolio management allows our origination Alternative(l) ....... 4.3 4.3 and risk management operation to manage and hedge Dual(2) .............. 10.6 2.0 its fixed-price purchase and sale commitments; provide (1) Includes solar, geothermal, hydro, biomass, and fixed-price commitments to customers and suppliers; waste-to-energy.
reduce exposure to the volatility of cash market prices; and hedge fuel requirements at our generation facilities. (2) Switches between natural gas and oil.
Other We discuss our risks associated with fuel in more We own 1,491 MW of generating facilities and detail in Item 7. Managements Discussion and Analysis-qualifying facilities and domestic power projects, which Market Risk section.
include several natural gas-fired facilities that commenced operation since 2001. The output of these Nuclear facilities is managed by our origination and risk The output at Calvert Cliffs over the past five years has management operation and sold into the wholesale been:
market.
Generation Capacity In addition, we hold up to a 50% ownership MWH Factor interest in 28 operating energy projects that consist of electric generation (primarily relying on alternative fuel 2002 ...................... 12,087,408 82%
sources), fuel processing, or fuel handling facilities and 2001 ...................... 13,648,932 92 2000...................... 13,826,046 93 are either qualifying facilities under the Public Utility Regulatory Policies Act of 1978 or otherwise exempt 1999 ...................... 13,309,306 91 from, or not subject to, the Public Utility Holding 1998 ...................... 13,326,633 91 Company Act of 1935. Each electric generating plant The output at Nine Mile Point over the past five sells its output to a local utility under long-term years has been:
contracts.
Our merchant energy business has invested in Generation Capacity MWH' Factor partnerships that own 13 operating power projects of which our ownership percentage represents 37 2002 ................... 111,727,567 87%
megawatts of electricity that are sold to Pacific Gas & 2001 .................... 11,613,519 86 Electric (PGE) and to Southern California Edison 2000 ................... 11,243,095 83 (SCE) in California under power purchase agreements. 1999 ................... 10,766,425 79 The projects entered into agreements with PGE through 1998 ............... 10,837,848 80 July 2006 and SCE through April 2007 that provide for *represencs our proportionate ownership interest fixed-price payments averaging $53.70 per megawatt-hour plus the stated capacity payments in the original agreements.
We also provide the following services:
- operation and maintenance services, including testing and start-up, to owners of electric generating facilities, and
- nuclear consulting services to the nuclear utility industry, along with plant life cycle support services, including aging management, spent fuel management, and project management and engineering.
5
____ _ __ ____I___ __ - -- 5 The supply of fuel for nuclear generating stations On February 14, 2002, the Secretary of Energy includes the: submitted to the President a recommendation for
- purchase of uranium concentrates, approval of the Yucca Mountain site for the
- conversion to uranium hexafluoride, development of a nuclear waste repository for the
- enrichment of uranium hexafluoride, and disposal of spent nuclear fuel and high level nuclear
- fabrication of nuclear fuel assemblies. waste from the nation's defense activities. In July 2002, the President signed a resolution approving the Yucca Uranium Mountain site after receiving the approval of the U.S.
Concentrates: We have under contract sufficient quantities Senate and House of Representatives. This action allows of uranium to meet 100% of both Calvert the Department of Energy to apply to the NRC to Cliffs' and Nine Mile Point's requirements license the project. The Department of Energy currently through 2004, 50% for both plants in expects that this facility will open in 2010. However, 2005, 60% for both plants in 2006 and the opening of Yucca Mountain could be delayed due 25% fr both plants in 2007. to multiple lawsuits initiated by the State of Nevada Conversion: We have contractual commitments and other interested parties, the NRC licensing providing for the conversion of uranium hearings, and other issues related to the site.
concentrate into uranium hexafluoride Storage of Spent Nuclear Fuel-On-Site Facilities that will meet 100% of Calvert Cliffs' and Nine Mile Point's requirements Calvern Cliffs has a license from the NRC to operate an through 2004, 50% for both plants in on-site independent spent fuel storage installation that expires in 2012. We have storage capacity at Calvert 2005, 67% for both plants in 2006 and Cliffs that will accommodate spent fuel from operations 50% for both plants in 2007.
through 2008. In addition, we can expand our Enrichment: We have contractual commitments that temporary storage capacity at Calvert Cliffs to meet provide 1OO% of Calvert Cliffs' and Nine future requirements until approximately 2025.
Mile Point's uranium enrichment Currently, Nine Mile Point does not have independent requirements through 2006 and 25% of spent fuel storage capacity. Rather, Nine Mile Point's these requirements for both plants in Unit I has sufficient storage capacity within the plant 2007 and 2008. until the end of its current operating license in 2009. If Fuel Assembly license renewal is obtained, independent spent fuel Fabrication: We have contracted for the fabrication of storage capability will need to be developed. Nine Mile fuel assemblies for reloads required Point's Unit 2 has sufficient storage capacity within the through 2013 at Calvert Cliffs and plant until 2012. After that time independent spent fuel through 2005 for Nine Mile Point Unit 2 storage capability may need to be developed.
and through 2009 for Nine Mile Point Unit 1. Cost for Decommissioning Uranium Enrichment Facilities The Energy Policy Act of 1992 contains provisions The nuclear fuel markets are competitive and we requiring domestic nuclear utilities to contribute to a do not anticipate any problem in meeting our future fund for decommissioning and decontaminating requirements. uranium enrichment facilities that had been operated by DOE. These contributions are generally payable over a Storage of Spent Nuclear Fuel-FederalFacilities 15-year period with escalation for inflation and are One of the issues associated with the operation and based upon the amount of uranium enriched by DOE decommissioning of nuclear generating facilities is for each utility through 1992. The 1992 Act provides disposal of spent nuclear fuel. The Nuclear Waste Policy that these costs are recoverable through utility service Act of 1982 required the federal government, through rates. BGE is solely responsible for these costs as they the Department of Energy (DOE) by January 31, 1998, relate to Calvert Cliffs. The sellers of the Nine Mile to begin to dispose of spent nuclear fuel. The federal Point plant and a subsidiary of the Long Island Power government has stated that it will not meet that Authority are responsible for the costs relating to the obligation until 2010 at the earliest. Nine Mile Point plant.
The 1982 Act assesses a tenth of one cent (one mill) per kilowatt-hour fee on nuclear electricity Cost fir Decommissioning generated and sold to pay for the costs of disposing of We are obligated to decommission our nuclear plants at spent fuel. We estimate this fee to be approximately the time these plants cease operation. Both Calvert
$13 million for Calvert Cliffs and $12 million for our Cliffs and Nine Mile Point are required by the NRC to portion of Nine Mile Point each year based on expected prepare financially for this decommissioning. When BGE transferred all of its nuclear generating assets to operating levels. We will pay our portion of these fees our merchant energy business, it also transferred the into the DOE's Nuclear Waste Fund.
trust fund established to pay for decommissioning Calvert Cliffs. At December 31, 2002, the trust fund was $239.7 million.
6
Under the Maryland Public Service Commissions The annual coal requirements for the ACE, (Maryland PSC) order regarding the deregulation of Jasmin, and POSO plants, which are located in electric generation, BGE ratepayers must pay a total of California, are supplied under contracts with mining
$520 million, in 1993 dollars, adjusted for inflation, to operators. Each plant is restricted to coal with sulfur decommission Calvert Cliffs through fixed annual content less than 4%.
collections of approximately $18.7 million until June All of our requirements reflect historical levels. The 30, 2006, and thereafter in an annual amount actual fuel quantities required can vary substantially determined by reference to specified factors. BGE is from historical levels depending upon the relationship collecting this amount on behalf of Calvert Cliffs. Any between energy prices and fuel costs, weather costs to decommission Calvert Cliffs in excess of this conditions, and operating requirements.
$520 million must be paid by Calvert Cliffs. If BGE ratepayers have paid more than this amount at the time Gas of decommissioning, Calvert Cliffs must refund the We purchase natural gas and transportation, as excess. If the cost to decommission Calvert Cliffs is less necessary, for electric generation at certain plants. Some than the amount BGE's ratepayers are obligated to pay, of our gas-fired units can use residual fuel oil or Calvert Cliffs may keep the difference. distillates instead of gas. Gas is purchased under The sellers of Nine Mile Point transferred a contracts with suppliers on the spot market and forward
$441.7 million decommissioning trust fund at the time markets, including financial exchanges and bilateral of sale. In return, Nine Mile Point assumed all liability agreements. The actual fuel quantities required can vary for the costs to decommission Unit I and 82% of the substantially from year to year depending upon the cost to decommission Unit 2. We believe that this relationship between energy prices and fuel costs, amount is adequate to cover our responsibility for weather conditions, and operating requirements.
decommissioning Nine Mile Point to a greenfield status However, we believe that we will be able to obtain (restoration of the site so that it substantially matches adequate quantities of gas to meet our requirements.
the natural state of the surrounding properties and the site's intended use). At December 31, 2002, the Nine Oil Mile Point trust fund was $405.7 million. Under normal burn practices, our requirements for residual fuel oil (No. 6) amount to approximately Coal 1,500,000 to 2,000,000 barrels of low-sulfur oil per We purchase the majority of our coal under supply year. Deliveries of residual fuel oil are made from the contracts with mining operators, and we acquire the suppliers' Baltimore Harbor marine terminal for remainder in the spot or forward coal markets. We distribution to the various generating plant locations.
believe that we will be able to renew supply contracts as Also, based on normal burn practices, we also require they expire or enter into contracts with other coal approximately 5,000,000 to 6,000,000 gallons of suppliers. Our primary coal burning facilities have the distillates (No. 2 oil and kerosene) annually, but these following requirements: requirements can vary substantially from year to year depending upon the relationship between energy prices Approximate and fuel costs, weather conditions, and operating Annual Coal Requirement Special Coal requirements. Distillates are purchased from the (tons) Restrictions suppliers' Baltimore truck terminals for distribution to Brandon Shores the various generating plant locations. We have Units I and 2 Sulfur content less contracts with various suppliers to purchase oil at spot (combined) ... 3,500,000 than 0.8% prices, and for future delivery, to meet our C. P. Crane requirements.
Units I and 2 Low ash melting (combined) ... 850,000 temperature Competition H. A. Wagner Market developments over the past several years have Units 2 and 3 Sulfur content no more changed the nature of competition in the merchant (combined) ... 1,100,000 than 1% energy business. Certain companies within the merchant energy sector have either curtailed their activities or Coal deliveries to these facilities are made by rail have withdrawn completely from the business. In an(d barge. The coal we use is produced from mines addition, other companies are entering the market (i.e.,
located in central and northern Appalachia. financial investors). We encounter competition from All of the Conemaugh and Keystone plants' annual companies of various sizes, having varying levels of coal requirements are purchased from regional suppliers experience, financial and human resources, and differing on the open market. The sulfur restrictions on coal are strategies.
approximately 2.5% for the Keystone plant and approximately 4.5% for the Conemaugh plant.
7
_ _ _ _ __ _ _ __ _ __ __ _ __ __ _ _ __ _ -_ _ _ _ _ _ _ _ _ _ _ _ _ _ L _.. ' I We face competition in the market for energy, competition that resulted from some of these initiatives capacity, and ancillary services. In our merchant energy in several states contributed in some instances to a business, we compete with international, national, and reduction in electricity prices and put pressure on regional full service energy providers, merchants and electric utilities to lower their costs, including the cost producers, to obtain competitively priced supplies from of purchased electricity. In addition, some states that a variety of sources and locations, and to utilize efficient were considering deregulation have slowed their plans or transmission or transportation. We principally compete postponed consideration of deregulation.
on the basis of the price, customer service, reliability, We believe there is adequate growth potential in and availability of our products. the current deregulated market. However, in response to With respect to power generation, we compete in regional market differences and to promote competitive the operation of energy-producing projects, and our markets, he Federal Energy Regulatory Commission competitors in this business are both domestic and (FERC) proposed initiatives promoting the formation of international organizations, many of whom have Regional Transmission Organizations and a standard extensive and diversified operating expertise including market design. If approved, these market changes could various utilities, industrial companies and independent provide additional opportunities for our merchant power producers (including affiliates of utilities), and energy business. Additionally, while competition has some of which have financial resources that are greater been adversely impacted by recent market events than ours. including the weakened financial condition of certain During the transition of the energy industry to energy companies, we expect our business to become competitive markets, it is difficult for us to assess our more competitive due to technological advances in position versus the position of existing power providers power generation, -commerce enabling new ways of and new entrants because each company may employ conducting business, the entrance of new ull service widely differing strategies in their fuel supply and power providers, and increased efficiency of energy markets.
sales contracts with regard to pricing, terms and However, we believe that our experience and conditions. Further difficulties in making competitive expertise in assessing and managing risk will help us to assessments of our company arise from states remain competitive during volatile or otherwise adverse considering different rypes of regulatory initiatives market circumstances.
concerning competition in the power industry. Increased Merchant Energy Operating Statistics 2002 2001 2000 1999 1998 Revenues (In millions)
PJM Plarform $1,391.4 $1,379.2 $ 731.7 $ - $ -
Plants with Power Purchase Agreements 456.4 70.8 - - -
Competitive Supply-Accrual Revenues 587.6 - - - -
-Mark-to-Market Revenues 238.1 175.8 151.5 147.7 47.5 Other 92.2 139.7 142.5 129.6 136.1 Total Revenue $2,765.7 $1,765.5 $1,025.7 $277.3 $183.6 Generation (In millioms-MWH 44.7 37.4 18.8 1.3 1.3 Operating statistics do not reflect the elimination of intercompany transactions.
8
Baltimore Gas and Electric Company
- BGE transferred, at book value, its nuclear BGE is an electric and gas public transmission and generating assets, its nuclear decommissioning distribution utility company with a service territory that trust fund, and related liabilities to Calvert covers the City of Baltimore and all or part of ten Cliffs Nuclear Power Plant, Inc. In addition, counties in central Maryland. BGE is regulated by the BGE transferred, at book value, its fossil Maryland PSC and FERC with respect to rates and generating assets and related liabilities and its other aspects of its business. partial ownership interest in two coal plants BGE's electric service territory includes an area of and a hydroelectric plant located in approximately 2,300 square miles. There are no Pennsylvania to Constellation Power Source municipal or cooperative wholesale customers within Generation.
BGE's service territory. BGE's gas service territory
- BGE assigned approximately $47 million to includes an area of approximately 800 square miles. Calvert Cliffs Nuclear Power Plant, Inc. and BGE's electric and gas revenues come from many $231 million to Constellation Power Source customers-residential, commercial, and industrial. In Generation of tax-exempt debt related to the 2002, BGE's largest electric customer provided transferred assets. At December 31, 2002, BGE approximately three percent of BGE's total electric remains contingently liable for the $269.8 revenues. In 2002, BGE's largest gas customer provided million outstanding balance of this debt.
approximately one percent of BGE's total gas revenues.
Standard Or Service Electric Business Our origination and risk management operation Electric Regulatory Matters and Competition provides BGE with 100% of the energy and capacity required to meet its standard offer service obligations Deregulation through June 30, 2003. Beginning July 1, 2003, this Effective July 1, 2000, electric cstomer choice and operation will provide 90% and Allegheny Energy competition among electric suppliers was implemented in Supply Company, LLC will provide the remaining 10%
Maryland. As a result of the deregulation of electric of the energy and capacity required for BGE to meet its generation, the following occurred effective July 1, 2000:
standard offer service obligations until June 30, 2006.
- All customers can choose their electric energy Beginning July 1, 2002, the fixed price standard supplier. BGE provides a fixed price standard offer service rate ended for large commercial and offer service over various time periods for industrial customers. As a result, customers representing different classes of customers that do not select approximately 96% (approximately 1,200 megawatts) of an alternative supplier until June 30, 2006.
load from this class purchase their electricity from an
- While BGE does not sell electric commodity to alternate supplier, including subsidiaries of Constellation all customers in its service territory, BGE does Energy. The remaining large commercial and industrial deliver electricity to all customers and provides customers that continue to receive their electric supply meter reading, billing, emergency response, from BGE are charged market rate standard offer regular maintenance, and balancing services.
service.
- BGE provides a market rate standard offer Beginning July 1, 2004, all other commercial and service for those commercial and industrial industrial customers that continue to receive their customers who are no longer eligible for fixed electric supply from BGE will be charged a market rate price standard offer service until June 30, 2006.
standard offer service. Currently, this class of customers
- BGE reduced residential base rates by represents approximately 2,200 megawatts of load.
approximately 6.5% on average, or about $54 Beginning July 1, 2006, BGE's current obligation to million a year, from rates prior to July 1, 2000.
provide fixed price standard offer service to residential These rates will not change before July 2006.
customers ends.
While total residential base rates remain BGE's (and other Maryland utilities') role in unchanged over this transition period (July 1, providing electricity supply to customers is currently the 2000 through June 30, 2006), the increase in subject of a proceeding at the Maryland PSC.
the standard offer service rate is offset by a Specifically, BGE entered into a proposed settlement corresponding decrease in the competitive agreement with parties representing customers, industry, transition charge (CTC) that BGE receives utilities, suppliers, the Maryland Energy Administration, from its cusromers.
the Maryland PSC's Staff, and the Office of People's
- Commercial and industrial customers have Counsel that extends BGE's obligation to supply several service options that will fix electric standard offer service.
energy rates through June 30, 2004 and transition charges through June 30, 2006.
9
li Under the proposed settlement agreement, BGE We refer to these programs as active load management would be obligated to provide market-based standard programs. These programs include:
offer service to residential customers until June 30,
- customer-owned generation and curtailable 2010, and for commercial and industrial customers for service for large commercial and industrial a one, two or four year period beyond June 30, 2004, customers, depending on customer size. The rates charged during
- air conditioning control for residential and this time would be fixed during the term of the supply commercial customers, and
- residential water heater control.
contract and would include an administrative fee. The BGE generally activates these programs on summer proposed settlement agreement currently is before the days when demand and/or wholesale prices are relatively Maryland PSC for approval. high. The reduction in the summer 2002 peak load We discuss the market risk of our regulated electric from active load management was approximately business in more detail in Item 7. Managements 260 MW.
Discussion and Analysis-Market Risk section.
Transmission and DistributionFacilities Competition BGE maintains approximately 250 substations and The electric transmission and distribution services are 1,300 circuit miles of transmission lines throughout facing competition from alternative energy sources that central Maryland. BGE also maintains nearly 22,500 include on-site generation and cogeneration projects. In circuit miles of distribution lines. The transmission facilities are connected to those of neighboring utility future years, emerging technologies, including fuel cells systems as part of the PJM Interconnection. Under the and solar panels, may also become a competitive factor. PJM Tariff and various agreements, BGE and other market participants can use regional transmission Electric Load Management facilities for energy, capacity and ancillary services BGE implemented various programs for use when transactions including emergency assistance.
system-operating conditions or market economics We discuss FERC's initiatives in implementing a indicate that a reduction in load would be beneficial. standard market design for wholesale electric markets in more detail in Item 7. Managements Discussion and Analysis-FERC Regulation section.
Electric Operating Statistics 2002 2001 2000(A) 1999(A) 1998(A)
Revenues (In millions)
Residential $ 946.6 $ 885.3 $ 922.6 $ 975.2 $ 948.6 Commercial 809.5 903.0 926.2 939.3 912.9 Industrial 169.6 218.1 203.6 204.3 211.5 System Sales 1,925.7 2,006.4 2,052.4 2,118.8 2,073.0 Interchange Sales - - 53.8 112.1 120.8 Other (B) 40.3 33.6 29.0 29.1 27.0 Total $1,966.0 $2,040.0 $2,135.2 $2,260.0 $2,220.8 Sales (In thousands)MWH Residential 12,652 11,714 11,675 11,349 10,965 Commercial 14,602 14,147 14,042 13,565 13,219 Industrial 4,475 4,445 4,476 4,350 4,583 System Sales 31,729 30,306 30,193 29,264 28,767 Customers (In thousands)
Residential 1,052.3 1,040.5 1,033.4 1,021.4 1,009.1 Commercial 110.8 110.9 108.9 107.7 106.5 Industrial 4.9 5.0 5.0 4.7 4.6 Total 1,168.0 1,156.4 1,147.3 1,133.8 1,120.2 (A) Operating statistics reflect the generation funaion as part of regulated electric operations hrough June 30, 2000.
(B) Primarily includes transmission service integration revenues, late payment charges, miscellaneous service fees, and tower leasing revenues.
Operating statistics do not ref!ect the elimination of intercompany transactions.
10
Gas Business Currently, no regulation exists for the wholesale price of Our current pipeline firm transportation natural gas as a commodity, and the regulation of entitlements to serve our firm loads are 284,053 interstate transmission at the federal level has been dekatherms (DTH) per day during the winter period reduced. All BGE gas customers have the option to and 259,053 DTH per day during the summer period.
purchase gas from other suppliers. BGE continues to Our current maximum storage entitlements are deliver gas to all customers within its service territory. 235,080 DTH per day. To supplement our gas supply This delivery service is regulated by the Maryland PSC. at times of heavy winter demands and to be available in BGE also provides these customers with meter temporary emergencies affecting gas supply, we have:
reading, billing, emergency response, regular
- a liquefied natural gas facility for the maintenance, and balancing services. liquefaction and storage of natural gas with a Delivery service customers may choose to purchase total storage capacity of 1,092,977 DTH and a gas from several different suppliers, including daily capacity of 311,500 DTH, and subsidiaries of Constellation Energy. The basis of
- a propane air facility with a mined cavern with competition for delivery service customers is primarily a total storage capacity equivalent to 564,200 commodity price. DTH and a daily capacity of 85,000 DTH.
Approximately 50% of the gas on our distribution We have under contract sufficient volumes of system is for customers using delivery service. We propane for the operation of the propane air facility and charge all our delivery service customers fees to recover are capable of liquefying sufficient volumes of natural the costs for the transportation service we provide. gas during the summer months for operations of our These fees are the same as the delivery charges to liquefied natural gas facility during winter emergencies.
customers that purchase gas from us. We historically have been able to arrange short-For customers that buy their gas from BGE, there term contracts or exchange agreements with other gas is a market-based rates incentive mechanism. Under companies in the event of short-term disruptions to gas market-based rates, our actual cost of gas is compared supplies.
to a market index (a measure of the market price of gas BGE also participates in the interstate markets by in a given period). The difference between our actual releasing pipeline capacity or bundling pipeline capacity cost and the market index is shared equally between with gas for off-system sales. Off-system gas sales are shareholders and customers. BGE must secure fixed- low-margin direct sales of gas to wholesale suppliers of price contracts for at least 10%, but not more than natural gas outside our service territory. Earnings from 20%, of forecasted system supply requirements for the these activities are shared between shareholders and November through March period. customers. We make these sales as part of a program to We purchase the natural gas we resell to customers balance our supply of, and cost of, natural gas.
directly from many producers and marketers. We have transportation and storage agreements that expire from 2004 to 2012.
11
Gas Operating Statistics 2002 2001 2000 1999 1998 Revenues (In millions)
Residential Excluding Delivery Service $ 342.1 $ 378.4 $ 328.4 $ 298.1 $ 279.2 Delivery Service 16.5. 16.3 23.5 11.5 4.9 Commercial Excluding Delivery Service 89.4 115.5 97.9 79.3 75.6 Delivery Service 29.2 21.4 25.8 24.4 19.4 Industrial Excluding Delivery Service 9.3 12.8 10.9 8.2 8.0 Delivery Service 13.9 13.8 16.3 16.1 16.0 System Sales 500.4 558.2 502.8 437.6 403.1 Off-system Sales 74.8 113.6 101.0 42.9 40.9 Other 6.1 8.9 7.8 7.6 7.1 Total $ 581.3 $ 680.7 $ 611.6 $ 488.1 $ 451.1 Sales (In thousands)-DTH Residential Excluding Delivery Service 35,364 33,147 34,561 34,272 33,595 Delivery Service 6,404 7,201 9,209 4,468 1,890 Commercial Excluding Delivery Service 11,583 12,334 13,186 11,733 11,775 Delivery Service 28,429 25,037 22,921 20,288 16,633 Industrial Excluding Delivery Service 1,207 1,386 1,386 1,367 1,412 Delivery Service 23,689 23,872 32,382 33,118 34,798 System Sales 106,676 102,977 113,645 105,246 100,103 Off-system Sales 18,551 20,012 22,456 15,543 16,724 Total 125,227 122,989 136,101 120,789 116,827 Customers (In thousands)
Residential 567.3 558.7 553.7 543.5 532.5 Commercial 40.7 40.2 40.1 39.9 39.6 Industrial 1.3 1.4 1.4 1.3 1.3 Total 609.3 600.3 595.2 584.7 573.4 Operating statistics do not reflect the elimination of intercompany transactions.
12 I I
Franchises BGE has nonexclusive electric and gas franchises to use sufficient to permit us to engage in our present streets and other highways that are adequate and business. Conditions of the franchises are satisfactory.
Other Nonregulated Businesses Energy Products and Services District Cooling Services We offer energy products and services designed We also provide cooling services using a central chilled primarily to provide solutions to the energy. needs of water distribution system to commercial customers in commercial and industrial customers. These energy the City of Baltimore.
products and services indude:
- designing, constructing, and operating single- Other site heating, cooling, and cogeneration facilities, Our other nonregulated businesses include investments
- energy consulting and power-quality services, that we do not consider to be core operations. These
- services to enhance the reliability of individual include financial investments, real estate projects, and electric supply systems, and interests in a Latin American distribution project and in
- customized financing alternatives. a fund that holds interests in two South American energy projects. In 2001, as part of our strategy to Home Products and Electric and focus attention and capital resources on our core energy Gas Retall Marketing businesses, we accelerated our exit strategies for our We offer services to customers including: remaining real estate projects and international
- home improvements, investments.
- the service of heating, air conditioning, plumbing, electrical, and indoor air quality systems, and
- electric and natural gas retail marketing.
Consolidated Capital Requirements Our business requires a great deal of capital. Our total We continuously review and change our capital capital requirements for 2002 were $923 million. Of expenditure programs, so actual expenditures may vary this amount, $706 million was used in our from the estimates above. We discuss our capital nonregulated businesses and $217 million was used in requirements further in Item 7. Managements Discussion our utility operations. We estimate our total capital and Analysis-CapitalResources section.
requirements to be $735 million in 2003.
Environmental Matters We are subject to regulation by various federal, state, Our activities require complex and often lengthy and local authorities with regard to: processes to obtain approvals, permits, or licenses for
- air quality, new, existing, or modified facilities. Additionally, the
- water quality, and use and handling of various chemicals or hazardous
- disposal of hazardous substances. materials (including wastes) requires preparation of The development (involving site selection, release prevention plans and emergency response environmental assessments, and permitting), procedures. We continuously monitor federal and state construction, acquisition, and operation of electric environmental initiatives in order to provide input as generating and distribution facilities are subject to well as to maintain a proactive view of the future which extensive federal, state, and local environmental and is key to effective strategic planning. Additionally, as land use laws and regulations. From the beginning new laws or regulations are promulgated, we assess their phases of siting and developing, to the ongoing applicability and implement the necessary modifications operation of existing or new electric generating and to our facilities or their operation, as required.
distribution facilities, our activities involve compliance Our capital expenditures (excluding allowance for with diverse laws and regulations that address emissions funds used during construction) were approximately and impacts to air and water, special, protected and $265 million during the five-year period 1998-2002 to cultural resources (such as wetlands, endangered species, comply with existing environmental standards and and archeological/historical resources), chemical, and regulations, and we estimate that the future incremental waste handling and noise impacts. capital expenditures necessary to comply with existing environmental standards and regulations will be approximately $20 million in 2003.
13
Clean Air Act The EPA and several states have filed suits against The Clean Air Act affects both existing generating a number of coal-fired power plants in Mid-Western facilities and new projects. The Clean Air Act and and Southern states alleging violations of the many state laws require significant reductions in S02 deterioration prevention and non-attainment provisions (sulfur dioxide) and NOx (nitrogen oxide) emissions of the Clean Air Act's new source review requirements.
that result from burning fossil fuels. The Clean Air Act In 2000, and again in 2002, using its broad also contains other provisions that could materially investigatory powers, the EPA requested information affect some of our projects. Various provisions may relating to modifications made to our Brandon Shores, require permits, inspections, or installation of additional Crane, and Wagner plants in Baltimore, Maryland. The pollution control technology or may require the EPA also sent similar, but narrower, information purchase of emission allowances. Certain of these requests to two of our newer Pennsylvania waste-coal provisions are described in more detail below. burning plants. This information is to determine On October 27, 1998, the Environmental compliance with the Clean Air Act and state Protection Agency (EPA) issued a rule requiring 22 implementation plan requirements, including potential Eastern states and the District of Columbia to reduce application of federal New Source Performance emissions of NOx (a precursor of ozone). Among other Standards. We have responded to the EPA and as of the things, the EPXs rule establishes an ozone season, which date of this report the EPA has taken no further action.
runs from May through September, and a NOX In general, such standards can require the emission budget for each state, including Maryland and installation of additional air pollution control Pennsylvania. The EPA rule requires states to equipment upon the major modification of an existing implement controls sufficient to meet their NOX budget plant. Although there have not been any new source by May 30, 2004. Coal-fired power plants are a review-related suits filed against our facilities, there can principal target of NOx reductions under this initiarive. be no assurance that any of them will not be the target Many of our generation facilities are subject to of an action in the future. Based on the levels of NOx reduction requirements under the EPA rule, emissions control that the EPA and states are seeking in including those located in Maryland and Pennsylvania. these new source review enforcement actions, we believe At the Brandon Shores and Wagner facilities, we that material additional costs and penalties could be installed emission reduction equipment to meet incurred, and planned capital expenditures could be Maryland regulations issued pursuant to EPA's rule. The accelerated, if the EPA was successful in any future owners of the Keystone plant in Pennsylvania are actions regarding our facilities.
installing emissions reduction equipment by July 2003 The Clean Air Act requires the EPA to evaluate to meet Pennsylvania regulations issued pursuant to the public health impacts of emissions of mercury, a EPAs rule. We estimate our costs for the equipment hazardous air pollutant, from coal-fired plants. The EPA needed at this plant will be approximately $35 million. has decided to control mercury emissions from coal-Through December 31, 2002, we have spent fired plants. Compliance could be required by approximately $26 million. approximately 2007. We believe final regulations could The EPA established new National Ambient Air be issued in 2004 and would affect all coal-fired boilers.
Quality Standards for very fine parriculates and revised The cost of compliance with the final regulations could standards for ozone attainment that were upheld after be material.
various court appeals. While these standards may Future initiatives regarding greenhouse gas require increased controls at some of our fossil emissions and global warming continue to be the generating plants in the future, implementation could subject of much debate. The related Kyoto Protocol was be delayed for several years. We cannot estimate the signed by the United States but has since been rejected cost of these increased controls at this time because the by the President, who instead has asked for an 18%
states, including Maryland, Pennsylvania, and decrease in carbon intensity on a voluntary basis. Future California, still need to determine what reductions in initiatives on this issue and the ultimate effects of the pollutants will be necessary to meet the EPA standards. Kyoto Protocol and the President's initiatives on us are unknown at this time. As a result of our diverse fuel portfolio, our contribution to greenhouse gases varies by plant type. Fossil fuel-fired power plants are significant sources of carbon dioxide emissions, a principal greenhouse gas. Our compliance costs with any mandated federal greenhouse gas reductions in the future could be material.
14
Clean Water Act cleanup of the site. BGE, along with the other PRPs, Our facilities are subject to a variety of federal and state submitted a remedial investigation and feasibility study regulations governing existing and potential water/ to the EPA on October 14, 1994, and the EPA issued wastewater and stormwater discharges. its Record of Decision on December 31, 1997. On In April 2002, the EPA proposed rules under the June 26, 1998, the EPA ordered BGE, the other utility Clean Water Act that require that cooling water intake PRPs, and the owner/operator to implement the structures reflect the best technology available for requirements of the Record of Decision. The utility minimizing adverse environmental impacts. These rules PRPs have submitted the remedial design to EPA. Based pertain to existing utilities and non-utility power on the Record of Decision, BGE's share of the producers that currently employ a cooling water intake reasonably possible cleanup costs, estimated to be structure and whose flow exceeds 50 million gallons per approximately 15.47%, could be as much as $1.3 day. We expect a final action on the proposed rules by million higher than amounts we believe are probable February 2004. The proposed rule may require the and have recorded as a liability in our Consolidated installation of additional intake screens or other Balance Sheers. There has been no significant activity protective measures, as well as extensive site specific with respect to this site since the EPA's Record of study and monitoring requirements. There is also the Decision in 1997.
possibility that the proposed rules may lead to the installation of cooling towers on four of our fossil and Kane and Lombard Streets both of our nuclear facilities. Our compliance costs Suit was originally filed by the EPA under CERCLA in associated with the final rules could be material. October 1989 against BGE and several other defendants Under current provisions of the Clean Water Act, in the U.S. District Court for the District of Maryland, existing permits must be renewed at least every five seeking to recover past and future clean up costs at the years, at which time permit limits come under extensive Kane and Lombard Street site located in Baltimore City, review and can be modified to account for more Maryland. The State of Maryland filed a similar stringent regulations. In addition, the permits can be complaint in the same case and court in February 1990.
modified at any time. Changes to the environmental The complaints alleged that BGE arranged for coal fly permits of our coal or other fuel suppliers due to ash to be deposited on the site. The Court dismissed federal or state initiatives may increase the cost of fuel, these complaints in November 1995. Maryland began which in turn could have a significant impact on our additional investigation on the remainder of the site for operations. the EPA, but never completed the investigation. BGE, along with three other defendants, agreed to complete a Comprehensive Environmental Response, remedial investigation and feasibility study of Compensation and Liability Act groundwater contamination around the site in a July (Superfund statutel 1993 consent order. The remedial investigation report This law, or CERCLA, among other things, imposes and a draft feasibility study were submitted to the EPA cleanup requirements for threatened or actual releases of in February 2002. In December 2002, the EPA released hazardous substances that may endanger public health its proposed remedy for the site and estimated the total or welfare of the environment. Under CERCLA, joint cost for the site to be $6.2 million. Until the EPA and several liability may be imposed on waste finalizes the plan, we cannot estimate BGE's share of generators, site owners and operators and others the total site cleanup costs, but it is not expected to be regardless of fault or the legality of the original disposal material.
activity. Many states have implemented laws similar to CERCLA. Although all waste substances generated by 68th Street Dump our facilities are generally not regarded as hazardous In July 1999, the EPA notified BGE, along with 19 substances, some products used in the operations and other entities, that it may be a potentially responsible the disposal of such products are governed by CERCLA party at the 68"' Street Dump/industrial Enterprises and similar state statutes.
Site, also known as the Robb Tyler Dump, located in Baltimore, Maryland. The EPA indicated that it is Metal Bank proceeding with plans to conduct a remedial In the early 1970s, BGE shipped an unknown number investigation and feasibility study. This site was of scrapped transformers to Metal Bank of America, a proposed for listing as a federal Superfund site in metal reclaimer in Philadelphia. Metal Bank's scrap and January 1999, but the listing has not been finalized.
storage yard has been found to be contaminated with Although our potential liability cannot be estimated, we oil containing high levels of PCBs (hazardous chemicals do not expect such liability to be material based on frequently used as a fire resistant coolant in electrical BGE records showing that it did not send waste to the equipment). On December 7, 1987, the EPA notified site.
BGE and nine other utilities that they are considered potentially responsible parties (PRPs) with respect to the 15
Spring Garde incurred at this site. Because of the results of studies at In the past, predecessor gas companies (which were later this site, it is reasonably possible that these additional merged into BGE) manufactured coal gas for residential costs could exceed the $47 million BGE recognized by and industrial use. The Spring Gardens site was once approximately $14 million.
used to manufacture gas from coal and oil. The residue As a result of CERCLA's no-fault, retroactive from this manufacturing process was coal tar, previously liability provisions, we cannot determine whether we thought to be harmless but now found to contain a will be free from substantial liabilities for other sites in number of chemicals designated by the EPA as the future.
hazardous substances.
In late December 1996, BGE signed a consent Employees order with the Maryland Department of the Constellation Energy and its subsidiaries had, at Environment that required it to implement remedial December 31, 2002, approximately 8,700 employees.
action plans for contamination at and around the The Central Wayne plant has a partially unionized Spring Gardens site, located in Baltimore, Maryland. workforce where approximately 30 employees are BGE submitted the required remedial action plans, and represented by the International Union of Operating they have been approved by the Maryland Department Engineers. The labor contract with this union expires of the Environment. Based on these plans, the costs June 30, 2004. At the Nine Mile Point plant, BGE considers to be probable to remedy the approximately 700 employees are represented by the contamination are estimated to total $47 million. BGE International Brotherhood of Electrical Workers, Local recorded these costs as a liability in its Consolidated 97. The labor contract with this union expires in July Balance Sheets and deferred these costs, net of 2006 with wages open to negotiation in June 2003. We accumulated amortization and amounts it recovered believe that our relations with both unions are from insurance companies, as a regulatory asset. satisfactory, bur there can be no assurances that this will Through December 31, 2002, BGE spent continue to be the case.
approximately $39 million for remediation at this site. We discuss several workforce reduction programs in BGE also is required by accounting rules to Item 7. Managenents Discussion and Analysis-disclose additional costs it considers to be less likely Significant Events section.
than probable, but still "reasonably possible" of being Item 2. Properties Constellation Energy's corporate offices occupy BGE has electric transmission and electric and gas approximately 85,000 square feet of leased office space distribution lines located:
in Baltimore, Maryland. The corporate offices for most
- in public streets and highways pursuant to of our merchant energy business occupy approximately franchises, and 100,000 square feet of leased office space in another
- on rights-of-way secured for the most part by building in Baltimore, Maryland. We describe our grants from owners of the property.
electric generation properties on the next page. We also All of BGE's property is subject to the lien of have leases for other offices and services located in the BGE's mortgage securing its mortgage bonds. All of the Baltimore metropolitan region, and for various real generation facilities transferred to affiliates by BGE on property and facilities relating to our generation July 1, 2000, along with the stock we own in certain of projects. our subsidiaries, are subject to the lien of BGE's We own BGE's principal headquarters building in mortgage.
downtown Baltimore. BGE owns propane air and We believe we have satisfactory title to our power liquefied natural gas facilities as discussed in Item 1. project facilities in accordance with standards generally Business-Gas Business section. accepted in the energy industry, subject to exceptions, BGE also has rights-of-way to maintain 26-inch which in our opinion, would not have a material natural gas mains across certain Baltimore City-owned adverse effect on the use or value of the facilities.
property (principally parks) which expire in 2004. We also maintain office space throughout North These rights-of-way can be renewed during their last America to support our competitive supply activities.
year for an additional period of 25 years based on a fair revaluation. Conditions of the grants are satisfactory.
16 I I
The following table describes out generating facilities:
Installed % Capacity Primary Plant Location Capacity (MW) Owned Owned (MW) Fuel (at December 31, 2002) (at December 31, 2002)
PIM Platform Calvert Cliffs Calvert Co., MD 1,685 100.0 1,685 Nuclear Brandon Shores Anne Atundel Co., MD 1,286 100.0 1,286 Coal H. A. Wagner Anne Arundel Co., MD 1,020 100.0 1,020 Coal/Oil/Gas C. P. Crane Baltimore Co., MD 399 100.0 399 Oil/Coal Keystone Armstrong and Indiana Cos., PA0. 1,711 21.0 359 (A) Coal Conemaugh Indiana Co., PA 1,711 10.6 181 (A) Coal Perryman Harford Co., MD 360 100.0 360 Oil/Gas Riverside Baltimore Co., MD 251 100.0 251 Oil/Gas Handsome Lake Rockland Twp, PA 250 100.0 250 Gas Notch Cliff Baltimore Co., MD 128 100.0 128 Gas Westport Baltimore City, MD 121 100.0 121 Gas Gould Street Baltimore City, MD 104 100.0 104 Oil/Gas Philadelphia Road Baltimore City, MD 64 100.0 64 Oil Safe Harbor Safe Harbor, PA 416 66.7 277 Hydro Total PJM Platforrm 9,506 6,485 Plants with Power Purchase Agreements Nine Mile Point Unit I Scriba, NY 609 100.0 609 Nuclear Nine Mile Point Unit 2 Scriba, NY 1,148 82.0 941 Nuclear Oleander Brevard Co., FL 680 100.0 680 Oil/Gas University Park Chicago, IL 300 100.0 300 Gas Total Plants with Power Purchase Agreements 2,737 2,530 Competitive Supply Rio Nogales Seguin, TX 800 100.0 800 Gas Other Holland Energy Shelby Co., IL 665 100.0 665 Gas Big Sandy Neal, WV 300 100.0 300 Gas
'olf Hills Bristol, VA 250 100.0 250 Gas Panther Creek Nesquehoning, PA 83 50.0 42 Waste Coal Colver Colver Township, PA 110 25.0 28 Waste Coal Sunnyside Sunnyside, UT 53 50.0 26 WVasteCoal ACE Trona, CA 102 30.3 31 Coal Jasmin Kern Co., CA 33 50.0 17 Coal POSO Kern Co., CA 33 50.0 17 Coal Puna I Hilo, Hi 30 50.0 15 Geothermal Mammoth Lakes G-1 Mammoth Lakes, CA 8 50.0 4 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 3 50.0 2 Geothermal Soda Lake 11 Fallon, NV 13 50.0 7 Geothermal Stillwater Fallon, NV 13 50.0 6 Geothermal Rocklin Placer Co., CA 24 50.0 12 Biomass Fresno Fresno, CA 24 50.0 12 Biomass Chinese Station Sonora, CA 22 45.0 10 Biomass Malacha Muck Valley, CA 32 50.0 16 Hydro Central Wayne
Dearborn,
Ml 22 50.0 II Municipal Solid Waste SEGS IV Kramer Junction, CA 30 12.0 4 Solar SEGS V Kramer Junction, CA 30 4.O I Solar SEGS VI Kramer Junction, CA 30 9.0 3 Solar Total Other 1,934 1,491 Total Generating Facilities 14,977 11,306 (A) Reflects our proportionate interest in and entitlement to capacity from Keystone and Conemaugh, which include 2 megawatts of diesel capacity for Keystone and I megawatt of diesel capacity for Conemaugh.
17
The following table describes our processing facilities:
Installed % Capacity Primary Plant Location Capacity (MW) Owned Owned (MW) Fuel (at December 31, 2002) (at December 31, 2002)
A/C Fuels Hazelton, PA 50.0 Coal Processing Gary PCI Gary, IN 24.5 Coal Processing PC Synfuel VA I Appalachia, VA 16.7 Synfuel Processing PC Synfuel WV I Charleston, WV 16.7 Synfuel Processing PC Synfuel WV II Wheelersburg, OH 16.7 Synfuel Processing PC Synfuel WV III Mayberry, WV 16.7 Synfuel Processing Item 3. Legal Proceedings We discuss our legal proceedings in Item 7. ManagementŽ Discussion and Analysis-Business Environment seccion and in Note 11 to Consolidated FinancialStatements.
Item 4. Submisslon of Matters to Vote of Security Holders Not applicable.
Executive Officers of the Registrant Other Offices or Positions Held Name Age Present Office Daring Past Five Years Mayo A. Shattuck III 48 Chairman of the Board of Constellation Co-Chairman and Co-Chief Executive Energy (since July 2002), President Officer-DB Alex Brown, LLC and and Chief Executive Officer of Deutsche Banc Securities, Inc., Vice Constellation Energy (since November Chairman-Bankers Trust 2001); and Chairman of the Board of Corporation.
BGE (since July 2002)
E. Follin Smith 43 Senior Vice President and Chief Senior Vice President and Chief Financial Officer of Constellation Financial Officer-Armstrong Energy (since June 2001) and Senior Holdings, Inc.; Vice President and Vice President and Chief Financial Treasurer-Armstrong Holdings, Inc.
Officer of Baltimore Gas and Electric (filed for bankruptcy under Chapter Company (since January 2002) 11 on December 6, 2000); and Chief Financial Officer-General Motors-Delphi Chassis Systems.
Thomas V Brooks 40 President of Constellation Power Source, Vice President of Business Development Inc. (since October 2001) and Strategy-Constellation Energy; and Vice President-Goldman Sachs.
Frank 0. Heintz 59 President and Chief Executive Officer of Executive Vice President, Utility Baltimore Gas and Electric Company Operations-BGE; and Vice (since July 2000) President, Gas-BGE.
Michael J. Wallace 55 President of Constellation Generation Managing Director and Member-Group, LLC (since January 2002) Barrington Energy Partners; and Senior Vice President-Commonwealth Edison.
Thomas F. Brady 53 Senior Vice President, Corporate Vice President, Corporate Strategy and Strategy and Development of Development-Constellation Energy; Constellation Energy (since May Vice President, Retail Services-BGE; 2002) and Vice President, Customer Service and Distribution-BGE.
18
Other Offices or Positions Held Name Age Present Office During Past Five Years Paul . Allen 51 Vice President, Corporate Affairs of Senior Vice President and Group Constellation Energy (since May Head-Ogilvy Public Relations.
2001)
Kathleen A. Chagnon 43 Vice President, General Counsel, and Vice President, Corporate Group Secretary of Constellation Energy General Counsel-The St. Paul (since August 2002) Companies, Inc.; and Assistant Vice President and Associate Group Counsel-USF&G Corporation.
John R. Collins 45 Vice President and Chief Risk Officer of Managing Director-Finance-Constellation Energy (since December Constellation Power Source Holdings, 2001) Inc.; and Senior Financial Officer-Constellation Power Source. Inc.
Mark P. Huston 39 Vice President, Corporate Strategy and Manager, Corporate Strategy &
Development of Constellation Energy Development-Constellation Energy; (since May 2002) Project Manager, Restructuring Project-BGE; and Director, Gas Business Development-BGE.
Marc C. Ugol 44 Vice President, Human Resources of Senior Vice President, Human Resources Constellation Energy (since October and Administration-Tellabs, Inc.;
2002) and Senior Vice President, Human Resources-Platinum Technology International.
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.
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PART II Item 5. Market for Registrant's Common Equity and Related Shareholder Matters Stock Trading In January 2003, we announced an increase in our Constellation Energy's common stock is traded under quarterly dividend from 24 cents to 26 cents per share the ticker symbol CEG. It is listed on the New York, on our common stock payable April 1, 2003 to holders Chicago, and Pacific stock exchanges. It has unlisted of record on March 10, 2003. This is equivalent to an trading privileges on the Boston, Cincinnati, and annual rate of $1.04 per share.
Philadelphia exchanges. Quarterly dividends were declared on our common As of February 28, 2003, there were 50,914 stock during 2002 and 2001 in the amounts set forth common shareholders of record. 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. 7.16% Deferrable Interest Subordinated Dividends have been paid continuously since 1910 Debentures due June 30, 2038, and any on the common stock of Constellation Energy, BGE, deferred interest remains unpaid; or and their predecessors. Future dividends depend upon
- all dividends (and any redemption payments) future earnings, our financial condition, and other due on BGE's preference stock have not been factors. paid.
Common Stock Dividends and Price Ranges 2002 2001 Price*
Di,vidend Price* Dividend Dc ecared High Low Dedared High Low First Quarter .................................... $.24 $31.18 $26.16 $ .12 $44.65 $34.69 Second Quartet................................ .24 32.38 27.65 .12 50.14 40.10 Third Quarter................................... .24 29.85 21.51 .12 43.80 22.85 Fourth Quarter.................................. .24 29.02 19.30 .12 28.21 20.90 Total ........................................... $.96 $ .48
- Based on New York Stock Exchange Composite Transactions.
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Item 6. Selected Financial Data Constellation Energy Group, Inc. and Subsidiaries 2002 2001 2000 1999 1998 (Dollar amounts in millions, except per share amounts)
Summary of Operations Total Revenues $ 4,703.0 $ 3,878.8 $ 3,774.4 $3,830.9 $3,382.5 Total Expenses 3,878.1 3,527.2 3,009.9 3,081.0 2,647.9 Net Gain on Sales of Investments and Other Assets 261.3 6.2 78.1 10.0 3.9 Income From Operations 1,086.2 357.8 842.6 759.9 738.5 Other Income 30.5 1.3 4.2 7.9 5.7 Fixed Charges 281.5 238.8 271.4 255.0 260.6 Income Before Income Taxes 835.2 120.3 575.4 512.8 483.6 Income Taxes 309.6 37.9 230.1 186.4 177.7 Income Before Extraordinary Item and Cumulative Effect of Change in Accounting Principle 525.6 82.4 345.3 326.4 305.9 Extraordinary Loss, Net of Income Taxes - - - (66.3) -
Cumulative Effect of Change in Accounting Principle, Net of Income Taxes - 8.5 - -
Net Income $ 525.6 $ 90.9 $ 345.3 $ 260.1 $ 305.9 Earnings Per Common Share and Earnings Per Common Share-Assuming Dilution Before Extraordinary Item and Cumulative Effect of Change in Accounting Principle $ 3.20 $ .52 $ 2.30 S 2.18 $ 2.06 Extraordinary Loss - - - (.44) -
Cumulative Effect of Change in Accounting Principle - .05 - - -
Earnings Per Common Share and Earnings Per Common Share-Assuming Dilution $ 3.20 $ .57 $ 2.30 $ 1.74 $ 2.06 Dividends Declared Per Common Share $ .96 $ .48 $ 1.68 $ 1.68 $ 1.67 Summary of Financial Condition Total Assets $ 14,128.9 $14,109.4 $12,939.3 $9,745.1 $9,434.1 Short-Term Borrowings $ 10.5 $ 975.0 $ 243.6 $ 371.5 $ -
Current Portion of Long-Term Debt $ 426.2 $ 1,406.7 $ 906.6 $ 808.3 $ 541.7 Capitalization Long-Term Debt $ 4,613.9 $ 2,712.5 $ 3,159.3 $2,575.4 $3,128.1 Minority Interests 105.3 101.7 97.7 95.2 2.0 Preference Stock Not Subject to Mandatory Redemption 190.0 190.0 190.0 190.0 190.0 Common Shareholders' Equity 3,862.3 3,843.6 3,174.0 3,017.5 2,995.9 Total Capitalization $ 8,771.5 $ 6,847.8 $ 6,621.0 $5,878.1 $6,316.0 Financial Statistics at Year End Ratio of Earnings to Fixed Charges 3.33 1.18 2.78 2.87 2.60 Book Value Per Share of Common Stock $ 23.44 $ 23.48 $ 21.09 $ 20.17 $ 20.08 Certain prior-year amounts have been rclassified to conform with the current years presentation.
We discuss items that affect comparability between years, including acquisitions, accounting changes, and special items, in Item 7. Management Discussion and Analysis.
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ffi--, -~ -1I I Baltimore Gas and Electric Company and Subsidiaries 2002 2001 2000(A) 1999 1998 (Dollar amounts in millions)
Summary of Operations Total Revenues $ 2,547.3 $2,720.7 $2,746.8 $3,092.2 $3,386.4 Total Expenses 2,181.0 2,408.9 2,334.4 2,387.9 2,647.9 Income From Operations 366.3 311.8 412.4 704.3 738.5 Other Income 10.7 0.4 7.5 8.4 5.7 Fixed Charges 140.6 154.6 184.0 205.9 238.8 Income Before Income Taxes 236.4 157.6 235.9 506.8 505.4 Income Taxes 93.3 60.3 92.4 178.4 177.7 Income Before Extraordinary Item 143.1 97.3 143.5 328.4 327.7 Extraordinary Loss, Net of Income Taxes - - - (66.3) -
Net Income 143.1 97.3 143.5 262.1 327.7 Preference Stock Dividends 13.2 13.2 13.2 13.5 21.8 Earnings Applicable to Common Stock $ 129.9 $ 84.1 $ 130.3 $ 248.6 $ 305.9 Summary of Financial Condition Total Assets $ 4,779.9 $4,954.5 $4,654.2 $7,272.6 $9,434.1 Short-Term Borrowings $ - $ - $ 32.1 $ 129.0 $ -
Current Portion of Long-Term Debt $ 420.7 $ 666.3 $ 567.6 $ 523.9 $ 541.7 Capitalization Long-Term Debt $ 1,499.1 $1,821.7 $1,864.4 $2,206.0 $3,128.1 Minority Interest 19.4 5.0 4.6 4.2 1.1 Preference Stock Not Subject to Mandatory Redemption 190.0 190.0 190.0 190.0 190.0 Common Shareholder's Equity 1,461.7 1,131.4 802.3 2,355.4 2,981.5 Total Capitalization $ 3,170.2 $3,148.1 $2,861.3 $4,755.6 $6,300.7 Financial Statistics at Year End Ratio of Earnings to Fixed Charges 2.66 1.99 2.27 3.45 2.94 Ratio of Earnings to Fixed Charges and Preferred and Preference Stock Dividends 2.31 1.75 2.03 3.14 2.60 Certain prior-year amounts have been reclassifiedto conform with the currentyears presentation.
(A) In July 2000, BGE transferred its generation assets, net of associated liabilities, to our merchant energy business as a result of the deregulation of electric generation.
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Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations Introduction As you read this discussion and analysis, refer to our Constellation Energy Group, Inc. (Constellation Energy) is a Consolidated Statements of Income, which present the results of North American energy company that conducts its business our operations for 2002, 2001, and 2000. We analyze and through various subsidiaries including a merchant energy explain the differences between periods in the specific line items business and Baltimore Gas and Electric Company (BGE). We of the Consolidated Statements of Income.
describe our operating segments in Note 3. Effective July 1, 2000, electric generation was deregulated This report is a combined report of Constellation Energy in Maryland and BGE transferred all of its generation assets and and BGE. References in this report to "we" and "our" are to related liabilities at book value to our merchant energy business.
Constellation Energy and its subsidiaries, collectively. References As a result, the financial results of the electric generation portion in this report to the "utility business" are to BGE. of our business are included in the merchant energy business Our merchant energy business is a competitive provider of beginning July 1, 2000. Prior to July 1, 2000, the financial energy solutions for large customers in North America. It has results of electric generation were included in BGE's regulated electric generation assets located in various regions of the United electric business. We discuss the deregulation of electric States and provides energy solutions to meet customers' needs. generation in the Electric Competition-Marylandsection.
Our merchant energy business focuses on serving the full energy and capacity requirements (load-serving activities) of, and Critical Accounting Policies providing other risk management activities for various customers, Our discussion and analysis of financial condition and results of such as utilities, municipalities, cooperatives, retail aggregators, operations are based on our consolidated financial statements and large commercial and industrial customers. These load- that were prepared in accordance with accounting principles serving activities typically occur in regional markets in which generally accepted in the United States of America. Management end use customer electricity rates have been deregulated and makes estimates and assumptions when preparing financial thereby separated from the cost of generation supply. statements. These estimates and assumptions affect various BGE is a regulated electric and gas public transmission and matters, including:
distribution utility company with a service territory that covers
- our reported amounts of assets and liabilities in our the City of Baltimore and all or part of ten counties in central Consolidated Balance Sheets at the dates of the financial Maryland. statements, Our other nonregulated businesses:
- our disclosure of contingent assets and liabilities at the
- design, construct, and operate single-site heating, dates of the financial statements, and cooling, and cogeneration facilities for commercial and
- our reported amounts of revenues and expenses in our industrial customers, Consolidated Statements of Income during the reporting
- provide home improvements, service heating, air periods.
conditioning, plumbing, electrical, and indoor air These estimates involve judgments with respect to quality systems, and provide electric and natural gas numerous factors that are difficult to predict and are beyond retail marketing, and management's control. As a result, actual amounts could
- own and operate a district cooling system for materially differ from these estimates.
commercial customers in the City of Baltimore, Management believes the following accounting policies Maryland. represent critical accounting policies as defined by the SEC. The In addition, we own several investments that we do not SEC defines critical accounting policies as those that are both consider to be core operations. These include financial most important to the portrayal of a company's financial investments, real estate projects, and interests in a Latin condition and results and require management's most difficult, American distribution project and in a fund that holds interests subjective, or complex judgment, often as a result of the need to in two South American energy projects. We sold certain non- make estimates about the effect of matters that are inherently core assets in 2002 and closed our retail merchandise stores in uncertain and may change in subsequent periods. We discuss our December 2002. significant accounting policies, including those that do not In this discussion and analysis, we explain the general require management to make difficult, subjective, or complex financial condition and the results of operations for judgments or estimates, in Note 1.
Constellation Energy and BGE including:
- factors which affect our businesses, Revenue RecognltonlMark-to-Market Method of
- our earnings and costs in the periods presented, AccountUng
- changes in earnings and costs between periods, Our merchant energy business engages in origination and risk
- sources of earnings, management activities using contracts for energy, other energy-
- impact of these factors on our overall financial related commodities, and related derivative contracts. We record condition, merchant energy business revenues using two methods of
- expected future expenditures for capital projects, and accounting: accrual accounting and mark-to-market accounting.
- expected sources of cash for future capital expenditures. We describe our use of accrual accounting in more detail in Note 1.
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~~~~~_
_ L ,,- x ---
lt 6 On October 25, 2002, the Emerging Issues Task Force resulting in no gain or loss at inception. The level of (EITF) reached a consensus on Issue 02-3, Recognition and total close-out reserves increases as we have larger Reporting of Gains and Losses on Energy Trading Contracts Under unhedged positions, bid-offer spreads increase, or market EITF Issues No. 98-10 and No. 00-17 EITF 02-3 affects how we information is not available, and it decreases as we apply the mark-to-market method of accounting. We describe reduce our unhedged positions, bid-offer spreads our accounting for energy contracts and the impact of decrease, or market information becomes available.
EITF 02-3 below.
- Credit-spread adjustment-for risk management We use mark-to-market accounting for energy trading purposes, we compute the value of our mark-to-market activities and for derivatives and other contracts for which we assets and liabilities using a risk-free discount rate. In are not permitted to use accrual accounting or hedge accounting. order to compute fair value for financial reporting These mark-to-market activities include derivative and (prior to purposes, we adjust the value of our mark-to-market EITF 02-3) non-derivative contracts for energy and other assets to reflect the credit-worthiness of each individual energy-related commodities. Under the mark-to-market method counterparty based upon published credit ratings, where of accounting, we record the fair value of energy contracts as available, or equivalent internal credit ratings and mark-to-market energy assets and liabilities at the time of associated default probability percentages. We compute contract execution. We record the changes in mark-to-market this reserve by applying the appropriate default energy assets and liabilities on a net basis in "Nonregulated probability percentage to our outstanding credit revenues" in our Consolidated Statements of Income. exposure, net of collateral, for each counterparty. The At December 31, 2002, mark-to-market energy assets and level of this reserve increases as our credit exposure to liabilities consisted of a combination of energy and energy- counterparties increases, the maturity terms of our related derivative and non-derivative contracts. While some of transactions increase, or the credit ratings of our these contracts represent commodities or instruments for which counterparties deteriorate, and it decreases when our prices are available from external sources, other commodities and credit exposure to counterparties decreases, the maturity certain contracts are not actively traded and are valued using terms of our transactions decrease, or the credit ratings modeling techniques to determine expected future market prices, of our counterparties improve.
contract quantities, or both. The market prices and quantities Market prices for energy and energy-related commodities used to determine fair value reflect management's best estimate vary based upon a number of factors. Changes in market prices considering various factors. However, future market prices and will affect both the recorded fair value of our mark-to-market actual quantities will vary from those used in recording mark-to- energy contracts and the level of future revenues and costs market energy assets and liabilities, and it is possible that such associated with accrual-basis activities. Changes in the value of variations could be material. our mark-to-market energy contracts will affect our earnings in We record reserves to reflect uncertainties associated with the period of the change, while changes in forward market prices certain estimates inherent in the determination of fair value that related to accrual-basis revenues and costs will affect our earnings are not incorporated in market price information or other in future periods. We cannot predict whether or to what extent market-based estimates used to determine fair value of our mark- the factors affecting market prices may change, but those to-market energy contracts. To the extent possible, we utilize changes could be material and could affect us either favorably or market-based data together with quantitative methods for both unfavorably. We discuss our market risk in more detail in the measuring the risks for which we record reserves and Market Risk section.
determining he level of such reserves and changes in those On October 25, 2002, the EITF reached a consensus on levels. Issue 02-3 that changed the accounting for certain energy We describe below the main types of reserves we record and contracts. The main provisions of Issue 02-3 are as follows:
the process for establishing each. Generally, increases in reserves
- EITF 02-3 prohibits the use of mark-to-market reduce our earnings, and decreases in reserves increase our accounting for any energy-related contracts that are not earnings. However, all or a portion of the effect on earnings of derivatives. Any contracts subject to EITF 02-3 must be changes in reserves may be offset by changes in the value of the accounted for on the accrual basis and recorded in the underlying positions. income statement gross rather than net upon application
- Close-out reserve-this reserve represents the estimated of EITF 02-3. This change applied immediately to new cost to close out or sell to a third-party open mark-to- contracts executed after October 25, 2002 and applied market positions. This reserve has the effect of valuing to existing non-derivative energy-related contracts "long" positions at the bid price and "short" positions at beginning January 1, 2003.
the offer price. We compute this reserve based on our
- We are required to report the impact of initially estimate of the bid/offer spread for each commodity and applying EITF 02-3 as the cumulative effect of a change option price and the absolute quantity of our open in accounting principle.
positions for each year. Effective July 1, 2002, to the
- The EITF minutes on Issue 02-3 indicate that an entity extent that we are not able to obtain market should not record unrealized gains or losses at the information for similar contracts, the close-out reserve is inception of derivative contracts unless the fair value of equivalent to the initial contract margin, thereby the contracts is evidenced by observable market data.
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Applying EITF 02-3 will not affect our cash flows or our On January 1, 2003, we recorded the $425.5 million non-accounting for new load-serving contracts for which we have derivative net asset removed from our Consolidated Balance been using accrual accounting since early 2002. Additionally, we Sheets as a cumulative effect of a change in accounting principle, continued to mark existing non-derivative energy-related which will reduce our 2003 net income by $263 million. The contracts to market for the remainder of 2002. However, $425.5 million represents $374.9 million of non-derivative EITF 02-3 requires us to record a non-cash, cumulative effect contracts recorded as "Mark-to-market energy assets and adjustment to convert these non-derivative mark-to-market liabilities" and $50.6 million of "Other assets and liabilities" contracts to accrual accounting no later than January 1, 2003. from the re-designation of Texas contracts to accrual accounting We reviewed our portfolio of mark-to-market contracts to earlier in 2002. The fair value of these contracts will be identify the contracts that are subject to the requirements of recognized in earnings as power is delivered.
EITF 02-3. The primary contracts that are affected are our full Additionally, on January 1, 2003, we reclassified the fair requirements load-serving contracts and unit-contingent power value of derivatives designated as hedges as "Risk management purchase contracts, which are not derivatives. The majority of assets and liabilities" in the balance sheet and will account for these contracts are in Texas and New England and were entered these hedges in accordance with the provisions of SFAS into prior to the shift to accrual accounting earlier in 2002. No. 133. At that time, we also reclassified the fair value of Additionally, we reviewed derivatives we use as supply sources derivatives designated as normal purchases and normal sales as and hedges of contracts that are subject to EITF 02-3. To the "Other assets and liabilities" in the balance sheet and will extent permitted by Statement of Financial Accounting account for these contracts on the accrual basis, with the fair Standards (SFAS) No. 133, Accounting for Derivative Instruments value amortized into earnings over the lives of the underlying and Hedging Activities, as amended, we designated derivative contracts.
contracts used to fulfill our load-serving contracts as either We cannot predict the impact of applying the provisions of normal purchases or cash flow hedges under SFAS No. 133 EIIF 02-3 in the future. Those provisions prohibit mark-to-effective January 1, 2003. market accounting for gains at the inception of new non-We summarize the impact on our Consolidated Balance derivative energy contracts, require accrual accounting for those Sheets of applying EITF 02-3 on January 1, 2003 as follows: contracts, and limit the ability to record gains at the inception of new derivative contracts. We believe that our shift to accrual Assets Liabilities Net accounting for new physical delivery transactions in early 2002 is consistent with the requirement of EITF 02-3 to use accrual (In millions) accounting for non-derivative contracts.
Mark-to-market energy contracts However, the impact of applying EITF 02-3 in the future Current $ 144.0 $ 94.1 $ 49.9 will be affected by many factors, including:
Noncurrent 1,348.2 881.5 466.7
- our ability to designate and qualifi derivative contracts Total 1,492.2 975.6 516.6 for normal purchase and sale accounting or hedge Other accounting under SFAS No. 133, Current 85.7 56.8 28.9
- potential volatility in earnings from derivative contracts Noncurrent 24.2 2.5 21.7 that serve as economic hedges but do not meet the Total 109.9 59.3 50.6 accounting requirements to qualify for normal purchase and sale accounting or hedge accounting, Balance at December 31, 2002 1,602.1 1,034.9 567.2
- our ability to enter into new mark-to-market derivative Impact of EITf 02-3 Adoption origination transactions, and Non-derivative net asser reversed
- sufficient liquidiry and transparency in the energy as cumulative effect of a change markets to permit us to record gains at inception of new in accounting principle derivative contracts because fair value is evidenced by Mark-to-marker energy quoted market prices or current market transactions.
contracts (494.7) (119.8) (374.9) While we cannot predict the ongoing impact of applying Other (109.9) (59.3) (50.6) EITF 02-3, the timing of recognizing earnings on new transactions will change. In general, earnings on new Total non-derivative net asset transactions will no longer be recognized at the inception of the reversed as cumulative effect of transactions under mark-to-marker accounting because they will a change in accounting be recognized over the term of the transaction. As a result, while principle (604.6) (179.1) (425.5)
Derivatives designated as hedges (88.3) (94.4) 6.1 total earnings over the term of a transaction will be unchanged, Derivatives designated as normal we expect that our reported earnings for contracts subject to EITF 02-3 will generally match the cash flows from those purchases and sales (192.6) (128.3) (64.3) contracts more closely and may be less volatile under accrual Mark-to-market derivatives accounting than under mark-to-market accounting, which remaining after adoption of reflects changes in fair value of contracts when they occur rather EITF 02-3 on January 1, 2003 $ 716.6 $ 633.1 $ 83.5 than when products are delivered and costs are incurred.
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Alternatively, other comprehensive income may have greater available evidence. To the extent applicable, the assumptions we fluctuations after we apply EITF 02-3 because of a larger use are consistent with forecasts that we are otherwise required number of derivative contracts that we designated for hedge to make (for example, in preparing our other earnings forecasts).
accounting under SFAS No. 133, but these fluctuations will not If we are considering alternative courses of action to recover the affect earnings or cash flows. Additionally, because we will record carrying amount of a long-lived asset (such as the potential sale revenues and costs on a gross basis under accrual accounting, of an asset), we probability-weight the alternative courses of our revenues and costs could increase, but our earnings will not action to establish the cash flows.
be affected by gross versus net reporting. We use our best estimates in making these evaluations and We discuss the impact of mark-to-market accounting on consider various factors, including forward price curves for our financial results in the Results of Operations-Merchant energy, fuel costs, legislative initiatives, and operating costs.
Energy Business section. However, actual future market prices and project costs could vary from the assumptions used in our estimates, and the impact Evaluation of Assets for Impairment and Other Than of such variations could be material.
Temporary Decline In Value For long-lived assets that can be classified as assets to be We are required to evaluate certain assets that have long lives disposed of by sale under SFAS No. 144, an impairment loss (for example, generating property and equipment and real estate) shall be recognized to the extent their carrying amount exceeds to determine if they are impaired when certain conditions exist. their fair value, including costs to sell.
SFAS No. 144, Accountingfor the Impairment or Disposal of The estimation of fair value under SFAS No. 144, whether Long-Lived Assets, provides the accounting for impairments of in conjunction with an asset to be held and used or with an long-lived assets. We are required to test our long-lived assets for asset to be disposed of by sale, also involves estimation and recoverability whenever events or changes in circumstances judgment. We consider quoted market prices in active markets indicate that their carrying amount may not be recoverable. to the extent they are available. In the absence of such Examples of such events or changes would be as follows: information, we may look to prices of similar assets, consult
- a significant decrease in the market price of a long-lived with brokers, or employ other valuation techniques. Often, we asset, will discount the estimated future cash flows associated with the
- a significant adverse change in the manner an asset is asset using a single interest rate that is commensurate with the being used or its physical condition, risk involved with such an investment or employ an expected present value method that probability-weights a range of possible
- an adverse action by a regulator or in the business outcomes. The use of these methods involves the same inherent climate, uncertainty of future cash flows as discussed above with respect
- an accumulation of costs significantly in excess of the to undiscounted cash flows and actual future market prices and amount originally expected for the construction or project costs could vary from those used in our estimates, and acquisition of an asset, the impact of such variations could be material.
- a current-period loss combined with a history of losses We also are required to evaluate our equity-method and or the projection of future losses, or cost-method investments (for example, in partnerships that own
- a change in our intent about an asset from an intent to power projects) to determine whether or not they are impaired.
hold to a greater than 50% likelihood that an asset will Accounting Principles Board Opinion (APB) No. 18, The Equity be sold or disposed of before the end of its previously Method of Accountingfor Investments in Common Stock, provides estimated useful life. the accounting for these investments. The standard for For long-lived assets that are expected to be held and used, determining whether an impairment must be recorded under SFAS No. 144 requires that an impairment loss shall only be APB No. 18 is whether the investment has experienced a loss in recognized if the carrying amount of an asset is not recoverable value that is considered an "other than a temporary" decline in and exceeds its fair value. The carrying amount of an asset is value.
not recoverable under SFAS No. 144 if the carrying amount The evaluation and measurement of impairments under the exceeds the sum of the undiscounted future cash flows expected APB No. 18 standard involves the same uncertainties as to result from the use and eventual disposition of the asset. described above for long-lived assets that we own directly and Therefore, when we believe an impairment condition may have account for in accordance with SFAS No. 144. Similarly, the occurred, we are required to estimate the undiscounted future estimates that we make with respect to our equity and cost-cash flows associated with a long-lived asset or group of long- method investments are subject to variation, and the impact of lived assets. This necessarily involves judgement surrounding the such variations could be material. Additionally, if the projects in inherent uncertainty of future cash flows. which we hold these investments recognize an impairment under In order to estimate an asset's future cash flows, we will the provisions of SFAS No. 144, we would record our consider historical cash flows, as well as reflect our proportionate share of that impairment loss and would evaluate understanding of the extent to which future cash flows will be our investment for an other than temporary decline in value either similar o or different from past experience based on all under APB No. 18.
26
Significant Events
- We recorded a $1.6 million expense associated with 2002 deferred payments to employees eligible for the VSERP.
In 2002, we recorded the following special items in earnings:
- Partially offsetting these costs, we reversed approximately Pre-Tax After-Tax $2.6 million of previously accrued workforce reduction costs primarily as a result of the reversal of education (In millions) and outplacement assistance benefits we accrued that Workforce reduction costs:
Costs associated with 2001 programs $ (50.8) $ (30.8) employees did not utilize to the extent expected.
Costs associated with programs initiated in 2002 (12.0) (7.2) Costs Associated with 2002 Programs Total workforce reduction costs (62.8) (38.0) In 2002, we recorded $12.0 million of expenses for anticipated Impairment losses and other costs: involuntary severance costs in accordance with EITF 94-3, Impairments of investments in Liability Recognition for Certain Employee Termination Benefits qualifying facilities and power projects (14.4) (9.9) and Other Costs to Exit an Activity (including Certain Costs Costs associated with exit of BGE Incurred in a Restructuring) associated with new workforce Home merchandise stores (9.0) (6.1)
Impairments of real estate and reduction initiatives as follows:
international investments (1.8) (1.2)
- We recorded $8.5 million for workforce reduction costs for the severance of 120 employees at Calvert Cliffs Total impairment losses and other costs (25.2) (17.2)
Net gain on sales of investments and other Nuclear Power Plant (Calvert Cliffs).
assets 261.3 166.7
- We recorded $1.6 million of workforce reduction costs Total special items $173.3 $111.5 for the severance of 27 employees in our information technology organization. BGE recorded $0.6 million of We also discuss these special items in Note 2. this amount.
- We recorded $1.9 million of workforce reduction costs Workforce Reduction Costs for the severance of 20 employees in our legal During 2002, we incurred costs related to workforce reduction organization. BGE recorded $0.9 million of this efforts initiated in the fourth quarter of 2001 as discussed in the amount.
2001 section and additional initiatives undertaken in 2002. We discuss these costs in more detail below. Ongoing Impacts As a result of our workforce reduction programs and other Costs Associated with 2001 Programs process improvements, we expect to realize cost savings from In 2002, we recorded $63.7 million of net workforce reduction productivity initiatives of approximately $65 million in 2003.
costs associated with our 2001 workforce initiatives as discussed below. The $63.7 million included $50.8 million recognized as Impairment Losses and Other Costs expense, of which BGE recognized $33.8 million. The Investments in Qualif5ing Facilitiesand Power Projects remaining $12.9 million was recognized by BGE as a regulatory Our merchant energy business recorded impairment losses on asset related to its gas business.
certain of the investments in qualifying facilities and power
- We recorded $52.9 million when 308 employees elected projects totaling $14.4 million under the provisions of APB the age 50 to 54 Voluntary Special Early Retirement No. 18. The provisions of APB No. 18 require that an Program (VSERP).
impairment loss be recognized when an investment experiences a
- We reversed $17.8 million of the $25.1 million loss in value that is other than temporary as discussed in our involuntary severance accrual that was recorded in 2001 CriticalAccounting Policies section.
to reflect the employees that elected the age 50 to 54 During the third quarter of 2002, we performed an analysis VSERP and whose costs were included in that program.
of whether any of the investments were impaired. As a result of Ultimately, we involuntarily severed 129 employees that our analysis, we concluded that the declines in value of resulted in a total cost for the involuntary severance particular investments in certain qualifying facilities and power program of $7.3 million.
projects were other than temporary in nature under the
- We recorded $29.6 million of settlement charges related provisions of APB No. 18 and we recognized the following losses to our pension plans under SFAS No. 88, Employers' in 2002:
Accountingfor Settlements and Curtailmentsof Defined
- We recognized a $5.2 million other than temporary Benefit Pension Plans andfor Termination Benefits. These decline in value of our investment in a partnership that charges reflect the recognition of actuarial gains and owns a geothermal project in Nevada. This project losses associated with employees who have retired and experienced a well implosion and we believe that the taken their pension in the form of a lump-sum expected cash flows from the project will not be payment. Under SFAS No. 88, the settlement charge sufficient to recover our equity interest in that could not be recognized until lump-sum pension partnership.
payments exceeded annual pension plan service and interest cost, which occurred in 2002.
27
I1
- We recognized a $2.6 million other than temporary its retail sales are procured from eligible renewable energy decline in value of our investment in a fuel processing resources by 2017. The legislation also requires the California site in Pennsylvania where the expected cash flows from Energy Commission to award supplemental energy payments o a sublease are no longer expected to be sufficient to electric corporations to cover above market costs of renewable recover our lease costs associated with this site. energy.
- We recognized a $6.6 million other than temporary Given the need for electric power and the desire for decline in value of our investment in a partnership that renewable resource technologies, we believe California will owns a waste burning power project in Michigan. continue to subsidize the use of renewable energy to make these At December 31, 2002, our investment in qualifying projects economical to operate. However, should the California facilities and domestic power projects consisted of the following: legislation fail to adequately support the renewable energy initiatives, our equity-method investments in these types of Project Type Book Value projects could become impaired under the provisions of APB (In millions) No. 18, and any losses recognized could be material.
Geothermal $151.4 If our strategy were to change from an intent to hold to an Coal 133.9 intent to sell for any of our equity-method investments in Hydroelectric 62.6 qualifying facilities or power projects, we would need to adjust Biomass 52.6 Fuel Processing 23.2 their book value to fair value, and that adjustment could be Solar 10.5 material. If we were to sell these investments in the current market, ve may have losses that could be material.
Total $434.2 We believe the current market conditions for our equity- Closing of BGE Home Retail Merchandise Stores method investments that own geothermal, coal, hydroelectric, In September 2002, we announced our decision to close our and fuel processing projects provide sufficient positive cash flows BGE Home retail merchandise stores. In connection with that to recover our investments. We continuously monitor issues that decision, we recognized approximately $9.5 million in exit costs.
potentially could impact future profitability of these investments, We recognized $2.9 million related to expected severance costs including environmental and legislative initiatives. We discuss for 93 employees and $2.9 million of costs in connection with certain risks and uncertainties in more detail in our Forward the termination of leases for the eight stores and other exit costs Looking Statements section. However, should future events cause in accordance with EITF 94-3.
these investments to become uneconomic, our investments in We also recognized $3.2 million for the write-off of these projects could become impaired under the provisions of unamortized leasehold improvements in accordance with SFAS APB No. 18. No. 144, and $0.5 million for the write-down of inventory to a We have an investment in a partnership that owns a lower-of-cost-or-market valuation in accordance with Accounting geothermal project with a book value of $99.0 million at Research Bulletin No. 43, Restatement and Revision of Accounting December 31, 2002. Currently, the project is not generating at Research Bulletins. The $0.5 million is included in "Operating its designed capacity. The project is drilling wells at this site to expenses" in our Consolidated Statements of Income.
restore the generation and we expect he geothermal resource to be sufficient to enable the project to generate adequate cash Real Estate and InternationalInvestments flows over the life of this project to recover our equiry interest in As discussed in the 2001 section, we changed our strategy from that investment. However, should current or future well drilling an intent to hold to an intent to sell for certain of our non-core at this site prove to be unsuccessful or become uneconomic assets in 2001. During 2002, we determined that the fair value causing us not to make future investments in this partnership, of several real estate projects and our investment in a South our investment in this partnership could become impaired under American generation project declined below their respective book the provisions of APB No. 18 and any losses recognized could values due to deteriorating market conditions for these projects.
be material. Accordingly, we recorded losses that totaled $1.8 million for The ability to recover our costs in our equity-method these projects in accordance with SFAS No. 144 and APB investments that own biomass and solar projects is partially No. 18. In 2002, we sold our investment in a South American dependent upon subsidies from the State of California. Under generation project for approximately book value.
the California Public Utility Act, subsidies currently exist in that the California Public Utilities Commission (CPUC) requires Net Gain on Sales of Investments and Other Assets electric corporations to identify a separate rate component to In February 2002, Reliant Resources, Inc. acquired all of the fund the development of renewable resources technologies, outstanding shares of Orion Power Holdings, Inc. (Orion) for including solar, biomass, and wind facilities. In addition, recently $26.80 per share, including the shares we owned of Orion. We enacted legislation in California requires that each electric received cash proceeds of $454.1 million and recognized a gain corporation increase its total procurement of eligible renewable of $255.5 million on the sale of our investment.
energy resources by at least one percent per year so that 20% of 28
In the fourth quarter of 2001, we announced our decision Alliance to focus efforts and capital on core domestic energy businesses On December 31, 2002, we purchased Alliance Energy Services, and undertook a plan to sell a number of non-core businesses LLC and Fellon-McCord Associates, Inc. (collectively, Alliance) and investments. In 2002, we made further progress on this from Allegheny Energy, Inc. These businesses provide gas supply initiative, and recognized approximately $5.8 million in net and transportation services and energy consulting services to gains from the sale of several non-core assets including: large commercial and industrial businesses primarily in the
- Our other nonregulated businesses recognized gains Midwest region, but also in other competitive energy markets totaling $6.7 million on the sale of several parcels of including the Northeast, Mid-Atlantic, Texas and California real estate and financial investments. regions. We acquired 100% ownership of these companies for a
- In October 2002, we sold all of our 18 senior-living note payable of $21.2 million that was settled in cash on facilities for $77.2 million that represents a combination January 2, 2003. We acquired cash of $4.6 million as part of the of cash and the assumption by the buyer of existing purchase. We describe the net assets acquired in Note 14. We mortgages. Our other nonregulated businesses recognized will include the operating results of Alliance in our merchant a $2.8 million gain on the sale of our entire ownership energy business segment in 2003.
interest in these facilities.
- Our merchant energy business recognized a $2.3 million Renegotiations of our High Desert Power Contract gain on the sale of a discontinued wind-powered We are currently leasing and supervising the construction of the development project. High Desert Power Project. The project is scheduled for
- In 2001, our merchant energy business recognized an completion in mid-2003. In April 2002, we amended our High impairment loss on four turbines, associated with a Desert Power Project long-term power sales agreement with the discontinued development program as discussed in the State of California to provide revised pricing and more flexibility 2001 section. Since that time, many other companies in the amount of electricity purchased from the plant by the canceled development projects and the market values for California Department of Water Resources (CDWR) and the turbines have declined significantly. Orders for three of timing of such purchases. This amended agreement provides the the four turbines were canceled with termination fees State of California with the flexibility they desired, while paid to the manufacturer consistent with the amount preserving our overall economics and reducing our regulatory, recognized in December 2001. The fourth turbine- fuel, and legal risks.
generator set was sold during 2002 for $6.0 million The contract is a "tolling" structure, under which the below its book value. CDWR will pay a fixed amount of $12.1 million per month In addition, we sold all of our Corporate Office Properties and provides CDWR the right, but not the obligation, to Trust (COPT) equity-method investment in 2002, approximately purchase power from the High Desert Power Project at a price 8.9 million shares, as part of a public offering. We received cash linked to the variable cost of production. During the term of the proceeds of $101.3 million on the sale, which approximated the contract, which runs for seven years and nine months from the book value of our investment. commercial operation date of the plant, the High Desert Power Project will provide energy exclusively to the CDWR.
Acquisitions We also signed a comprehensive settlement agreement with NewEnergy the CDWR, the California Energy Oversight Board (EOB), the On September 9, 2002, we completed our purchase of AES CPUC, the California Attorney General, and the Governor of NewEnergy, Inc. from AES Corporation. Subsequent to the California by which each of these parties agreed to release claims acquisition, we renamed AES NewEnergy, Inc. as Constellation against us arising out of the original and renegotiated contracts.
NewEnergy, Inc. (NewEnergy). NewEnergy is a leading national Under the settlement agreement, the California parties filed provider of electricity, natural gas, and energy services, serving with the Federal Energy Regulatory Commission (FERC) to approximately 4,300 megawatts (MW) of load associated with withdraw us from the regulatory complaint filed at the FERC by large commercial and industrial customers in competitive energy the CPUC and EOB against all holders of long-term power markets including the Northeast, Mid-Atlantic, Midwest, Texas contracts. We agreed to pay $1.25 million into a school and and California. We acquired 100% ownership of NewEnergy for public buildings energy retrofit fund and another $1.25 million cash of $250.3 million including $1.4 million of direct costs to the Attorney General's office in order to conclude this overall associated with the acquisition. We acquired cash of $45.5 comprehensive settlement package.
million as part of the purchase. We describe the net assets We discuss our High Desert project in more detail in the acquired in Note 14. We include the results of NewEnergy in CapitalResources section.
our merchant energy business segment beginning on the date of acquisition.
29
- -. _ _ - -~~~~~~~~~~_ L ._ _L Generating Facilities Commence Operations 2001 The following generating facilities commenced operations during In 2001, we recorded the following special items in earnings:
the second half of 2002. Our origination and risk management operation manages the output of these plants. Pre-Tax After-Tax (In millions)
Capacity Primary Workforce reduction costs:
Plant Location (MW) Type Fuel Voluntary termination benefits-VSERP $ (70.1) $ (42.5)
Settlement and curtailment charges (16.3) (9.9)
Rio Nogales Seguin, TX 800 Combined Natural Involuntary severance accrual (19.3) (11.7)
Cyde Gas Oleander Brevard Co., FL 680 Combustion Natural Total workforce reduction costs (105.7) (64.1)
Turbine Gas Contract termination related costs (224.8) (139.6)
Holland Energy Shelby Co., IL 665 Combined Natural Impairment losses and other costs:
Cycle Gas Cancellation of domestic power projects (46.9) (30.5)
Impairments of real estate, senior-living, and international investments (107.3) (69.7)
Pension Plan Reduction of financial investment (4.6) (2.8)
At December 31, 2002, we recorded an after-tax charge to equity of $118 million as a result of increasing our additional Total impairment losses and other costs (158.8) (103.0)
Net gain on the sales of investments and other minimum pension liability. We discuss this in more detail in assets 6.2 1.9 Note 6.
As a result of declines in the financial markets, our actual Total special items $(483.1) $(304.8) return on pension plan assets was a loss of approximately 10% We also discuss these special items in Note 2.
for the year ended December 31, 2002. We assume an expected return on pension plan assets of 9% for the purpose of Workforce Reduction Costs computing annual net periodic pension expense. We determined In the fourth quarter of 2001, we undertook several measures to our assumption for expected return on pension plan assets in reduce our workforce through both voluntary and involuntary accordance with SFAS No. 87, Employers Accounting for Pensions. means. The purpose of these programs was to reduce our This assumption reflects our targeted long-term investment operating costs to become more competitive. As part of this allocation of 65% equities and 35% fixed income securities for initiative, several companies, including our merchant energy our pension plan assets. We set the level of this assumed return business and BGE, announced several workforce reduction based on a review of average, actual returns for these categories initiatives to provide enhanced retirement benefits to certain of investments over a long-term period. Some years our actual eligible participants that elected to retire in 2002 and other return on pension assets will exceed the 9% expected return, involuntary severance programs.
resulting in an actuarial gain; and some years our actual return As a result, we recorded $105.7 million of expenses related will fall short of the 9% expected return, resulting in an to these programs during the fourth quarter of 2001. BGE actuarial loss. recorded $57.0 million of this amount as expense relating to its These differences between actual and expected returns are electric and gas businesses. BGE also recorded $19.5 million on deferred along with other actuarial gains and losses and reflected its balance sheet as a regulatory asset of its gas business.
in future net periodic pension expense in accordance with SFAS No. 87. Expected and actual returns on pension assets also are Contract Termination Related Costs affected by plan contributions. In 2002, we contributed $152 We announced the termination of our power business services million to our pension plans, which included $80 million to the agreement with Goldman Sachs & Co. (Goldman Sachs) in Constellation Energy qualified pension plan and amounts 2001. We paid Goldman Sachs a total of $355 million, received from the sellers of Nine Mile Point to the Nine Mile representing $196 million to terminate the power business Point pension plan. As of the date of this report, we contributed services agreement with our origination and risk management an additional $111 million to our pension plans in 2003. operation and $159 million previously recognized as a payable for services rendered under the agreement. We issued commercial Certain Reatioships paper and borrowed under our existing bank lines to fund this Thomas E Brady, a Senior Vice President of Constellation payment. In the fourth quarter of 2001, we recognized expenses Energy is a trustee of COPT. Constellation Energy sold some of of approximately $224.8 million related to the termination of its real estate holdings to COPT in 2002 for an aggregate price the contract with Goldman Sachs.
of less than $5 million. Constellation Energy sold, and anticipates selling, additional real estate holdings to COPT in Impairment Losses and Other Costs 2003 for an aggregate price of less than $35 million. The real In the fourth quarter of 2001, our merchant energy business estate sales were made, and future sales will be made, on an recorded impairments of $46.9 million primarily due to the arm7s length basis. termination of all planned development projects not under construction, including projects in Texas, California, Florida, and Massachusetts, and due to a decline in value of an investment in 30
a power project in Michigan. We decided to terminate our funds. As a result of this purchase, we own 1,550 megawatts of development projects due to the expected excess generation Nine Mile Point's 1,757 megawatts of total generating capacity.
capacity in most domestic markets and the significant decline in We sell 90% of our share of Nine Mile Point's output, on a the forward market prices of electricity. The impairments unit contingent basis (if the output is not available because the included costs associated with four turbines no longer expected plant is not operating, there is no requirement to provide output to be placed in service. from other sources), back to the sellers at an average price of In the fourth quarter of 2001, our other nonregulated nearly $35 per megawatt-hour for approximately 10 years under businesses recorded $107.3 million in impairments of certain power purchase agreements.
non-core assets as follows: We describe the net assets acquired in Note 14.
- We decided to sell six real estate projects without further development and our senior-living facilities. Bethlehem Steel
- We decided to accelerate the exit strategies for two other On October 15, 2001, Bethlehem Steel Corporation filed for real estate projects that we will continue to hold and reorganization under Chapter 11 of the U.S. Bankruptcy Code.
own over the next several years. Bethlehem Steel's Sparrows Point plant, located in Baltimore,
- We decided to accelerate the exit strategy for the Maryland is BGE's largest customer, accounting for investment in a distribution company in Panama. approximately three percent of electric revenues and one percent
- There was an other than temporary decline in value in of gas revenues. At December 31, 2002 and 2001, our exposure our equity-method Bolivian investment due to a to Bethlehem Steel was not material. There is uncertainty deterioration in our investment's position in the Bolivian regarding the continuation of Bethlehem Steel's operations; capacity market. however, we do not expect the impact to be material to our In addition, our financial investments business recorded a financial results.
$4.6 million reduction of its investment in an aircraft due to the decline in value of used airplanes as a result of the Strategy September 11, 2001 terrorist attacks and the general downturn We are pursuing an integrated energy platform that provides a in the aviation industry. balanced mix of stable and predictable earnings from regulated utility operations with a growth platform from merchant energy Net Gain on the Sales of Investments and Otber Assets operations. The strategy for our merchant energy business is to During 2001, our other nonregulated businesses recognized a be a leading competitive provider of energy solutions for large
$49.5 million gain on the sale of non-core assets, including a customers in North America. Our merchant energy business has
$14.9 million gain on the sale of one million shares of our electric generation assets located in various regions of the United Orion investment and $34.6 million on the sales of other States and has an origination and risk management operation financial investments. that focuses on providing energy solutions to meet customers' In addition, on November 8, 2001, we sold our needs throughout North America.
Guatemalan power plant operations to an affiliate of Duke The integration of electric generation assets with origination Energy International, L.L.C., the international business unit of and risk management of energy and energy-related commodities Duke Energy. Through this sale, Duke Energy acquired Grupo allows our merchant energy business to manage energy price risk Generador de Guatemala y Cia., S.C.A., which owns two over geographic regions and over time. Our focus is on generating plants at Esquintla and Lake Amatitlan in Guatemala. providing solutions to customers' energy needs, and our The combined capacity of the plants is 167 megawatts. origination and risk management operation adds value to our We decided to sell our Guatemalan operations to focus our generation assets by providing national market access, market efforts on our core North American energy businesses. As a infrastructure, real-time market intelligence, risk management result of this transaction, we are no longer committed to making and arbitrage opportunities, and transmission and transportation significant future capital investments in this non-core operation. expertise. Generation capacity supports our origination and risk We recorded a loss of $43.3 million in the fourth quarter of management operation by providing a source of reliable power 2001 resulting from this sale. supply that provides a physical hedge for some of our load-serving activities.
Nine Mile Point To achieve our strategic objectives, we expect to continue to On November 7, 2001, we completed our purchase of the Nine pursue opportunities that expand our access to customers and to Mile Point Nuclear Station (Nine Mile Point) located in Scriba, support our origination and risk management operation with New York. Nine Mile Point Nuclear Station, LLC, a subsidiary generation assets that have diversified geographic, fuel, and of Constellation Nuclear, purchased 100 percent of Nine Mile dispatch characteristics. We also expect to use a disciplined Point Unit I and 82 percent of Unit 2 for cash of $382.7 growth strategy through originating transactions with large million including settlement costs and a sellers' note of $388.1 customers and by acquiring and developing additional generating million to be repaid over five years with an interest rate of facilities when desirable to support our merchant energy I 1.0%. This note was prepaid in April 2002. The sellers also business.
transferred approximately $442 million in decommissioning 31
Our merchant energy business will focus on long-term, several merchant energy businesses significantly reduced their high-value sales of energy, capacity, and related products to large energy trading activities due to deteriorating credit quality.
customers, including distribution utilities, industrial customers, Beginning in the second quarter of 2002, several regional and large commercial customers primarily in the regional energy markets experienced a significant decline in liquidity. As a markets in which end-use customer electricity rates have been result of the reduced market liquidity, our origination and risk deregulated and thereby separated from the cost of generation management operation held energy positions in certain markets supply. These markets include the New England region, the longer than it otherwise would have during the first half of New York region, the Mid-Atlantic region, Texas, Illinois, 2002. In response to this reduced market liquidity, we reduced California, and certain areas in Canada. these positions and continue to modify our positions to reflect The growth of BGE and our other retail energy services the underlying liquidity of the various regional energy markets.
businesses is expected through focused and disciplined expansion As discussed above, certain companies in the energy primarily from new customers. industry have been experiencing deteriorating credit quality. We Customer choice, regulatory change, and energy market continue to actively manage our credit portfolio to attempt to conditions significantly impact our business. In response, we reduce the impact of a potential counterparty default. We discuss regularly evaluate our strategies with these goals in mind: to our counterparty credit risk in more detail in the Market Risk improve our competitive position, to anticipate and adapt to section.
business environment and regulatory changes, and to maintain a We also continue to examine plans to achieve our strategies strong balance sheet and investment-grade credit quality. and to further strengthen our balance sheet and enhance our Beginning in the fourth quarter of 2001, we undertook a liquidity. We discuss our strategies in the Strategy section. We number of initiatives to reduce our costs towards competitive discuss our liquidity in the FinancialCondiron section.
levels and to ensure that our resources are focused on our core energy businesses. This included the implementation of Electric Competition workforce reduction programs, termination of all planned We are facing competition in the sale of electricity in wholesale development projects not under construction, and the power markets and to retail customers.
acceleration of our exit strategy for certain non-core assets.
We also might consider one or more of the following Maryland strategies: As a result of the deregulation of electric generation in
- the complete or partial separation of BGE's transmission Maryland, the following occurred effective July 1, 2000:
function from its distribution function,
- All customers can choose their electric energy supplier.
- mergers or acquisitions of utility or non-utility BGE provides fixed price standard offer service over businesses or assets, and various time periods for different classes of customers
- sale of assets or one or more businesses. that do not select an alternative supplier until June 30, 2006.
Business Environment
- While BGE does not sell electric commodity to all General Industry customers in its service territory, BGE does deliver The utility industry and energy markets continue to experience electricity to all customers and provides meter reading, significant changes as a result of less liquid and more volatile billing, emergency response, regular maintenance, and wholesale markets, deteriorating credit qualities of various balancing services.
industry participants, volatile power and fuel prices, excess
- BGE provides a market rate standard offer service for generation in the domestic markets, and the slow recovery of the those commercial and industrial customers who are no U.S. economy. longer eligible for fixed price standard offer service until Due to market conditions in 2001, we canceled our June 30, 2006.
separation plans and terminated our power business services
- BGE reduced residential base rates by approximately agreement with Goldman Sachs on October 26, 2001 and 6.5% on average, or about $54 million a year, from decided to maintain our existing corporate structure. We also rates prior to July 1, 2000. These rates will not change terminated all planned development projects not under before July 2006. While total residential base rates construction. Separately, we initiated efforts to reduce costs in remain unchanged over this transition period (July 1, order to become more competitive and to sell certain non-core 2000 through June 30, 2006), the increase in the assets to focus attention and capital resources on our core energy standard offer service rate is offset by a corresponding businesses. decrease in the competitive transition charge (CTC) that During 2002, the energy markets were affected by BGE receives from its customers.
significant events, including expanded investigations by state and
- Commercial and industrial customers have several federal authorities into business practices of energy companies in service options that will fix electric energy rates through the deregulated power and gas markets relating to "wash trading" June 30, 2004 and transition charges through June 30, to inflate revenues and volumes, and other trading practices 2006.
allegedly designed to manipulate market prices. In addition, 32
- BGE transferred, at book value, its nuclear generating Other States assets, its nuclear decommissioning trust fund, and Several states, other than Maryland, have supported deregulation related assets and liabilities to Calvert Cliffs Nuclear of the electric industry. The pace of deregulation in other states Power Plant, Inc. In addition, BGE transferred, at book varies based on historical moves to competition and responses to value, its fossil generating assets and related assets and recent market events. Certain states that were considering liabilities and its partial ownership interest in two coal deregulation have slowed their plans or postponed consideration.
plants and a hydroelectric plant located in Pennsylvania In response to regional market differences and to promote to Constellation Power Source Generation. competitive markets, the FERC proposed initiatives promoting Our origination and risk management operation provides the formation of Regional Transmission Organizations and a BGE with 100% of the energy and capacity required to meet its standard marker design. If approved, these market changes could standard offer service obligations through June 30, 2003. Our provide additional opportunities for our rerchant energy origination and risk management operation obtains the energy business. We discuss these initiatives in the FERC Regulation-and capacity to supply BGE's standard offer service obligations Regional Transmission Organizationsand Standard Market Design from affiliates that own Calvert Cliffs and BGE's former fossil section.
plants, supplemented with energy and capacity purchased from As a result of ongoing litigation before the FERC regarding the wholesale market, as necessary. sales into the spot markets of the California Independent System In August 2001, BGE entered into contracts with our Operator and Power Exchange, we estimate that we may be origination and risk management operation to supply 90% and required to pay refunds of between $3 and $4 million for Allegheny Energy Supply Company, LLC (Allegheny) to supply transactions that we entered into with these entities for the the remaining 10% of BGE's standard offer service for the final period between October 2000 and June 2001. However, our three years (July 1, 2003 to June 30, 2006) of the transition estimate is based on current information and because litigation is period. Currently, the credit ratings of Allegheny are below ongoing, new events could occur that could cause the actual investment grade. Under the terms of the contract, in certain amount, if any, to be materially different from our estimate.
circumstances, BGE has the right to request additional credit support from Allegheny to secure performance under the Gas Competition contract. If BGE was to exercise these rights and Allegheny did Currently, no regulation exists for the wholesale price of natural not meet such request, BGE could liquidate and terminate the gas as a commodity, and the regulation of interstate transmission contract. As of the date of this report, Allegheny is in at the federal level has been reduced. All BGE gas customers compliance with the terms of the contract. have the option to purchase gas from other suppliers.
BGE's (and other Maryland utilities') role in providing electricity supply to customers is currently the subject of a Regulation by the Maryland PSC proceeding at the Maryland PSC. Specifically, BGE entered into In addition to electric restructuring which was discussed earlier, a proposed settlement agreement with parties representing regulation by the Maryland PSC influences BGE's businesses.
customers, industry, utilities, suppliers, the Maryland Energy The Maryland PSC determines the rates that BGE can charge Administration, the Maryland PSC's Staff, and the Office of customers for the electric distribution and gas businesses. The People's Counsel that extends BGE's obligation to supply Maryland PSC incorporates into BGE's electric rates the standard offer service. transmission rates determined by FERC. Prior to July 1, 2000, Under the proposed settlement agreement, BGE would be BGE's regulated electric rates consisted primarily of a "base rate" obligated to provide market-based standard offer service to and a "fuel rate." BGE unbundled its electric rates to show residential customers until June 30, 2010, and for commercial separate components for delivery service, competitive transition and industrial customers for a one, two or four year period charges, standard offer services (generation), transmission, beyond June 30, 2004, depending on customer size. The rates universal service, and taxes. The rates for BGE's regulated gas charged during this time would be fixed during the term of the business continue to consist of a "base rate" and a "fuel rate."
supply contract and would include an administrative fee. The proposed settlement agreement currently is before the Maryland PSC for approval.
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v~~~~~ ~ 1L I Base Rate FERC Regulation The base rate is the rate the Maryland PSC allows BGE to Regional Transmission Organizationsand StandardMarket charge its customers for the cost of providing them service, plus Design a profit. BGE has both an electric base rate and a gas base rate. In December 1999, FERC issued Order 2000, amending its Higher electric base rates apply during the summer when the regulations under the Federal Power Act to advance the demand for electricity is higher. Gas base rates are not affected formation of Regional Transmission Organizations (RTOs) that by seasonal changes. would allow easier access to transmission.
BGE may ask the Maryland PSC to increase base rates On July 31, 2002, the FERC issued a proposed rulemaking from time to time. The Maryland PSC historically has allowed regarding implementation of a standard market design (SMD)
BGE to increase base rates to recover increased utility plant asset for wholesale electric markets. The SMD rulemaking is intended costs and higher operating costs, plus a profit, beginning at the to complement the FERC's RTO order, and will require RTOs time of replacement. Generally, rate increases improve our utility to substantially comply with its provisions. The SMD proposal earnings because they allow us to collect more revenue. However, requires transmission providers to turn over the operation of rate increases are normally granted based on historical data, and their facilities to an independent operator that will operate them those increases may not always keep pace with increasing costs. consistent with a revised market structure proposed by the Other parties may petition the Maryland PSC to decrease base FERC. According to the FERC, the revised market structure will rates. reduce inefficiencies caused by inconsistent market rules and On June 19, 2000, the Maryland PSC authorized a $6.4 barriers to transmission access. The FERC proposed that its rule million annual increase in our gas base rates effective June 22, be implemented in stages by October 1, 2004. Comments on 2000. the SMD proposal were submitted in February 2003. However, As a result of the deregulation of electric generation in in early 2003, the FERC announced that it would issue a report Maryland, BGE's residential electric base rates are frozen until on SMD and again solicit comments from interested parties.
2006. Electric delivery service rates are frozen until 2004 for In 1997, BGE turned over the operation of its transmission commercial and industrial customers. The generation and facilities to PJM, a FERC approved RTO, which generally transmission components of rates are frozen for different time conducts its operations in accordance with FERC standard periods depending on the service options selected by those market design principles. We believe that the SMD proposal customers. may lead to long-term benefits for Constellation Energy and BGE because the proposal will promote competition in regions Fuel Rate where it is implemented. However, until the proposal is Through June 30, 2000, we charged our electric customers finalized, we cannot predict its effect on our, or BGE's, financial separately for the fuel we used to generate electricity (nuclear results.
fuel, coal, gas, or oil) and for the net cost of purchases and sales of electricity. We charged the actual cost of these items to the Cash Management customer with no profit to us. If these fuel costs increased, the In August 2002, the FERC issued proposed rules for the Maryland PSC generally permitted us to increase the fuel rate. regulation of cash management practices of a regulated Under deregulation of electric generation, BGE's electric subsidiary of a nonregulated parent. As currently proposed, we fuel rate was frozen until July 1, 2000, at which time the fuel do not believe the proposed rule will have a material effect on rate clause was discontinued. We deferred the difference between our, and BGE's, financial results. We discuss our cash our actual costs of fuel and energy and what we collected from management arrangement in Note 15.
customers under the fuel rate through June 30, 2000.
In September 2000, the Maryland PSC approved the Weather collection of the $54.6 million accumulated difference berween Merchant Ener Business our actual costs of fuel and energy and the amounts collected Weather conditions in the different regions of North America from customers that were deferred under the electric fuel rate influence the financial results of our merchant energy business.
clause through June 30, 2000. We collected this accumulated Weather conditions can affect the supply of and demand for difference from customers over the twelve-month period ended electricity and fuels, and changes in energy supply and demand October 2001. Effective July 1, 2000, earnings are affected by may impact the price of these energy commodities in both the the changes in the cost of fuel and energy. spot market and the forward market. Typically, demand for We charge our gas customers separately for the natural gas electricity and its price are higher in the summer and the winter, they purchase from us. The price we charge for the natural gas when weather is more extreme. Similarly, the demand for and is based on a market-based rates incentive mechanism approved price of natural gas and oil are higher in the winter. However, by the Maryland PSC. We discuss market-based rates and a all regions of North America typically do not experience extreme current proceeding with the Maryland PSC in more detail in the weather conditions at the same time.
Gas Cost Adjustments section and in Note 1.
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BGE These factors can affect energy commodity and derivative Weather affects the demand for electricity and gas for our prices in different ways and to different degrees. These effects regulated businesses. Very hot summers and very cold winters may vary throughout the country as a result of regional increase demand. Mild weather reduces demand. Residential sales differences in:
for our regulated businesses are impacted more by weather than
- weather conditions, commercial and industrial sales, which are mostly affected by
- market liquidity, business needs for electricity and gas.
- capability and reliability of the physical electricity and However, the Maryland PSC allows us to record a monthly gas systems, and adjustment to our regulated gas business revenues to eliminate
- the nature and extent of electricity deregulation.
the effect of abnormal weather patterns. We discuss this further Other factors, aside from weather, also impact the demand in the Weather Normalization section. for electricity and gas in our regulated businesses. These factors We measure the weather's effect using "degree-days." The include the "number of customers" and "usage per customer" measure of degree-days for a given day is the difference between during a given period. We use these terms later in our the average daily actual temperature and a baseline temperature discussions of regulated electric and gas operations. In those of 65 degrees. Cooling degree-days result when the average daily sections, we discuss how these and other factors affected electric actual temperature exceeds the 65 degree baseline. Heating and gas sales during the periods presented.
degree-days result when the average daily actual temperature is The number of customers in a given period is affected by less than the baseline. new home and apartment construction and by the number of During the cooling season, hotter weather is measured by businesses in our service territory.
more cooling degree-days and results in greater demand for Usage per customer refers to all other items impacting electricity to operate cooling systems. During the heating season, customer sales that cannot be measured separately. These factors colder weather is measured by more heating degree-days and include the strength of the economy in our service territory.
results in greater demand for electricity and gas to operate When the economy is healthy and expanding, customers tend to heating systems. consume more electricity and gas. Conversely, during an We show the number of cooling and heating degree-days in economic downtrend, our customers tend to consume less 2002 and 2001, the percentage change in the number of degree- electricity and gas.
days from the prior year, and the number of degree-days in a "normal" year as represented by the 30-year average in the Environmental and Legal Maters following table. You will find details of our environmental matters in Note 11 30
-year and Item 1. Business-EnvironmentalMatters section. You will 2002 2001 Average find details of our legal matters in Note 11. Some of the Cooling degree-days 1,006 787 836 information is about costs that may be material to our financial Percentage change from prior year 27.8% 6.9% results.
Heating degree-days 4,542 4,514 4,736 Percentage change from prior year 0.6% (8.5)% Accounting Standards Adopted and Issued We discuss recently adopted and issued accounting standards in Other Factors Note 1.
A number of other factors significantly influence the level and volatility of prices for energy commodities and related derivative products for our merchant energy business. These factors include:
- seasonal daily and hourly changes in demand,
- number of market participants,
- extreme peak demands,
- available supply resources,
- transportation availability and reliability within and between regions,
- procedures used to maintain the integrity of the physical electricity system during extreme conditions, and
- changes in the nature and extent of federal and state regulations.
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I. l I Results of Operatlons
- We benefited from the absence of Goldman Sachs fees In this section, we discuss our earnings and the factors affecting due to the termination of the power business services them. We begin with a general overview, then separately discuss agreement in October 2001.
net income for our operating segments. Changes in other
- We had higher mark-to-market earnings from our income, fixed charges and income taxes are discussed in the origination and risk management operation.
aggregate for all segments in the ConsolidatedNonoperating
- We had higher earnings from our regulated electric Income and Expenses section. business because of warmer summer weather in the central Maryland region.
Overview
- We had higher earnings from the addition of Net Income NewEnergy.
2002 2001 2000
- We had higher earnings from our other nonregulated (In millions) businesses due to the growth of our energy services Net Income Before Special Items business and improved results from our international Induded in Operations: portfolio.
Merchant energy $275.5 $291.2 $213.6 These increases were partially offset by special items Regulated electric 119.8 84.5 106.5 recorded in 2002 as previously discussed in the Significant Events Regulated gas 31.9 38.3 30.6 section and the following:
Other nonregulated (13.1) (26.8) (33.4)
- We had higher fixed charges due to the issuance of $2.5 Net Income Before Special Items billion of long-term debt that was primarily used to Induded in Operations 414.1 387.2 317.3 repay short-term borrowings and due to lower Special Items Included in Operations: capitalized interest because of the new generating Net gain on sales of investmenrs and facilities that commenced operations since mid-2001.
other assets 166.7 1.9 47.2 Workforce reduction costs (38.0) (64.1) (4.2)
- Our merchant energy business had higher purchased fuel Impairments of investment in costs.
qualifirng facilities and domestic
- We had lower earnings due to the extended outage at power projects (9.9) (30.5) Calvert Cliffs to replace the steam generators at Unit 1.
Costs associated with exit of BGE
- Our merchant energy business had lower earnings due Home merchandise stores (6.1) to the impact of large commercial and industrial Impairments of real estate, senior- customers leaving BGE's standard offer service and living, and international electing other generation suppliers resulting in the sale investments (1.2) (69.7) of excess generation at lower wholesale market prices.
Contract termination related costs - (139.6)
Reduction of financial investment - (2.8)
- Our merchant energy business had lower earnings from Deregulation transition cost - - (15.0) our investments in qualifying facilities and domestic power projects.
Net Income Before Cumulative Effect of Change in Accounting Principle 525.6 82.4 345.3 In addition, our other nonregulated businesses recorded the Cumulative Effect of Change in following in 2001 that had a positive impact in that period:
Accounting Principle - 8.5 -
- an $8.5 million after-tax, or $.05 per share, gain for the Net Income $525.6 $ 90.9 $345.3 cumulative effect of adopting SFAS No. 133, and
- gains on the sale of securities of $30.0 million after-tax, Net income for the periods presented reflect a significant shiftfrom or $.19 per share.
the regulated electric business to the merchant energy business as a Earnings per share contributions from all of our business result of the transfer of BGEs electric generation assets to segments are impacted by the dilution resulting from the nonregulatedsubsidiaries on July 1, 2000. issuance of 13.2 million of common shares during 2001.
2002 2001 Our total net income for 2002 increased $434.7 million, or Our total net income for 2001 decreased $254.4 million, or
$2.63 per share, compared to 2001 mostly because of the $1.73 per share, compared to 2000 mostly because the special following: items included in operations as previously discussed in the
- We recognized a $163.3 million after-tax gain, or $1.00 Signficant Events section more than offset the $69.9 million, or per share, on the sale of our investment in Orion as $.29 per share, increase in our net income before special items.
previously discussed in the Sigtificant Events section. Net income before special items was $387.2 million, or
- We recorded special items in 2001 that had a negative $2.41 per share, in 2001 compared to $317.3 million, or $2.12 impact in that year. per share, in 2000. Net income before special items was higher
- We had cost reductions due to productivity initiatives compared to 2000 mostly because BGE recorded $75.0 million associated with our corporate-wide workforce reduction pre-tax, or approximately $.30 per share, of amortization expense and other productivity programs. for the reduction of our generating plants associated with the The addition of Nine Mile Point Nuclear Station (Nine M deregulation of electric generation in 2000 that had a negative Mile Point) to the generation fleet increased net income. impact in that year. In addition, we had higher earnings from our regulated gas business in 2001 mostly because of increases in 36
the sharing mechanism under our gas cost adjustment clauses
- We record changes in the fair value of contracts that are and the increase in our base rates. These increases were offset by subject to mark-to-market accounting in revenues on a the impact of a 6.5% annual electric residential rate reduction net basis in the period in which the change occurs.
that was effective July 1, 2000. EITF 02-3 will affect how we apply the mark-to-market The decrease in total net income for 2001 compared to method of accounting. We discuss EITF 02-3 in the 2000 also was partially offset by the following: CriticalAccounting Policies section and in Note 1.
- Our merchant energy business recorded in 2000 an Mark-to-market accounting requires us to make estimates expense of $15.0 million after-tax, or $.Io per share, for and assumptions using judgment in determining the fair value of a deregulation transition cost to Goldman Sachs that our contracts and in recording revenues from those contracts.
had a negative impact in that year. We discuss the effects of mark-to-market accounting on our
- BGE recorded an expense of $4.2 million after-tax, or revenues in the Competitive Supply-Mark-to-Market Revenues
$.03 per share, for its employees that elected to section. We discuss mark-to-market accounting and the participate in a targeted VSERP in 2000 that had a accounting policies for the merchant energy business further in negative impact in that year. the CriticalAccounting Policies section and in Note 1.
- We recorded an $8.5 million after-tax, or $.05 per As a result of the changes in our organization and senior share, gain for the cumulative effect of adopting SFAS management in late 2001, including the cancellation of our No. 133 in the first quarter of 2001. business separation and the termination of the power business In the following sections, we discuss our net income by services agreement with Goldman Sachs, we re-evaluated our business segment in greater detail. load-serving activities in Texas and New England as discussed in more detail in the Competitive Supply section. We determined Merchant Energy Business that since we manage these activities as a physical delivery Background business rather than a trading business, it is appropriate to apply Our merchant energy business is a competitive provider of accrual accounting for these activities. After the re-designation of energy solutions for large customers in North America. As existing contracts to non-trading, we began to record revenues discussed in the Business Environment-Electric Competition and expenses on a gross basis, but this did not have a material section, in connection with the July 1, 2000 implementation of impact on earnings because the resulting increase in revenues customer choice in Maryland, BGE's generating assets became was accompanied by a similar increase in fuel and purchased part of our nonregulared merchant energy business, and our energy expenses.
origination and risk management operation began selling to As a result of applying accrual accounting to an increasing BGE the energy and capacity required to meet its standard offer portion of our merchant energy business, including the January service obligations for the first three years (July 1, 2000 to 1, 2003 implementation of EITF 02-3, future mark-to-market June 30, 2003) of the transition period. earnings will be lower than they otherwise would have been In August 2001, BGE entered into a contract with our because we will record the margin on new transactions as power origination and risk management operation to provide 90% of is delivered to customers over the contract term using accrual the energy and capacity required for BGE to meet its standard accounting rather than in full at the inception of each new offer service requirements for the final three years (uly 1, 2003 contract. However, we expect accrual earnings for 2003 to be to June 30, 2006) of the transition period. Also effective July 1, $52 million higher than they would have been prior to applying 2000, merchant energy business revenues include 90% of the EITF 02-3, reflecting the 2003 portion of the fair value of competitive transition charges (CTC revenues) BGE collects contracts converted to accrual accounting using market prices as from its customers and the portion of BGE's revenues providing of December 31, 2002.
for nuclear decommissioning costs. While we cannot predict the ongoing impact of applying We record merchant energy revenues and expenses in our EITF 02-3, the timing of recognizing earnings on new financial results in different periods depending upon which transactions will change. In general, earnings on new portion of our business they affect. We discuss our revenue transactions will no longer be recognized at the inception of the recognition policies in the CriticalAccounting Policies section and transactions under mark-to-market accounting because they will in Note 1. We summarize our policies as follows: be recognized over the term of the transaction. However, we
- We record revenues as they are eamed and electric fuel cannot predict the total impact of these changes on our earnings and purchased energy costs as they are incurred for for the reasons discussed in the CriticalAccounting Policies contracts and activities subject to accrual accounting, section.
including certain load-serving activities, as discussed Additionally, we also expect lower earnings volatility for this below. portion of our business because unrealized changes in the fair
- Prior to the settlement of the forecasted transaction being value of load-serving contracts will no longer be recorded as hedged, we record changes in the fair value of contracts revenue at the time of the change under mark-to-market designated as cash-flow hedges in other comprehensive accounting as is required for trading activities. Any contracts income to the extent that the hedges are effective. We subject to EITF 02-3 must be accounted for on the accrual basis record the effective portion of the changes in fair value of and recorded gross rarher than net upon application of EITF hedges in earnings in the period the settlement of the 02-3, which was effective after October 25, 2002 for new non-hedged transaction occurs. We record the ineffective derivative transactions (including spot market purchases and portion of the changes in fair value of hedges, if any, in sales) and January 1, 2003 for contracts existing as of earnings in the period in which the change occurs. October 25, 2002.
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- - -___ - ~~~~~~~~~~~~~~~~~~~ L Our merchant energy busirsess results were as follows: Revenues and Fuel and PurchasedEnergy Expenses Our origination and risk management operation manages our Net Income costs of procuring fuel and energy and revenues we realize from 2002 2001 2000 the sale of energy to our customers. The difference between revenues and fuel and purchased energy expenses is the primary
$27657 $176an illon)driver 5 $ of the profitability of our merchant energy business.
Revenues Accordingly, we believe it is appropriate to discuss the operating Fuel and purchased energy 1,151.3 484.5 199.5 results of our merchant energy business by analyzing the changes expenses in the relationship between revenues and fuel and purchased Operations and maintenance expenses 787.4 597.8 387.3 energy expenses. We discuss non-fuel direct costs, such as Workforce reduction costs 26.5 46.0 - ancillary services, transmission costs, financing, and legal costs in conjunction with other operations and maintenance expenses Impairment losses and other costs 14.4 46.9 - later in this section.
We analyze our merchant energy revenues and fuel and Contract termination related costs - 224.8 - purchased energy expenses in the fllowing categories because of differences in the revenue sources, the nature of fuel and Depreciation and amortization 242.8 174.9 83.6 purchased energy expenses, and the risk profile of each category.
- PJM Platform-our fossil, nuclear, and hydroelectric Taxes other than income taxes 83.5 49.4 24.6 generating facilities and load-serving activities in the Net loss on sales of assets 3.7 - - PJM Interconnection (PJM) region for which the output is primarily used to serve BGE.
Income from Operations $ 456.1 $ 141.2 $ 330.7
- Plants with Power Purchase Agreements-our generating Net Income $ 247.2 $ 93.1 $ 198.6 facilities with long-term power purchase agreements, including our Nine Mile Point nuclear generating Net Income Before Special facility and our new Oleander and University Park Items Included in Operations $ 275.5 $ 291.2 $ 213.6 generating facilities.
Workforce reduction costs (16.0) (28.0) -
- Competitive Supply-our wholesale business that provides load-serving activities to distribution utilities Impairment of investments (primarily in Texas and New England), other wholesale in qualifying facilities origination and risk management services, and electric and domestic power 9 9) (30.5) and gas retail energy services to large commercial and projects (2.4) ( - industrial customers.
Net loss on sales of assets
- Other-our other gas-fired generating facilities, Contract termination related costs (139.6) _ investments in qualifying facilities and domestic power Deregulation transition projects, and our generation and consulting services.
cost _ _ (15.0)
Net Income $ 247.2 $ 93.1 $ 198.6 Above amounts include intercompany transactions eliminated in our Consolidated FinancialStatements. Note 3 provides a reconciliation of operating results by segment to our Consolidated Financial Statements.
38 I I
We provide a summary of our revenues and fuel and These decreases were due to approximately 1,200 megawatts purchased energy expenses as follows: of large commercial and industrial customers leaving BGE's 2002 2001 2000 standard offer service in the second quarter of 2002 and electing other electric generation suppliers, partially offset by higher (Dollaramounts in millions) volumes sold to BGE due to warmer summer weather. However, Revenues:
PJM approximately one-third of the load for large commercial and Platform $1,391A $1,379.2 $ 731.7 industrial customers left BGE's standard offer service and elected Plants with BGE Home, a subsidiary of Constellation Energy, as their Power electric generation supplier. Our merchant energy business Purchase Agreements 456.4 70.8 continues to provide the energy to BGE Home to meet the Competitive requirements of these customers under market-based rates.
Supply 825.7 175.8 151.5 Revenues from BGE Home were $45.3 million in 2002. BGE Other 92.2 139.7 142.5 Home is included in our other nonregulated businesses.
Total $2,765.7 $1,765.5 $1,025.7 CTC revenues are impacted by the CTC rates our Fuel and merchant energy business receives from BGE customers as well purchased as the volumes delivered to BGE customers. The CTC rates energy decline over the transition period as previously discussed in the expenses PJM Electric Competition-Marylandsection.
Platform $ 527.5 $ 420.9 $ 199.5 Revenues from BGE's standard offer service requirements Plants with increased $578.0 million, including CTC and decommissioning Power revenues that increased $74.4 million, in 2001 compared to Purchase Agreements 40.0 13.9 2000 because our merchant energy business provided BGE's Competitive standard offer service requirements for a full year in 2001 as Supply 552.9 - compared to six months in 2000.
Other 30.9 49.7 Total $1,151.3 $ 484.5 $ 199.5 Other PJM Revenues Revenue less Other merchant energy revenues in the PJM region decreased fuel and $32.6 million in 2002 compared to 2001 mostly because of the pursed %of %of % of following:
enetgy Total Total Total expenses:--
- The sales of power from our owned generation in excess PJM of that required to serve BGE's standard offer service Platform $ 863.9 53% $ 958.3 75% $ 532.2 65% requirements decreased $17.9 million compared to Plants with 2001. These sales decreased primarily due to lower Power Purchase generation because of the extended outage at Calvert Agreements 416.4 26 56.9 4 - - Cliffs in order to replace the steam generators at Unit I Competitive and lower generation from our coal plants partially Supply 272.8 17 175.8 14 151.5 18 offset by higher revenues due to warmer summer Other 61.3 4 90.0 7 142.5 17 weather.
Total $1,614.4 100%$1281.0 100%$ 826.2 100%
- Our merchant energy business recognized a $9.5 million gain on the sale of a project under development in this PJM Platform region in 2001 that had a positive impact in that year.
2002 2001 2000 Other merchant energy revenues in the PJM region increased $69.5 million in 2001 compared to 2000 mostly (In millions) because of the following:
Revenues $1,391.4 $1,379.2 $731.7
- The sales of power from our Baltimore plants in excess Fuel and purchased energy cxpenses 527.5 420.9 199.5 of that required to serve BGE's standard offer service requirements increased $51.2 million.
Revenues less fuel and
- Our merchant energy business recognized a $9.5 million purchased energy $ 863.9 $ 958.3 $532.2 gain on the sale of a project under development in the PJM region in March 2001.
Revenues
- The Handsome Lake generating facility that commenced BGE Standard Offer Service operations in 2001 provided revenues of $8.8 million.
The majority of PJM Platform revenues arise from BGE standard offer service. Revenues from BGE's standard offer Fuel and Purchased Energy Expenses service requirements decreased $8.3 million, including CTC and Our merchant energy business had higher fuel and purchased decommissioning revenues that decreased $4.3 million, in 2002 energy expenses in the PJM region in 2002 compared to 2001 compared to 2001. primarily due to higher replacement power costs from the extended outage at Calvert Cliffs and higher coal prices. These were partially offset by lower generation at our coal plants.
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Our merchant energy business began an extended outage at Accrual Revenues and Fuel and PurchasedEnergy Expenss Unit I of Calvert Cliffi during the first quarter of 2002 to Our accrual revenues and fuel and purchased energy expenses replace the unit's steam generators, which was completed at the increased in 2002 primarily due to the re-designation of our end of June 2002. As a result, our merchant energy business had Texas and New England load-serving activities to accrual and the lower revenues and higher operating costs, including higher acquisition of NewEnergy in September 2002. Texas and New purchased energy to meet BGE's standard offer service. Calvert England revenues were $310.5 million, and purchased energy Cliffs will replace the steam generators for Unit 2 during the expenses were $317.1 million. NewEnergy's revenues were 2003 refueling outage. Based on our current outage schedule, we $261.3 million, and purchased energy expenses were $211.6 expect the 2003 outage to be shorter than the 2002 extended million. We discuss the re-designation of Texas and New outage. However, this outage will be significandy longer than a England below.
normal refueling outage. We expect lower annual revenues and Since February 2002, we manage our Texas load-serving higher annual operating costs in 2003 from Calvert Cliffs activities as a physical delivery business separate from our trading compared to 2001 due to the longer outage. activities and re-designated these activities as non-trading. We Our merchant energy business had higher fuel and believe this designation more accurately reflects the substance of purchased energy expenses in the PJM region in 2001 compared our Texas load-serving physical delivery activities.
to 2000 mosdy because 2001 reflects a full year's operation of At the time of this change in designation, we reclassified the generation plants that were transferred from BGE effective the fair value of load-serving contracts and physically delivering July 1, 2000. The fuel cost increase also reflects higher fuel power purchase agreements in Texas from "Mark-to-market prices for generating electricity mostly because coal prices energy assets and liabilities" to "Other assets and liabilities." The increased during 2001 compared to 2000. contracts reclassified consisted of gross assets of $78 million and gross liabilities of $15 million, or a net asset of $63 million.
Plants with Power PurchaseAgreements EITF 02-3 required us to remove the unamortized balance of these assets and liabilities, excluding the costs of any acquired 2002 2001 2000 contracts, from our Consolidated Balance Sheets by January 1, (In millions) 2003.
Revenues $456.4 $70.8 $- After the change in designation, the results of our Texas Fuel and purchased energy expenses 40.0 13.9 load-serving business are included in "Nonregulated revenues" on Revenues less fuel and purchased a gross basis as power is delivered to our customers and energy $416.4 $56.9 $ "Operating expenses" as costs are incurred. Prior to the re-designation, the results of these activities were reported on a net The increases in revenues and expenses primarily were due basis as part of mark-to-market revenues included in to a full year's results from Nine Mile Point, which we acquired "Nonregulated revenues." Mark-to-market revenues for the Texas in November 2001, and the University Park generating facility, crading activities were a net loss of $1.2 million for the portion which commenced operations in the second half of 2001. In of 2002 prior to designation as non-trading. Mark-to-market addition, the Oleander generating facility commenced operations revenues for the Texas trading activities were a net loss of $33.4 in the second half of 2002.
million in 2001.
Since future power sales revenues and costs from this Competitive Supply business will be reflected in our Consolidated Statements of 2002 2001 2000 Income as part of "Nonregulated revenues" when power is (In millions) delivered and "Operating expenses" when the costs are incurred, Accrual revenues $587.6 $ - $ - this re-designation generally will delay the recognition of Mark-to-market revenues 238.1 175.8 151.5 earnings from this business in the future compared to what we Fuel and purchased energy would have recognized under mark-co-market accounting. The expenses 552.9 - - change in designation of our Texas load-serving business did not impact our cash flows.
Revenues less fuel and purchased In addition, our New England load-serving business energy $272.8 $175.8 $151.5 consists primarily of contracts to serve the full energy and We analyze our accrual and mark-to-market competitive capacity requirements of retail customers and electric distribution supply activities separately below. utilities and associated power purchase agreements to supply our customers' requirements. We manage this business primarily to assure profitable delivery of customers' energy requirements rather than as a traditional trading activity. Therefore, we use accrual accounting for New England load-serving transactions and associated power purchase agreements entered into since the second quarter of 2002.
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Because applicable accounting rules significantly limited the Revenues from origination transactions represent the initial circumstances under which contracts previously designated as a unrealized fair value of new wholesale energy transactions trading activity could be re-designated as non-trading, prior to (including restructurings) at the time of contract execution to EITF 02-3, we were required to continue to include contracts the extent permitted by applicable accounting rules. Risk entered into before the second quarter of 2002 in our mark-to- management revenues represent both realized and unrealized market accounting portfolio. However, under EITF 02-3, on gains and losses from changes in the value of our entire January 1, 2003, we removed these contracts from our "Mark- portfolio. We discuss the changes in mark-to-market revenues to-market energy assets and liabilities" and began to account for below. We show the relationship between our revenues and the these contracts under the accrual method of accounting. change in our net mark-to-market energy asset later in this We discuss the implications of EITF 02-3 in more detail in section.
the CriticalAccounting Policies section and in Note 1. Our mark-to-market revenues were and continue to be affected by a decrease in the portion of our activities that is Mark-to-Market Revenues subject to mark-to-market accounting. As previously discussed, Mark-to-market revenues include net gains and losses from we re-designated our Texas load-serving business as accrual origination and risk management activities for which we use the during 2002, and we began to account for new non-derivative mark-to-market method of accounting. We discuss these origination transactions on the accrual basis rather than under activities and the mark-to-market method of accounting in more mark-to-market accounting. Under EITF 02-3, we no longer detail in the CriticalAccounting Policies section and in Note 1. record existing non-derivative contracts at fair value beginning We also discuss the implications of EITF 02-3 on the mark-to- January 1, 2003. Further, effective July 1, 2002, to the extent market method of accounting in the CriticalAccounting Policies that we are not able to observe quoted market prices or other section and in Note 1. current market transactions for contract values determined using As a result of the nature of our operations and the use of models, we record a reserve to adjust such contracts to result in mark-to-market accounting for certain activities, mark-to-market zero gain or loss at inception. We remove the reserve and record revenues and earnings will fluctuate. We cannot predict these such contracts at fair value when we obtain current market fluctuations, but the impact on our revenues and earnings could information for contracts with similar terms and counterparties.
be material. We discuss our market risk in more detail in the Mark-to-market revenues increased $62.3 million during Market Risk section. The primary factors that cause fluctuations 2002 compared to 2001 mostly because of net gains from risk in our mark-to-market revenues and earnings are: management activities compared to net losses in the prior year,
- the number, size, and profitability of new transactions, partially offset by lower revenues from origination transactions.
- changes in the level and volatility of forward commodity The increase in risk management revenues is primarily due to prices and interest rates, the absence of mark-to-market losses recorded in 2001 on Texas
- changes in estimates of customers' load requirements as trading activities designated as non-trading in 2002, favorable a result of changes in weather and customer attrition changes in regional power prices, price volatility, and other due to the selection of other suppliers, and factors in 2002 compared to 2001. The decrease in origination
- the number and size of our open derivative positions. revenues reflects the use of accrual accounting for new load-Mark-to-market revenues were as follows: serving transactions originated beginning in the second quarter of 2002, the impact of applying the EITF guidance on recording 2002 2001 2000 gains at the time of contract origination as previously described, aIn millions) and fewer individually significant transactions in 2002 as Unrealized revenues compared to 2001.
Origination transactions $160.4 $227.0 $158.8 Mark-to-market revenues increased $24.3 million during Risk management 2001 compared to 2000 mostly because of higher revenues from Unrealized changes in fair new origination transactions, partially offset by net losses from value 66.9 (55.7) (4.0) risk management activities. The increase in origination revenues Changes in valuation reflects new full-requirements load-serving transaction volumes, techniques 10.8 4.5 (3.3) primarily in New England and Texas. The increase in risk Reclassification of serded management net losses is primarily due to decreases in both contracts to realized (45.4) (19.7) 57.0 future power prices and price volatility in 2001 and costs of Total risk management 32.3 (70.9) 49.7 establishing hedges for new origination transactions. The decrease in forward prices and volatility negatively affected the Total unrealized revenues 192.7 156.1 208.5 mark-to-market value of our portfolio of supply arrangements.
Realized revenues 45.4 19.7 (57.0) However, these mark-to-market losses were more than offset by Total mark-to-market revenues $238.1 $175.8 $151.5 mark-to-market gains in the form of new origination transactions that were in part enabled by these supply arrangements.
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L L Mark-to-Market Energy Assets and Liabilities The following are the primary sources of the change in net Our mark-to-market energy assets and liabilities are comprised of mark-to-market energy asset during 2002 and 2001:
a combination of derivative and non-derivative (physical) contracts. The non-derivative assets and liabilities primarily relate 2002 2001 to load-serving activities originated prior to the shift to accrual (In millions) accounting earlier this year. While some of these contracts Fair value beginning of year $418.4 S 527.9 represent commodities or instruments for which prices are Changes in fair value recorded as revenues available from external sources, other commodities and certain Origination transactions $160.4 $227.0 contracts are not actively traded and are valued using other Unrealized changes in pricing sources and modeling techniques to determine expected fair value 66.9 (55.7) future market prices, contract quantities, or both. We discuss our Changes in valuation modeling techniques later in this section. techniques 10.8 4.5 Mark-to-market energy assets and liabilities consisted of the Reclassification of settled following: contracts to realized (45.4) (19.7)
Total changes in fair value At December 31, 2002 2001 recorded as revenues 192.7 156.1 (in millions) Changes in fair value Current Assets $ 144.0 $ 398.4 recorded as operating Noncurrent Assets 1,348.2 1,819.8 expenses 9.0 (15.0)
Changes in value of Total Assets 1,492.2 2,218.2 exchange-listed futures and options (8.5) 6.9 Current Liabilities 94.1 323.3 Net change in premiums Noncurrent Liabilities 881.5 1,476.5 on options (40.1) (242.2)
Total Liabilities 975.6 1,799.8 Texas contracts re-designated as non-Net mark-to-market energy asset $ 516.6 $ 418.4 trading (63.3)
Other changes in fair value 8.4 (15.3)
At December 31, 2002, the primary components of our net mark-to-market energy asset were as follows: Fair value at end of year $516.6 $ 418.4 Changes in the net mark-to-market energy asset that (in millions) affected revenues were as follows:
Non-derivative contracts reversed as part of
- Origination transactions represent the initial unrealized cumulative effect of a change in accounting fair value at the time these contracts are executed.
principle effective January 1 2003 $374.9
- Unrealized changes in fair value represent unrealized Derivatives designated as hedges effective changes in commodity prices, the volatility of options January 1, 2003 (6.1) on commodities, the time value of options, and other Derivatives designated as normal purchases and valuation adjustments.
sales effective January 1, 2003 64.3
- Changes in valuation techniques represent improvements Other positions 83.5 in estimation techniques, including modeling and other Total $516.6 statistical enhancements used to value our portfolio to The non-derivative portion of the net asset represents the reflect more accurately the economic value of our fair value of contracts that we reclassified to accrual effective contracts.
January 1, 2003 as required by EITF 02-3. Derivatives
- Reclassification of settled contracts to realized represents designated as hedges effective January 1, 2003 represent the portion of previously unrealized amounts settled derivative contracts used to hedge our physical delivery contracts during the period and recorded as realized revenues.
in connection with the implementation of EITF 02-3. The net mark-to-market energy asset also changed due to Derivatives designated as normal purchases and sales effective the following items recorded in accounts other than revenue:
January 1, 2003, represent derivative contracts used to
- Changes in fair value recorded as operating expenses economically hedge our physical delivery contracts in connection represent accruals for future incremental expenses in with the implementation of EITF 02-3 but which receive accrual connection with servicing origination transactions.
accounting treatment. The remainder of the net asset primarily While these accruals are recorded as part of the fair consisrs of a PJM generation hedge comprised of a group of value of the net mark-to-market energy asset, they are options that serve as an economic hedge of the PJM generation reflected in our Consolidated Statements of Income as portfolio. These options give us the right to sell power at a floor expenses rather than revenues.
price which is valuable to our generation operation when market prices are low and also give us the right to buy power at a capped price, which adds value when the market prices are high.
We have not designated these options as hedges under SFAS No.
133 due to the complexity of qualifying options as effective hedges under the requirements of that standard.
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- Changes in value of exchange-listed futures and options
- Net changes in premiums on options reflects the are adjustments to remove unrealized revenue from accounting for premiums on options purchased as an exchange-traded contracts that are included in risk increase in the net mark-to-market energy asset and management revenues. The fair value of these contracts premiums on options sold as a decrease in the net is recorded in "Accounts receivable" rather than "Mark- mark-to-market energy asset.
to-market energy assets" in our Consolidated Balance We discuss our Texas contracts re-designated as non-trading Sheets because these amounts are settled through our in more detail in the Competitive Supply section.
margin account with a third-party broker. The settlement terms of the net mark-to-market energy asset and sources of fair value as of December 31, 2002 are as follows:
Settlement Term 2003 2004 2005 2006 2007 2008 Thereafter Fair Value (In millions)
Prices provided by external sources (1) $50.1 $ (23.9) $ (65.1) $ (0.5) $ (1.1) $ (3.5) $10.5 $ (33.5)
Prices based on models (0.2) 124.4 113.8 83.9 72.2 77.7 78.3 550.1 Total net mark-to-market energy asset $49.9 $100.5 $ 48.7 $83.4 $71.1 $74.2 $88.8 $516.6 (1) Includes contracts actively quoted and contracts valued from other external sources.
The implementation of EITF 02-3 significantly impacted the amount and composition of the net mark-to-market energy asset.
The table below presents the settlement terms of our net mark-to-market energy asset as of January 1, 2003 after reflecting the impact of implementing EITF 02-3. We discuss EITF 02-3 and the effect of its implementation in more detail in the Critical Accounting Policies section and in Note 1.
Settlement Term After Reflecting Implementation of EITF 02-3 2003 2004 2005 2006 2007 2008 Thereafter Fair Value (In millions)
Prices provided by external sources (1) $ 9.7 $(2.4) $(48.7) $ (1.0) $ (3.0) $ (5.2) $ 3.9 $ (46.7)
Prices based on models 0.8 1.1 35.3 24.5 23.0 20.0 25.5 130.2 Total net mark-to-market energy asset $10.5 $(1.3) $(13.4) $23.5 $20.0 $ 14.8 $29.4 $ 83.5 We manage our mark-to-market risk on a portfolio basis The amounts for which fair value is determined using based upon the delivery period of our contracts and the prices provided by external sources represent the portion of individual components of the risks within each contract. forward, swap, and option contracts for which price quotations Accordingly, we record and manage the energy purchase and sale are available through brokers or over-the-counter transactions.
obligations under our contracts in separate components based The term for which such price information is available varies by upon the commodity (e.g., electricity or gas), the product (e.g., commodity, region, and product. The fair values included in this electricity for delivery during peak or off-peak hours), the category are the following portions of our contracts:
delivery location (e.g., by region), the risk profile (e.g., forward
- forward purchases and sales of electricity during peak or option), and the delivery period (e.g., by month and year). hours for delivery terms primarily through 2004, but up Consistent with our risk management practices, we have to 2010, depending upon the region, presented the information in the tables above based upon the
- forward purchases and sales of electricity during off-peak ability to obtain reliable prices for components of the risks in hours for delivery terms primarily through 2004, but up our contracts from external sources rather than on a contract-by- to 2007, depending upon the region, contract basis. Thus, the portion of long-term contracts that is
- options for the purchase and sale of electricity during valued using external price sources is presented under the peak hours for delivery terms through 2003, depending caption "prices provided by external sources." This is consistent upon the region, with how we manage our risk, and we believe it provides the
- forward purchases and sales of electric capacity for best indication of the basis for the valuation of our portfolio. delivery terms through 2005, Since we manage our risk on a portfolio basis rather than
- forward purchases and sales of natural gas, coal and oil contract-by-contract, it is not practicable to determine separately for delivery terms through 2005, and the portion of long-term contracts that is included in each
- options for the purchase and sale of natural gas, coal valuation category. We describe the commodities, products, and and oil for delivery terms through 2005.
delivery periods included in each valuation category in detail below.
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The remainder of the net mark-to-market energy asset is The fair values in the tables represent expected future cash valued using models. The portion of contracts for which such flows based on the level of forward prices and volatility factors techniques are used includes standard products for which as of December 31, 2002 and could change significantly as a external prices are nor available and customized products that are result of future changes in these factors. Additionally, because valued using modeling techniques to determine expected future the depth and liquidity of the power markets varies substantially market prices, contract quantities, or both. between regions and time periods, the prices used to determine Modeling techniques include estimating the present value of fair value could be affected significantly by the volume of cash flows based upon underlying contractual terms and transactions executed.
incorporate, where appropriate, option pricing models and Management uses its best estimates to determine the fair statistical and simulation procedures. Inputs to the models value of commodity and derivative contracts it holds and sells.
include: These estimates consider various factors including closing
- observable market prices, exchange and over-the-counter price quotations, time value,
- estimated market prices in the absence of quoted market volatility factors, and credit exposure. However, future market prices, prices and actual quantities will vary from those used in
- the risk-free market discount rate, recording mark-to-market energy assets and liabilities, and it is
- volatility factors, possible that such variations could be material.
- estimated correlation of energy commodity prices,
- estimated volumes for customer requirements, which are Other influenced by customer switching behavior, impact of 2002 2001 2000 temperature on electric prices, and customer acquisition (In millions) and servicing costs, Revenues $92.2 $139.7 $142.5
- estimated volumes for tolling contracts, and Fuel and purchased energy expenses 30.9 49.7 -
- expected generation profiles of specific regions.
Additionally, we incorporate counterparty-specific credit Revenues less fuel and purchased quality and factors for market price and volatility uncertainty energy $61.3 $ 90.0 $142.5 and other risks in our valuation. The inputs and factors used to We analyze the revenues and fuel and purchased energy determine fair value reflect management's best estimates. expenses of the final category of our merchant energy business The electricity, fuel, and other energy contracts we hold below.
have varying terms to maturity, ranging from contracts for delivery the next hour to contracts with terms of ten years or Revenues more. Because an active, liquid electricity futures market Our other merchant energy business revenues decreased in 2002 comparable to that for other commodities has not developed, the compared to 2001 mostly because we had lower revenues of majority of contracts used in the origination and risk $23.4 million from our mid-continent region facilities that management operation are direct contracts between market commenced operations in mid-summer of 2001 primarily due to participants and are not exchange-traded or financially settling lower output from these facilities because of a less favorable contracts that can be readily liquidated in their entirety through relationship between energy prices and gas costs. In addition, we an exchange or other market mechanism. Consequently, we and had lower revenues of $14.0 million from our investments in other market participants generally realize the value of these qualifying facilities and domestic power projects. We discuss our contracts as cash flows become due or payable under the terms investments in qualifying facilities and domestic power projects of the contracts rather than through selling or liquidating the in more detail on the next page.
contracts themselves. Our other merchant energy business revenues decreased in Consistent with our risk management practices, the 2001 compared to 2000 mostly because of the following:
amounts shown in the tables on the previous page as being
- Our merchant energy business had lower revenues of valued using prices from external sources include the portion of $27.1 million from our investments in qualifying long-term contracts for which we can obtain reliable prices from facilities and domestic power projects.
external sources. The remaining portions of these long-term
- Our merchant energy business terminated an operating contracts are shown in the tables as being valued using models. arrangement and sold certain subsidiaries of In order to realize the entire value of a long-term contract in a Constellation Operating Services Inc. (COSI) to Orion single transaction, we would need to sell or assign the entire in 2000. COSI ended its exclusive arrangement with contract. If we were to sell or assign any of our long-term Orion to operate Orion's facilities, and Orion purchased contracts in their entirety, we may not realize the entire value from COSI the four subsidiary companies formed to reflected in the tables. However, based upon the nature of the operate power plants owned by Orion. Our merchant origination and risk management operation, we expect to realize energy business recognized a $13.3 million gain on this the value of these contracts, as well as any contracts we may sale in 2000 which had a positive impact on that year, enter into in the future to manage our risk, over time as the and the absence of $25.6 million of revenues during contracts and related hedges settle in accordance with their 2001 compared to 2000 due to the sale of these terms. We do not expect to realize the value of these contracts subsidiaries.
and related hedges by selling or assigning the contracts themselves in total.
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These lower revenues were partially offset by higher Operations and Maintenance Expenses revenues of $59.2 million from our mid-continent region gas- Our merchant energy business operations and maintenance fired peaking facilities that commenced operations in mid- expenses increased $189.6 million in 2002 compared to 2001 summer of 2001. mostly due to the following:
- Higher operations and maintenance expenses of $224.0 Investments in Qualifying Facilities and Domestic Power Projects million associated with the acquisitions of Nine Mile Our merchant energy business holds up to a 50% ownership Point in November 2001 and NewEnergv in September interest in 28 operating domestic energy projects that consist of 2002.
electric generation, fuel processing, or fuel handling facilities. Of
- Higher operations and maintenance expenses of $11.6 these 28 projects, 20 are "qualifying facilities" that receive certain million associated with new generating facilities that exemptions and pricing under the Public Utility Regulatory commenced operations beginning in mid-2001 and Policy Act of 1978 based on the facilities' energy source or the mid-2002.
use of a cogeneration process. Earnings from our investments These increases were partially offset by the following:
were $9.1 million in 2002, $23.1 million in 2001, and $50.2
- Lower costs of approximately $31 million due to million in 2000. productivity initiatives associated with our corporate-The decrease in revenues in 2002 compared to 2001 was wide workforce reduction and other productivity due to a geothermal project generating at a lower capacity and programs.
lower revenues from out California projects as discussed below.
- Lower origination and risk management operating The decrease in revenues in 2001 compared to 2000 was expenses of $10.2 million as a result of the absence of primarily due to lower revenues from our California projects. Goldman Sachs fees due to the termination of the power business services agreement in October 2001. The California Power Purchase Agreements Goldman Sachs fees were $28.9 million in 2001. This Our merchant energy business has $260.6 million invested in decrease was partially offset by an increase in expenses partnerships that own 13 operating power projects of which our associated with the growth of the operation.
ownership percentage represents 137 megawatts of electricity that Our merchant energy business operations and maintenance are sold to Pacific Gas & Electric (PGE) and to Southern expenses increased $210.5 million in 2001 compared to 2000 mostly due to the following:
California Edison (SCE) in California under power purchase
- Higher operations and maintenance expenses of $203.0 agreements. Our merchant energy business was not paid in full million mostly because 2001 reflects a full year's for its sales from these plants to the two utilities from November operation of the generation plants that were transferred 2000 through early April 2001. At December 31, 2001, our from BGE effective July 1, 2000.
portion of the amount due for unpaid power sales from these
- Higher operations and maintenance expenses of $29.5 utilities was approximately $45 million. We recorded reserves of million associated with the acquisitions of Nine Mile approximately 20% of this amount in 2001.
Point in November 2001.
Through the date of this report, we received the $45
- Higher operations and maintenance expenses of $4.3 million for unpaid power sales plus interest. We reversed all of million associated with new generating facilities that our credit reserves that totaled $9.1 million during the first commenced operations beginning in mid-2001.
quarter of 2002 as payments ensued following court-approved
- Higher origination and risk management operating restructuring agreements. expenses of $41.2 million as a result of the growth of Revenues from these projects, net of credit reserves, were the operation and higher direct expenses primarily due
$20.0 million in 2002, $22.1 million in 2001, and $44.1 to higher transaction volumes.
million in 2000. While California power prices were significantly These increases were partially offset by the following:
lower during 2002 compared to 2001, 2001 results were reduced
- The decrease in the Goldman Sachs fees of $52.4 by credit reserves established for our exposure in California. million due to the termination of the power business These reserves were subsequently reversed in 2002 as discussed services agreement in October 2001. The Goldman above, which had a positive impact in 2002. Sachs fee was $81.3 million in 2000, which included Revenues decreased in 2001 compared to 2000 because of the $24.0 million, or $.10 per share, deregulation lower power prices in California during the second half of 2001. transition cost.
While energy rates were higher during the first half of 2001, the
- Lower operations and maintenance expenses at COSI of higher rates were offset by reserves established for our exposure $20.9 million due to the sale of certain subsidiaries as in California during that year. previously discussed.
The projects entered into agreements with PGE through July 2006 and SCE through April 2007 that provide for fixed- Workorce Reduction Costs, Impairment Losses and Other Costs, price payments averaging $53.70 per megawatt-hour plus the Contract Termination Related Costs, andNet Loss on Sales of stated capacity payments in the original agreements. Assets Our merchant energy business recognized the following in 2002:
Fueland PurchasedEnergy Expenses * $26.5 million of expenses associated with our workforce Our other merchant energy business fuel and purchased energy reduction efforts, expenses decreased in 2002 compared to 2001 mostly because * $14.4 million of impairment losses for the decline in we had lower fuel and purchased energy for our mid-continent value of certain investments in partnerships that have region facilities primarily due to lower demand for the output of investments in qualifying facilities and domestic power these facilities. projects, 45
_L_ _L_
- $6.0 million loss on the sale of a steam turbine Regulated Electric Business generator set, and As previously discussed, our regulated electric business
- $2.3 million gain on the sale of Cabazon, a was significandy impacted by the July 1, 2000 wind-powered independent power project located implementation of customer choice. These changes in California. include BGE's generating assets and related liabilities Our merchant energy business recognized the becoming part of our nonregulated merchant energy following in 2001: business on that date.
- $224.8 million of expenses related to the Effective July 1, 2000, BGE unbundled its rates to termination of the power business services show separate components for delivery service, transition agreement with Goldman Sachs, charges, standard offer services (generation), rransmission,
- $46.0 million of expenses associated with our universal service, and taxes. BGE's rates also were frozen workforce reduction efforts, in total except for the implementation of a residential
- $40.8 million of impairment losses of certain base rate reduction totaling approximately $54 million planned development projects that were annually. In addition, 90% of the CTC revenues BGE terminated, and collects and the portion of its revenues providing for
- $6.1 million loss on the impairment of a power decommissioning costs, are included in revenues of the project. merchant energy business.
We discuss these special items in more detail in the As part of the deregulation of electric generation, Significant Events section and in Note 2. while total rates were frozen over the transition period, As a result of our workforce reduction programs and the increasing rates received from customers under the other process improvement initiatives, our merchant standard offer service are offset by declining CTC rates.
energy business expects to realize cost savings of approximately $44 million partially offset by other Net Income increases in operating costs in 2003.
2002 2001 2000 Depreciation and Amortization Etpense (In millions)
Merchant energy depreciation and amortization expense Revenues $ 1,966.0 $2,040.0 $2,135.2 increased $67.9 million in 2002 compared to 2001 Fuel and purchased mosdy because of the depreciation and amortization energy expenses 1,080.7 1,192.8 870.7 associated with Nine Mile Point and the new generating Operations and facilities. maintenance Merchant energy depreciation and amortization expenses 252.4 258.7 447.2 expense increased $91.3 million in 2001 compared to Workforce 2000 mostly because 2001 includes a full year of reduction costs 34.0 55.7 7.0 expenses associated with the generation plants that were Depreciation and transferred from BGE effective July 1, 2000. Additionally, amortization 174.2 173.3 319.9 2001 expenses include depreciation and amortization Taxes other than associated with the new generating facilities and Nine income taxes 137.0 139.5 157.8 Mile Point.
Income from Taxes Other Than Income Taxes Operations $ 287.7 $ 220.0 $ 332.6 Merchant energy taxes other than income taxes increased Net Income $ 99.3 $ 50.9 $ 102.3
$34.1 million in 2002 compared to 2001 mostly because Net Income Before of taxes other than income taxes associated with Nine Special Items Mile Point and the new generating facilities.
Included in Merchant energy taxes other than income taxes Operations $ 119.8 $ 84.5 $ 106.5 increased $24.8 million in 2001 compared to 2000 Workforce mostly because of taxes other than income taxes reduction costs (20.5) (33.6) (4.2) associated with the generation plants that were transferred from BGE effective July 1, 2000. Additionally, 2001 Net Income $ 99.3 $ 50.9 $ 102.3 expenses include taxes other than income taxes associated Above amounts include intercompany transactions eliminated with Nine Mile Point and the new generating facilities. in our Consolidated FinancialStatements. Note 3 provides a reconciliation of operating results by segment to our ConsolidatedFinancial Statements.
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Net income from the regulated electric business Standard Offer Service increased in 2002 compared to 2001 mostly because of BGE provides standard offer service for customers that the following: do not select an alternative generation supplier as
- increased distribution sales volumes due to previously discussed. Standard offer service revenues warmer summer weather, increased usage per decreased in 2002 compared to 2001 primarily as a result customer, and an increased number of customers, of large commercial and industrial customers leaving
- cost reductions resulting from our corporate-wide BGE's standard offer service and electing other electric workforce reduction programs and other generation suppliers. These decreased revenues were productivity initiatives, and partially offset by increased sales to residential customers
- lower interest expense. due to warmer summer weather and an increase in the Net income from the regulated electric business standard offer service rate that BGE charges its decreased in 2001 compared to 2000 mostly because of customers.
the July 1, 2000 deregulation of electric generation as As a result of large commercial and industrial discussed later in this section. customers leaving BGE's service, BGE also had lower purchased energy expense as discussed in the Electric Fuel Electric Revenues and Purchased Energy Expenses section.
The changes in electric revenues in 2002 and 2001 Standard offer service revenues decreased in 2001 compared to the respective prior year were caused by: compared to 2000 mostly due to:
- the 6.5% annual residential rate reduction of 2002 2001 $17.6 million recorded through June 30, 2001, and (In millions)
- $74.4 million of higher CTC and Distribution sales volumes $ 32.7 $ 2.8 decommissioning revenues that were transferred Standard offer service (70.2) (79.3) to the merchant energy business effective July 1, Fuel rate surcharge (43.2) 30.5 2000.
Total change in electric revenues These decreases were partially offset by the increase from electric system sales (80.7) (46.0) in the standard offer service rate that BGE charges its Interchange and other sales - (53.8) customers and other net impacts of the rate restructuring Other 6.7 4.6 previously discussed.
Total change in electric revenues $ (74.0) $(95.2)
Fuel Rate Surcharge Prior to July 1, 2000, we deferred (included as an asset Distribution Sals Volumes or liability in our Consolidated Balance Sheets and "Distribution sales volumes" are sales to customers in excluded from our Consolidated Statements of Income)
BGE's service territory at rates set by the Maryland PSC. the difference between our actual costs of fuel and energy The percentage changes in our electric system sales and what we collected from customers under the fuel rate volumes, by type of customer, in 2002 and 2001 in a given period. Effective July 1, 2000, the fuel rate compared to the respective prior year were: clause was discontinued as a result of the deregulation of electric generation. In September 2000, the Maryland 2002 2001 PSC approved the collection of the $54.6 million Residential 8.0% 0.3% accumulated difference between our actual costs of fuel Commercial 3.2 0.7 and energy and the amounts collected from customers Industrial 0.7 (0.7) that were deferred under the electric fuel rate clause through June 30, 2000. We collected this accumulated In 2002, we distributed more electricity to difference from customers over the twelve-month period residential and commercial customers compared to 2001 ended October 2001.
due to warmer summer weather, increased usage per customer, and an increased number of customers. We Interchange and Other Saks distributed about the same amount of electricity to "Interchange and other sales" are sales in the PJM energy industrial customers in 2002 compared to 2001.
market and to others. PJM is a FERC approved RTO In 2001, we distributed about the same amount of that also operates a regional power pool with members electricity to all customer classes compared to 2000 due that include many wholesale market participants, as well primarily to milder winter weather offset by an increased as BGE and other utility companies. Prior to the number of customers.
implementation of customer choice, BGE sold energy to 47
_ _ _ _ _ - - ~~~~~~~~~~~~~~~~I
- 1 PJM members and to others after it had satisfied the Electric Operationsand Maintenance Expenses demand for electricity in its own system. Regulated electric operations and maintenance expenses Effective July 1, 2000, BGE no longer engages in decreased $6.3 million in 2002 compared to 2001 mostly interchange sales, as these activities are included in our due to cost reductions resulting from our corporate-wide merchant energy business, which resulted in a decrease in workforce reduction programs and other productivity interchange and other sales for 2001 compared to 2000. initiatives.
Regulated electric operations and maintenance Electrc Fuel and PurchasedEnergy Expenses expenses decreased $188.5 million during 2001 compared to 2000 mostly because effective July 1, 2000, costs of 2002 2001 2000 $194.7 million were no longer incurred by this business segment. These costs were associated with the electric (In millions) generation assets that were transferred to the merchant Actual costs $ 1,080.7 $1,150.5 $868.0 energy business.
Recovery of costs deferred under Workforce Reduction Cost electric fuel rate clause BGE's electric business recognized expenses associated
- 42.3 2.7 with our workforce reduction efforts as previously Total electric fuel and discussed in the Significant Events section and in Note 2.
purchased energy As a result of our workforce reduction programs and expenses $ 1,080.7 $1,192.8 $870.7 other process improvement initiatives, our electric business expects to realize cost savings of approximately Actual Costs $17 million partially offset by other increases in As discussed in the Business Environment-Electric operating costs in 2003.
Competition section, effective July 1, 2000, BGE transferred its generating assets to, and began purchasing Electric Depreciation and Amortization Expense substantially all of the energy and capacity required to Regulated electric depreciation and amortization expense provide electricity to standard offer service customers was about the same during 2002 compared to 2001.
from, the merchant energy business. Regulated electric depreciation and amortization expense Our actual costs of fuel and purchased energy decreased $146.6 million during 2001 compared to 2000 aecreased in 2002 compared to 2001 mosdy because mostly due to:
BGE purchased less energy due to large commercial and
- the absence of $75.0 million of amortization industrial customers leaving BGE's fixed price standard expense recorded in 2000 associated with the offer service and electing other electric generation $150 million reduction of our generating plants suppliers. as a result of the deregulation of electric Our actual costs of fuel and purchased energy generation, and increased in 2001 compared to 2000 mosdy because of * $75.1 million of expenses associated with the the deregulation of electric generation. The higher transfer of the generation assets to the merchant amount BGE paid for purchased energy from our energy business effective July 1, 2000.
merchant energy business is offset by the absence of
$206.4 million in 2001 in fuel costs, and lower Elkctric Taxes Other Than Income Taxes operations and maintenance, depreciation, taxes, and Regulated electric taxes other than income taxes were other costs at BGE as a result of no longer owning and about the same during 2002 compared to 2001.
operating the transferred electric generation plants. Regulated electric taxes other than income taxes decreased Prior to July 1, 2000, BGE's purchased fuel and $18.3 million during 2001 compared to 2000 mostly energy costs only included actual costs of fuel to generate due to the absence of taxes other than income taxes electricity (nuclear fuel, coal, gas, or oil) and electricity associated with the generation assets that were transferred we bought from others. to the merchant energy business effective July 1, 2000 partially offset by fewer tax credits.
48 I I
Regulated Gas Business Gas Revenues All BGE customers have the option to purchase gas from The changes in gas revenues in 2002 and 2001 compared other suppliers. To date, customer choice has not had a to the respective prior year were caused by:
material effect on our, or BGE's, financial results.
2002 2001 Net Income (In millions)
Distribution sales volumes $ 1.4 $ (3.4) 2002 2001 2000 Base rates (2.9) 3.3 (In millions) Weather normalization (0.5) 11.9 Revenues $ 581.3 $680.7 $611.6 Gas cost adjustments (55.8) 43.6 Gas purchased for resale Total change in gas revenues expenses 316.7 401.3 350.6 from gas system sales (57.8) 55.4 Operations and Off-system sales (38.8) 12.6 maintenance expenses 102.9 104.3 100.6 Other (2.8) 1.1 Workforce reduction costs 1.3 1.3 -
Depreciation and Total change in gas revenues $ (99.4) $69.1 amortization 47.4 47.7 46.2 Taxes other than income Distribution Sales Volumes taxes 34.4 34.3 34.8 The percentage changes in our distribution sales volumes, Income from Operations $ 78.6 $ 91.8 $ 79.4 by type of customer, in 2002 and 2001 compared to the respective prior year were:
Net Income $ 31.1 $ 37.5 $ 30.6 Net Income Before 2002 2001 Special Items Included Residential 3.5% (7.8)%
in Operations $ 31.9 $ 38.3 $ 30.6 Commercial 7.1 3.5 Workforce reduction Industrial (1.4) (25.2) costs (0.8) (0.8) -
We distributed more gas to residential and Net Income $ 31.1 $ 37.5 $ 30.6 commercial customers during 2002 compared to 2001 Above amounts include intercompany transactions eliminated mostly due to increased usage per customer, slightly in our ConsolidatedFinancialStatements. Note 3 provides a colder weather, and an increased number of customers.
reconciliation of operating results by segment to our We distributed less gas to industrial customers mosdy Consolidated FinancialStatements. because of a decreased number of customers.
We distributed less gas to residential customers Net income from our regulated gas business during 2001 compared to 2000 mosdy due to milder decreased during 2002 compared to 2001 mostly due to winter weather and lower usage per customer partially a $7.7 million pre-tax disallowed portion of a previously offset by an increased number of customers. We established regulatory asset as discussed in the Gas Cost distributed more gas to commercial customers mostly due Adjustments section and a $3.7 million pre-tax decrease in to higher usage per customer. We distributed less gas to the shareholders' portion of the sharing mechanism under industrial customers mostly because of lower usage due to our gas cost adjustment clauses.
customers switching to lower cost alternative fuel sources Net income from our regulated gas business and lower business needs related to the general downturn increased during 2001 compared to 2000 mostly due to in the economy, partially offset by an increased number a $3.6 million pre-tax increase in the shareholders' of custorers.
portion of the sharing mechanism under our gas cost adjustment clauses and an increase in our base rates.
Base Rates Base rate revenues decreased during 2002 compared to 2001 mostly because of a decrease in the rate approved by the Maryland PSC associated with the energy conservation surcharge program.
Base rate revenues increased during 2001 compared to 2000 mostly because the Maryland PSC authorized a
$6.4 million annual increase in our base rates effective June 22, 2000.
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I Il -L Weather Normalization However, we appealed the proposed order. As of the date The Maryland PSC allows us to record a monthly of this report, the Maryland PSC has not acted on BGE's adjustment to our gas revenues to eliminate the effect of appeal.
abnormal weather patterns on our gas system sales volumes. This means our monthly gas revenues are based 0ff-System Saks on weather that is considered "normal" for the month Off-system gas sales are low-margin direct sales of gas to and, therefore, are not affected by actual weather wholesale suppliers of natural gas outside our service conditions. territory. Off-system gas sales, which occur after we have satisfied our customers' demand, are not subject to gas Gas Cost Adjustments cost adjustments. The Maryland PSC approved an We charge our gas customers for the natural gas they arrangement for part of the margin from off-system sales purchase from us using gas cost adjustment clauses set by to benefit customers (through reduced costs) and the the Maryland PSC as described in Note 1. However, remainder to be retained by BGE (which benefits under market-based rates, our actual cost of gas is shareholders).
compared to a market index (a measure of the market Revenues from off-system gas sales decreased during price of gas in a given period). The difference between 2002 compared to 2001 mostly because we sold less gas our actual cost and the market index is shared equally at a lower price.
between shareholders and customers. The shareholders' Revenues from off-system gas sales increased during 2001 compared to 2000 mostly because the gas we sold portion decreased $3.7 million during 2002 compared to off-system was at a higher price partially offset by less gas 2001. The shareholders' portion increased $3.6 million sold. In the first half of 2001, the revenue increase during 2001 compared to 2000.
reflects the significant increase in natural gas prices.
Effective November 2001, the Maryland PSC approved an order that modifies certain provisions of the Gas PurchasedFor Resale Expenses market-based rates incentive mechanism. These provisions Gas purchased for resale expenses include the cost of gas require that BGE secure fixed-price contracts for at least purchased for resale to our customers and for off-system 10%, but not more than 20%, of forecasted system sales. These costs do not include the cost of gas supply requirements for the November through March purchased by delivery service customers.
period. These fixed price contracts are not subject to Gas costs decreased during 2002 as compared to sharing under the market-based rates incentive 2001 because we purchased gas at a lower price partially mechanism. We do not expect these changes to have a offset by the $7.7 million of disallowed fuel costs as material impact on our financial results.
previously discussed in the Gas Cost Adjustments section.
Delivery service customers are not subject to the gas Gas costs increased during 2001 compared to 2000 cost adjustment clauses because we are not selling gas to mostly because gas we purchased was at a higher price them. We charge these customers fees to recover the fixed partially offiet by less gas purchased for both system and costs for the transportation service we provide. These fees off-system sales.
are the same as the base rate charged for gas distributed and are included in gas distribution volumes.
Gas Operations and Maintenance Expenses Gas cost adjustment revenues decreased during 2002 Regulated gas operations and maintenance expenses were compared to 2001 mostly because the gas we sold to about the same during 2002 and 2001 compared to the non-delivery service customers was at a lower price, respective prior year. In 2002, cost reductions resulting partially offset by more gas sold. Gas cost adjustment from our corporate-wide workforce reduction programs revenues increased during 2001 compared to 2000 and other productivity initiatives were offset by the mostly because the gas we sold to non-delivery service amortization of gas regulatory assets established in 2001 customers was at a higher price, partially offset by less related to these initiatives.
gas sold. In the first half of 2001, the revenue increase reflects the significant increase in natural gas prices. Workforce Reduction Costs In December 2002, a Hearing Examiner from the BGE's gas business recognized expenses associated with Maryland PSC issued a proposed order related to our our workforce reduction efforts as previously discussed in annual gas adjustment clause review proceeding that will the Significant Events section and in Note 2.
allow us to recover $1.7 million of a previously As a result of our workforce reduction programs and established regulatory asset of $9.4 million for certain other process improvement initiatives, out gas business credits that were over-refunded to customers through our expects to realize cost savings of approximately $4 million market-based rates. BGE reserved the remaining partially offset by other increases in operating costs in difference of $7.7 million as disallowed fuel costs. 2003.
50 I .
Other Nonregulated Businesses Net income from our other nonregulated businesses Net Income increased during 2002 compared to 2001 mostly because of the following:
2002 2001 2000
- We recognized a $255.5 million pre-tax gain on (In millions) the sale of our investment in Orion in 2002.
Revenues $ 537.4 $552.6 $635.2
- We recorded impairment losses and other costs Operating expenses 505.9 510.7 588.8 in 2001 that had a negative impact in that year.
Workforce reduction costs 1.0 2.7 -
- We recognized a loss on the sale of our Impairment losses and other costs 10.8 111.9 -
Guatemalan operations in 2001 that had a Depreciation and negative impact in that year.
amortization 16.6 23.2 20.3
- We had higher earnings due to the growth of Taxes other than income our energy services business and improved results taxes 4.3 3.4 4.3 from our international portfolio.
Net gain on sales of investments and other These increases were partially offset by the assets 265.0 6.2 78.1 following:
Income (Loss) from
- We recognized gains on the sale of securities in Operations $ 263.8 $ (93.1) $ 99.9 2001 that had a positive impact in that year, Net Income (Loss) Before including the $14.9 million pre-tax gain on the Cumulative Effect of sale of one million shares of our Orion Change in Accounting investment and $34.6 million pre-tax gains on Principle $ 148.0 $ (99.1) $ 13.8 the sale of securities by our financial investments Cumulative Effect of Change in Accounting operation.
Principle - 8.5 -
- We recorded $9.5 million of pre-tax costs associated with the exit of BGE Home Net Income (Loss) $ 148.0 $ (90.6) $ 13.8 merchandise stores in 2002.
Net Loss Before Special
- We recorded impairment losses of $1.8 million Items Included in Operations $ (13.1) $ (26.8) $ (33.4) pre-ax related to certain non-core assets in 2002.
Net gain on sales of Net income from our other nonregulated businesses investments and other decreased during 2001 compared to 2000 mostly because assets 169.1 1.9 47.2 of the following items:
Workforce reduction costs (0.7) (1.7) -
- Our Latin American operation recorded a loss of Costs associated with $43.3 million pre-tax on the sale of our exit of BGE Home Guatemalan operations.
merchandise stores (6.1)
- We recorded impairment losses of $107.3 million Impairment of real estate, senior-living, pre-tax related to certain non-core assets.
and international
- Our financial investments operation recorded a investments (1.2) (69.7) - $4.6 million pre-tax reduction of its investment Reduction of financial in an aircraft due to the dedine in value of used investment - (2.8) -
airplanes as a result of the September 11, 2001 Net Income (Loss) Before terrorist attacks and the general downturn in the Cumulative Effect of Change in Accounting aviation industry.
Principle 148.0 (99.1) 13.8
- Our financial investments operation had lower Cumulative Effect of earnings due to lower gains on the sale of Change in Accounting securities and declining equity values in 2001 Principle - 8.5 -
compared to 2000.
Net Income (Loss) $ 148.0 $ (90.6) $ 13.8 We discuss our special items further in the Above amounts include intercompany transactions eliminated Significant Events section and in Note 2.
in our ConsolidatedFinancialStatements. Note 3 provides a In addition, we recognized an $8.5 million after-tax.
reconciliation of operating results by segment to our or $.05 per share, gain for the cumulative effect of Consolidated FinancialStatements. adopting SFAS No. 133 in the first quarter of 2001.
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As previously discussed in the Significant Events Other income for BGE increased $10.3 million section, we decided to sell certain non-core assets and during 2002 compared to 2001 mostly because of accelerate the exit strategies on other assets that we will interest income on temporary cash investments in the continue to hold and own over the next several years. Constellation Energy cash pool. Other income for BGE These assets included approximately 1,300 acres of land decreased $7.1 million during 2001 compared to 2000 holdings in various stages of development located in mostly due to the absence of income on the Calvert seven sites in the central Maryland region, an operating Cliffs decommissioning trust fund that was transferred to waste water treatment plant located in Anne Arundel our merchant energy business effective July 1, 2000 as a County, Maryland, all of our 18 senior-living facilities result of electric deregulation.
and certain international power projects. In 2002, we sold approximately 800 acres of land holdings, all of our FiRed Charges senior-living facilities, and a South American generating Total fixed charges increased $42.7 million during 2002 facility. While our intent is to dispose of these remaining compared to 2001 mostly because of a higher level of non-core assets, market conditions and other events debt outstanding at higher interest rates and lower beyond our control may affect the actual sale of these capitalized interest due to our new generating facilities assets. In addition, a future decline in the fair value of commencing operations. In 2002, we issued $2.5 billion these assets could result in additional losses. of long-term debt and used the proceeds to repay short-Our remaining projects are partially or substantially term borrowings, to prepay the Nine Mile Point sellers' developed. Our strategy is to hold and in some cases note, and to find acquisitions. Total fixed charges further develop these projects to increase their value. decreased $32.6 million during 2001 compared to 2000 However, if we were to sell these projects in the current mostly because of lower interest rates and higher market, we may have losses that could be material, capitalized interest associated with our construction of although the amount of the losses is hard to predict. new generating facilities. These decreases were offset In addition, we initiated a liquidation program for partially by a higher average level of debt outstanding.
our financial investments operation and expect to sell Total fixed charges for BGE decreased $14.0 million substantially all of our investments in this operation by during 2002 as compared to 2001 mostly because of a the end of 2003. Through February 28, 2003, we lower level of debt outstanding due to the repayment of liquidated approximately 85% of our investment maturing long-term debt. Total fixed charges for BGE portfolio since the beginning of 2002. decreased $29.4 million during 2001 compared to 2000 mostly because of a lower level of debt outstanding Consolidated Nonoperating Income and Expenses primarily due to the transfer of debt to our merchant Other Income energy business effective July 1, 2000 due to the Other income increased $29.2 million during 2002 implementation of electric deregulation.
compared to 2001 mostly because of interest income on the nuclear decommissioning trust find transferred in Income Taxes connection with the acquisition of Nine Mile Point and The differences in income taxes result from a income on temporary cash investments. Other income combination of the changes in income and the effective was about the same in 2001 compared to 2000. tax rate. We include an analysis of the changes in the effective tax rate in Note 9.
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Financial Condition The factors that credit rating agencies consider in Cash Flows establishing Constellation Energy's and BGE's credit Cash provided by operations was $1,020.0 million in ratings include, but are not limited to, cash flows, 2002 compared to $573.3 million in 2001 and $850.9 liquidity, and the amount of debt as a component of million in 2000. total capitalization. All Constellation Energy and BGE Cash used in investing activities was $319.8 credit ratings have stable outlooks. At the date of this million in 2002 compared to $1,472.7 million in 2001 report, our credit ratings were as follows:
and $1,106.5 million in 2000. The decrease in 2002 compared to 2001 was mostly due to the sale of Orion Standard and COPT that generated $555.4 million in cash & Poors Moody's proceeds, as well as the liquidation program associated Rating Investors Fitch-with our investment portfolio and a decrease in capital Group Service Ratings spending due to the termination of all planned Constellation Energy development projects. This was partially offset by the Commercial Paper A-2 P-2 F-2 acquisitions of NewEnergy (net of cash acquired) for Senior Unsecured
$204.8 million in September 2002 and of Alliance (net Debt BBB+ Baal A-of cash acquired) for $16.6 million in December 2002.
The increase in 2001 compared to 2000 was mostly BGE due to increased purchases of property, plant and Commercial Paper A-2 P-l F-I equipment and other capital expenditures including Mortgage Bonds A Al A+
$382.7 million relating to the net cash paid for the Senior Unsecured acquisition of Nine Mile Point. Debt BBB+ A2 A Cash used in financing activities was $157.6 Trust Originated million in 2002 compared to cash provided by Preferred financing activities of $789.1 million in 2001 and Securities and
$345.6 million in 2000. The decrease in 2002 Preference Stock BBB Baal A-compared to 2001 was mostly due to higher repayment of debt in 2002 and the issuance of common stock in Available Sources of Funding 2001. This was partially offset by higher issuance of In 2001, we decided to sell certain non-core assets to debt during 2002. The increase in 2001 compared to focus on our core strategies. During 2002, we realized 2000 was mostly due to increased proceeds from the proceeds of over $800 million from the sale of non-core issuance of common stock, an increase in proceeds from assets and used these funds to repay both short-term the net issuance of short-term borrowings, and a $130.0 and long-term debt. In addition, during 2002, we million decrease in common stock dividends paid. issued $2.5 billion of debt and established $1.28 billion These items were partially offset by the issuance of less of credit facilities resulting in $1.7 billion of total credit long-term debt and higher repayments of our long-term facilities. We continuously monitor our liquidity debt. requirements and believe that our facilities and access to the capital markets provide sufficient liquidity to meet Security Ratings our business requirements. We discuss our available Independent credit-rating agencies rate Constellation sources of funding in more detail below.
Energy's and BGE's fixed-income securities. The ratings indicate the agencies' assessment of each company's Constelation Energy ability to pay interest, distributions, dividends, and In addition to the $2.5 billion of debt issued in 2002, principal on these securities. These ratings affect how Constellation Energy has a commercial paper program much it will cost each company to sell these securities. under which we can issue short-term notes to fund our The better the rating, the lower the cost of the subsidiaries. At December 31, 2002, we had securities to each company when they sell them. approximately $1.5 billion of credit under three facilities as discussed below.
In June 2002, Constellation Energy arranged a
$640 million 364-day revolving credit facility and a
$640 million three-year revolving credit facility. We use these two facilities to allow issuance of commercial paper and letters of credit along with our previously established $188.5 million revolving credit facility that expires in June 2003.
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_________________ ____________ I - l 1 -L At December 31, 2002, we had $338.7 million of Our estimates are also subject to additional factors.
outstanding letters of credit that results in approximately Please see the Forward Looking Statements section.
$1.1 billion of unused credit fcilities. These three facilities can issue letters of credit up to approximately 2000 2001 2002 2003
$1.1 billion. Constellation Energy also has access to (In millions) interim lines of credit as required from time to time to Nonregulated Capital support its outstanding commercial paper. Requirements:
Merchant energy (excludes BGE BGE maintains $200.0 million in annual committed acquisitions) credit facilities, expiring May through November 2003, Construction program $ 537 $ 697 $122 $ -
in order to allow commercial paper to be issued. As of Steam generators 21 53 83 70 December 31, 2002, BGE had no outstanding Environmental controls 45 89 66 20 commercial paper, which results in $200.0 million in Continuing requirements unused credit facilities. BGE also has access to interim (including nuclear lines of credit as required from time to time to support fuel) 96(A) 205 370 320( B) its outstanding commercial paper.
Total merchant energy Other Nonregudated Businesses capital requirements 699 1,044 641 410 BGE Home Products & Services maintains a program Other nonregulated capital to sell up to $50 million of receivables. requirements 131 35 65 65 If we can get a reasonable value for our remaining Total nonregulated capital real estate projects and other investments, additional requirements 830 1,079 706 475 cash may be obtained by selling them. Our ability to sell or liquidate assets will depend on market Utility Capital conditions, and we cannot give assurances that these Requirements:
sales or liquidations could be made. Regulated electric Generation 73 - _ _
Capital Resources Steam generators 13 - - -
Our business requires a great deal of capital. Our actual Environmental controls 17 - - -
consolidated capital requirements for the years 2000 Transmission and through 2002, along with the estimated annual amount distribution 187 180 167 205 for 2003, are shown in the table below.
We will continue to have cash requirements for: Total regulated electric 290 180 167 205
- working capital needs, Regulated gas 60 59 50 55
- payments of interest, distributions, and Total utility capital dividends, requirements 350 239 217 260
- capital expenditures, and Total capital requirements $1,180 $1,318 $923 $735
- the retirement of debt and redemption of preference stock.
(A) Effective July 1, 2000, includes $44.6 million for Capital requirements for 2003 and 2004 include estimates of spending for existing and anticipated electric generation and nuclear fuel formerly part of projects. We continuously review and modify those BGE's regulated electric business.
estimates. Actual requirements may vary from the (B) Exdudes capital requirements and financing costs estimates included in the table below because of a for the High Desert Power Project, which are number of factors including.
estimated to be approximately $90 million for the
- regulation, legislation, and competition, full year of 2003.
- BGE load requirements,
- environmental protection standards, Certainprior-year amounts have been reclassified to
- the tpe and number of projects selected for conform to the curentyearr presentation.
construction or acquisition, As of the date of this report, we have not
- the effect of market conditions on those completed our 2004 capital budgeting process, but projects, expect our 2004 capital requirements to be
- the cost and availability of capital, and approximately $600-700 million.
- the availability of cash from operations.
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Capital Requirements The High Desert Power Project uses an off-balance Merchant Energy Business sheet financing structure through this SPE and currently Our merchant energy business will invest in the qualifies as an operating lease. As an operating lease, we following. do not record any assets or debt associated with the
- Costs for replacing the steam generators at Calvert project in our Consolidated Balance Sheets. In January Cliffs. In March 2000, we received a license 2003, the FASB issued Interpretation No. (FIN) 46, extension from the NRC that extends Ca1vert Consolidation of Variable Interest Entities, that will impact Cliffi' operating licenses to 2034 fr Unit I and the accounting for, but not the cash flows associated 2036 for Unit 2. Replacement of the steam with, our High Desert operating lease and the related generators will allow us to operate these units SPE. Under the interpretation and current lease structure, through our operating license periods. The 2002 we will be required to consolidate the SPE in our steam generator replacement for Unit I was Consolidated Balance Sheets as of July 1, 2003, which is completed at the end of June 2002. We expect the the effective date of FIN 46. Had we consolidated this 2003 steam generator replacement to occur during project at December 31, 2002, we would have recorded the 2003 refueling outage for Unit 2. approximately $488.7 million of development,
- Continuing requirements, including construction construction, and capitalized financing costs as an asset expenditures for improvements to generating and the related financial obligations as a liability in our plants, nuclear fuel costs, costs of complying Consolidated Balance Sheets. We discuss FIN 46 in more with the Environmental Protection Agency detail in Note 1.
(EPA), Maryland, and Pennsylvania nitrogen The lease with the Trust contains several events of oxides (NOx) emissions regulations, and default that are commonly found in financings of this enhancements to our information technology type, including failure to make all payments when due, infrastructure. We discuss the NOx regulations failure to comply with all covenants, violation of material and timing of expenditures in Note 11. representations and warranties and change of control. In The table on the previous page does not include the addition, several events of default are applicable to us as financing for the High Desert 830 megawatt gas-fired guarantor, including defaults in other material financing generation project in California, which is under an agreements and failure to own 100% of BGE's common operating lease with a term through February 2006. stock.
Under the terms of the lease, we are required to make At the conclusion of the lease term in 2006, we payments that represent all or a portion of the lease have the following options:
balance if construction is terminated prior to completion
- renew the lease upon approval of the lessors, or we default under the lease.
- elect to purchase the property for a price equal Under certain circumstances, we may be required to to the lease balance at the end of the term, or either post cash collateral equal to the outstanding lease
- request the lessor to sell the property.
balance or we may elect to purchase the property for the If the lessor sells the property, we guarantee the outstanding lease balance. At any time during the term payment of any difference between the sale proceeds and of the lease we have the right to pay off the lease and the lease balance at the time of sale up to a maximum acquire the asset from the lessor. At December 31, 2002, amount of approximately 83% of such lease balance. The the outstanding lease balance plus other committed lease balance at the end of the term is currently expenses was approximately $585 million. estimated to be $600 million, which represents the Our wholly owned subsidiary, High Desert Power estimated cost of the project; however, this may vary Project LLC, is supervising the construction of, and based on the ultimate cost of construction and interest leasing, the High Desert project from High Desert Power incurred during the construction period.
Trust, an independent special purpose entity (SPE) created to own and lease the project to our subsidiary. Reguated Electric and Gas Neither Constellation Energy nor any affiliate owns any Regulated electric and gas construction expenditures equity or other interest in High Desert Power Trust, primarily include new business construction needs and which is owned by a consortium of banks and other improvements to existing facilities.
financial institutions. We provide a guaranty of High Desert Power Project LLC's obligations to the Trust.
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______-- - - I.- I Funding for Capital Requirements Committed Amounts Merchant Energy Business Our total contractual and contingent obligations as of Funding for the expansion of our merchant energy December 31, 2002 are shown in the following table:
business is expected from internally generated funds. We also have available sources from commercial paper Payments/Expiration issuances, issuances of long-term debt and equity, leases, 2004- 2006-2003 2005 2007 Thereafter Total and other financing activities. (In millions)
The projects that our merchant energy business Contractual Obliatioms develops typically require substantial capital investment. Short-term borrowings S 10.5 S - - $ - S 10.5 Most of the projects recently constructed were funded Nonregulated long-term debt' 5.5 315.6 620.1 2,208.6 3,149.8 through corporate borrowings by Constellation Energy. BGE long-term debt 284.2 194.7 591.4 829.7 1,900.0 Many of the qualifying facilities and independent power BGE preference stock - - - 190.0 190.0 projects that we have an interest are financed primarily Fuel and with non-recourse debt that is repaid from the project's transportation 626.9 316.9 145.2 94.2 1,183.2 Purchased capacity and cash flows. This debt is collateralized by interests in the energy' 182.8 160.7 46.5 73.1 463.1 physical assets, major project contracts and agreements, Operating leases 34.6 103.7 38.0 151.6 327.9 cash accounts and, in some cases, the ownership interest Capital and loan in that project. commitments 32.7 0.5 - - 33.2 We expect to fund acquisitions with a mixture of Total contractual debt and equity with an overall goal of maintaining a obligations $1,177.2 $1,092.1 $1,441.2 $3,547.2 S 7,257.7 strong investment grade credit profile. Contingent Obligations Letters of credit S 338.3 $ 0.4 $ - $ - S 338.7 Guarantees -
BGE competitive supply 1,758.8 167.0 35.8 189.4 2,151.0 Funding for utility capital expenditures is expected from Other guarantes, net 16.5 2.2 602.1 140.8 761.6 internally generated funds. During 2003, we expect our Total contingent regulated utility business to generate significant excess obligations $2,113.6$ 169.6$ 637.9 $ 330.2 $ 3,251.3 cash flows from operations. If necessary, additional Total obligations $3,290.8 $1,261.7 $2,079.1 $3,877.4 $10,509.0 funding may be obtained from commercial paper issuances, available capacity under credit facilities, the I Amounts refcted in lngterm debt maturities do nor include $394.3 issuance of long-term debt, trust securities, or preference million investors may requirrus to rpay early through put options and remarketingfeatures.
stock, and/or from time to time equity contributions 2 Our contractualobligations for purchasedcapacity and energy are shown from Constellation Energy. During 2002, Constellation on a gros basisfor certain transactions. including contracts in Texas that Energy made a $200 million capital contribution to ure re-d-signated and NewEnergy BGE. BGE also participates in a cash pool administered 3 Amounts related to capital expenditures are includedfor applicableyears in our capital requirements tabk.
by Constellation Energy as discussed in Note 15. 4 While the face amount of these guarantees is $2.151. 0 million, we do not expect to fund the full amount as our calulation of the fair value of Other Nonregslated Businesses obligations covred by these guarantees was $519.8 million as Funding for our other nonregulated businesses is December 31. 2002.
5 Other guarantees in the above table are shown net of liabilities rcordedat expected from internally generated funds, commercial December 31, 2002 in our Consolidated Balance Sheets. The 2006 paper issuances, issuances of long-term debt of amount shown in the table primarily relates to the High Desert lease.
Constellation Energy, sales of securities and assets, and/or from time to time equity contributions from While we included our contingent obligations in the Constellation Energy. BGE Home Products & Services table above, these amounts do not represent incremental can continue to fund capital requirements through sales consolidated Constellation Energy obligations; rather, of receivables. they primarily represent guarantees from one Our ability to sell or liquidate securities and non- Constellation entity to another. We do not expect to core assets will depend on market conditions, and we fund the full amounts under the letters of credit and cannot give assurances that these sales or liquidations guarantees. Specifically, the $2,151.0 million could be made. We discuss our remaining non-core assets guarantees-competitive supply represent the face and market conditions in the Results of Operation-Other amount of these guarantees. However, we do not expect NonregulatedBusinesses section. to fund the full amount, as our calculation of the fair value of obligations covered by these guarantees was
$519.8 million at December 31, 2002.
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Lease payments under the High Desert operating The credit facilities of Constellation Energy and lease are reflected in "Other guarante !es, net" in the table BGE have limited material adverse change dauses that on the previous page. The lease balarice at the end of the only consider a material change in financial condition 2006 lease term is currendy estimateiI to be $600 and are not direcdy affected by decreases in credit million. ratings. If these clauses are violated, the lending The table on the previous page does not include the institutions can decline making new advances or issuing fixed payment portions of our mark- to-market energy new letters of credit, but cannot accelerate existing assets and liabilities primarily related to capacity amounts outstanding. The long-term debt indentures of payments under tolling contracts. We discuss the Constellation Energy and BGE do not contain material expected settlement terms of these cc'ntracts in the adverse change clauses or financial covenants.
Competitive Supply-Mark-to-Market Energy Assets and Certain credit facilities of Constellation Energy contain Liabilities section. a provision requiring Constellation Energy to maintain a ratio of debt to capitalization equal to or less than 65%. At Liquidity Provisions December 31, 2002, the debt to capitalization ratios as We have certain agreements that con tain provisions that defined in the credit agreements were no greater than 57%.
would require additional collateral uf)on significant credit A BGE credit facility of $50.0 million that expires rating decreases in the Senior Unsecuired Debt of in August 2003 requires BGE to maintain a ratio of debt Constellation Energy. Decreases in Constellation Energy's to capitalization equal to or less than 70%. At December credit ratings would not trigger an eaarly payment on any 31, 2002, the debt to capitalization ratio for BGE as of our credit facilities. However, und,er counterparty defined in the credit agreement was 54%. At December contracts related to our origination atnd risk management 31, 2002, no amount is outstanding under this facility.
operation, where we are obligated to post collateral, we Failure by Constellation Energy, or BGE, to comply estimate that we would have additior nal collateral with these covenants could result in the maturity of the obligations based on downgrades to the following credit debt outstanding under these facilities being accelerated.
ratings for our Senior Unsecured Delbt- The credit facilities of Constellation Energy contain usual and customary cross-default provisions that apply to Level Below defaults on debt by Constellation Energy and certain Credit Ratings Current Incr Rating Obl iemental Cumulative subsidiaries over a specified threshold. Certain BGE Downgraded iao lgto credit facilities also contain usual and customary cross-(In mnillions) default provisions that apply to defaults on debt by BGE BBB/Baa2 BBB-/Baa3 2 155 180 over a specified threshold. The indentures pursuant to Below investment which BGE has issued and outstanding mortgage bonds grade 3 500 680 and subordinated debentures provide that a default under any debt instrument issued under the relevant indenture At December 31, 2002, we had approximately $1.3 may cause a default of all debt outstanding under such billion of unused credit facilities and $615.0 million of indenture.
cash available to meet potential requi rements. However, Constellation Energy also provides credit support to based on market conditions and conitractual obligations Calvert Cliffs and Nine Mile Point to ensure these plants at the time of such a downgrade, we could be required have funds to meet expenses and obligations to safely to post collateral in an amount that could exceed the operate and maintain the plants.
amounts specified above, and which could be material. We discuss our short-term borrowings in Note 7, In many cases, customers of outr origination and risk long-term debt in Note 8, lease requirements in Note 10, management operation rely on the crreditworthiness of and commitments and guarantees in Note 11.
Constellation Energy. A decline beloi v investment grade by Constellation Energy would negat ively impact the business prospects of that operation.
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________________- - I l.-- -
Market Risk Interest Rate Risk We are exposed to various market risks, including We are exposed to changes in interest races as a result of changes in interest rates, certain commodity prices, credit financing through our issuance of variable-rate and fixed-risk, and equity prices. To manage our market risk, we rate debt. We may use derivative instruments to manage may enter into various derivative instruments including our interest rate risks. The following table provides swaps, forward contracts, futures contracts, and options. information about our debt obligations that are sensitive In this section, we discuss our current market risk and to interest rate changes:
the related use of derivative instruments.
Principal Payments and Interest Rate Detail by ContractualMaturity Date Fair value at 2003 2004 2005 2006 2007 Thereafter Total Dec. 31, 2002 (Dollar amounts in milions)
Short-term debt Variable-rate debt $ 10.5 $ - S - $ - $ - $ - $ 10.5 $ 10.5 Average interest rate 3.61% - 3.61%
Long-term debt Variable-rate debt $ 5.0 $ 7.0 $ 7.5 $120.6 $ 10.0 $ 185.8 $ 335.9 $ 335.9 Average interest rate 5.49% 5.45% 5.50% 1.75% 5.50% 1.76% 2.08%
Fixed-rate debt $284.7(A) $152.0 $343.8 $352.8 $728.1 $2,852.5 $4,713.9 $5,018.8 Average interest rate 6.50% 5.75% 7.72% 5.54% 7.00% 6.90% 6.74%
(A) Amount excludes $136.5 million of long-term debt that contains certain put options under which knders could potentially require us to repay the debt prior to maturity and is classified as currentportion of long-term debt in our Consolidated Balance Sheets.
Commodity Risk Commodity Prices We are exposed to the impact of market fluctuations in Commodity price risk arises from the potential for the price and transportation costs of electricity, natural changes in the price of, and transportation costs for, gas, coal, and other commodities. These risks arise from electricity, natural gas, coal, and other commodities; the our ownership and operation of power plants, the load- volatility of commodity prices; and changes in interest serving activities of BGE standard offer service and our rates. A number of factors associated with the structure competitive supply activities, and our mark-to-market and operation of the electricity markets significandy origination and risk management activities. We discuss influence the level and volatility of prices for energy these risks separately for our merchant energy and our commodities and related derivative products. We use regulated businesses below. such commodities and contracts in our merchant energy business, and if we have not hedged the associated Merchant Energy Business financial exposure, this price volatility could affect our Our merchant energy business is exposed to various earnings. These factors include:
risks in the competitive marketplace that may materially
- seasonal daily and hourly changes in demand, impact its financial results and affect our earnings.
- extreme peak demands due to weather These risks include changes in commodity prices, conditions, imbalances in supply and demand, and operational risk. + available supply resources,
- transportation availability and reliability within and between regions,
- procedures used to maintain the integrity of the physical electricity system during extreme conditions, and
- changes in the nature and extent of federal and state regulations.
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These factors can affect energy commodity and Additionally, if one or more of our generating derivative prices in different ways and to different facilities is not able to produce electricity when required degrees. These effects may vary throughout the country due to operational factors, we may have to forego sales as a result of regional differences in: opportunities or fulfill fixed-price sale commitments
- weather conditions, through the operation of other more costly generating
- market liquidity, facilities or through the purchase of energy in the
- capability and reliability of the physical wholesale market at higher prices.
electricity and gas systems, and Our nuclear plants produce electricity at a
- the nature and extent of electricity deregulation. relatively low marginal cost. As a result, the costs of replacement energy associated with outages at these Supply and Demand Risk plants can be significant. If an unplanned outage were We are exposed to the risk that available sources of to occur during the summer or winter when demand supply may differ from the amount of power demanded was at a high level, the replacement power costs could by our customers under fixed-price load-serving have a material adverse impact on our financial results.
contracts. During periods of high demand, our power Calvert Cliffs experienced an extended outage to replace supplies may be insufficient to serve our customers' the steam generators for Unit I during a refueling needs and could require us either to generate power outage in the spring of 2002, and will experience using plants with more costly fuel or to purchase another extended outage to replace the steam generators additional energy at higher prices. Alternatively, during for Unit 2 during a refueling outage in the spring 2003.
periods of low demand, our power supplies may exceed our customers' needs and could result in us selling that Risk Management excess energy at lower prices. Either of those As part of our overall portfolio, we manage the circumstances could have a negative impact on our commodity price risk of our competitive supply earnings. activities and our electric generation facilities, including power sales, fuel and energy purchases, emission credits, OperationalRisk weather risk, and the market risk of outages. In order to Operational risk is the risk that a generating plant will manage these risks, we may enter into fixed-price not be available to produce energy and the risks related derivative or non-derivative contracts to hedge the to physical delivery of energy to meet our customers' variability in future cash flows from forecasted sales of needs. For 2003, we expect to use the majority of the electricity and purchases of fuel and energy, including:
generating capacity controlled by our merchant energy
- forward contracts, which commit us to business to provide standard offer service to BGE or to purchase or sell energy commodities in the serve the load requirements of the sellers of Nine Mile future; Point. Beginning in July 2002, approximately 1,200
- futures contracts, which are exchange-traded megawatts of industrial customer load moved from standardized commitments to purchase or sell a BGE's standard offer service to market-based rates. commodity or financial instrument, or to make Going forward, our merchant energy business will a cash settlement, at a specific price and future supply 100% of the standard offer service to BGE date; through June 30, 2003 and 90% from July 1, 2003
- swap agreements, which require payments to or through June 30, 2006. from counterparties based upon the differential As a result of declines in BGE's standard offer between two prices for a predetermined service load and the 2,900 megawatts of natural gas- contractual (notional) quantity; and fired peaking and combined cyde generating facilities
- option contracts, which convey the right to buy recently constructed, we have a substantial amount of or sell a commodity, financial instrument, or generating capacity that is subject to future changes in index at a predetermined price.
wholesale electricity prices and have fuel requirements that are subject to future changes in coal, natural gas, and oil prices. Our power generation facilities purchase fuel under contracts or on the spot market. Fuel prices may be volatile and the price that can be obtained from power sales may not change at the same rate as changes in fuel costs.
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I I __
The objectives for entering into such hedges The value at risk calculation does not include include: market risks associated with activities that are subject to
- fixing the price for a portion of anticipated accrual accounting, primarily our generating facilities future electricity sales at a level that provides an and our competitive supply load-serving activities. We acceptable return on our electric generation manage these risks by monitoring our fuel and energy operations, purchase requirements and our estimated contract sales
- fixing the price of a portion of anticipated fuel volumes compared to associated supply arrangements.
purchases for the operation of our power We also engage in hedging activities to manage these plants, and risks. We describe those risks and our hedging activities
- fixing the price for a portion of anticipated earlier in this section.
energy purchases to supply our load-serving The value at risk amount represents the potential customers. pre-tax loss in the fair value of mark-to-market energy The portion of forecasted transactions hedged may assets and liabilities over a one-day holding period.
vary based upon management's assessment of market, Based on the confidence levels in the table below, we weather, operational, and other fctors. would expect a one-day change in fair value greater While some of the contracts we use to manage risk than or equal to the daily value at risk at least once per represent commodities or instruments for which prices year. Our value at risk was as follows:
are available from external sources, other commodities and certain contracts are not actively traded and are 99.9% 95%
Confidence Confidence valued using other pricing sources and modeling Level Level techniques to determine expected future market prices, Year Ended December 31, 2002 2001 2002 2001 contract quantities, or both. We use our best estimates (In millions) to determine the fair value of commodity and derivative Year end $ 7.4 $18.0 $ 3.0 $ 74 contracts we hold and sell. These estimates consider Average 15.5 18.0 6.4 7.5 various factors including closing exchange and over-the- High 33.8 68.9 13.9 26.9 counter price quotations, time value, volatility factors, Low 4.2 8.7 1.7 3.6 and credit exposure. However, it is likely that future The high value at risk amount for the year 2001 market prices could vary from those used in recording represents certain hedge contracts entered into in mark-to-market energy assets and liabilities, and such anticipation of closing an offsetting transaction. When variations could be material. the offsetting transaction closed within several days, the We monitor and manage our risk exposures value at risk amount returned to a level more through separate, but complementary financial, representative of the average for the year.
operational, and credit reporting systems. Constellation Due to the inherent limitations of statistical Energy's board of directors establishes parameters for the measures such as value at risk, the relative immaturiry risks that we can undertake and risk levels are of the competitive market for electricity and related monitored daily by management and our Chief Risk derivatives, and the seasonality of changes in market Officer. In addition, we maintain segregation of duties, prices, the value at risk calculation may not reflect the with credit review and risk monitoring functions full extent of our commodity price risk exposure.
performed by groups that are independent from revenue Additionally, actual changes in the value of options may producing groups. differ from the value at risk calculated using a linear We measure the sensitivity of our mark-to-market approximation inherent in our calculation method. As a energy contracts to potential changes in market prices result, actual changes in the fair value of mark-to-using value at risk. Value at risk is a statistical model market energy assets and liabilities could differ from the that attempts to predict risk of loss based on historical calculated value at risk, and such changes could have a market price volatility. We calculate value at risk using a material impact on our financial results.
variance/covariance technique that models option positions using a linear approximation of their value.
Regulated Electric Business Additionally, we estimate variances and correlation using Effective July 1, 2000, BGE's residential rates are frozen historical commodity price changes over the most recent for a six-year period, and its commercial and industrial rolling three-month period. Our value at risk calculation rates are frozen for four to six years. BGE entered into includes all mark-to-market energy assets and liabilities, standard offer service arrangements with our origination including contracts for energy commodities and and risk management operation and Allegheny Energy derivatives that result in physical settlement and Supply Company to provide the energy and capacity contracts that require cash settlement.
required to meet its standard offer service obligations through June 30, 2006.
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Regulated Gas Business Due to the possibility of extreme volatility in the Our regulated gas business may enter into gas futures, prices of energy commodities and derivatives, the options, and swaps to hedge its price risk under our market value of contractual positions with individual market-based rate incentive mechanism and our off- counterparties could exceed established credit lmits or system gas sales program. We discuss this further in collateral provided by those counterparties. If such a Note 1. At December 31, 2002 and 2001, our exposure counterparty were then to fail to perform its obligations to commodity price risk for our regulated gas business under its contract (for example, fail to deliver the was not material. electricity our origination and risk management operation had contracted for), we could sustain a loss Credit Risk that could have a material impact on our financial We are exposed to credit risk, primarily through our results.
merchant energy business. Credit risk is the loss that Additionally, if a counterparty were to default and may result from a counterparry's nonperformance. We we were to liquidate all contracts with that entity, our use credit policies to manage our credit risk, including credit loss would include the loss in value of mark-to-utilizing an established credit approval process, market contracts, the amount owed for settled monitoring counterparty limits, employing credit transactions, and additional payments, if any, we would mitigation measures such as margin, collateral, or have to make to settle unrealized losses on accrual prepayment arrangements, and using master netting contracts.
agreements. We measure credit risk as the replacement cost for open energy commodity and derivative Equity Price Risk positions (both mark-to-market and accrual) plus We are exposed to price fluctuations in equity markets amounts owed from counterparties for settled primarily through our financial investments operation, transactions. The replacement cost of open positions our pension plan assets, and our nuclear represents unrealized gains, net of any unrealized losses, decommissioning trust funds. We are required by the where we have a legally enforceable right of setoff. NRC to maintain an externally funded trust for the Recently, several major participants in the energy costs of decommissioning our nuclear power plants. We markets suffered severe declines in their credit ratings or discuss our nuclear decommissioning trust funds in declared bankruptcy. However, as of December 31, more detail in Note 1.
2002, approximately 85% of our credit portfolio was A hypothetical 10% decrease in equity prices rated at least investment grade by the major rating would result in an approximate $65 million reduction agencies, with 3% rated below investment grade and in the fair value of our financial investments that are 12% not rated. Of the portion not rated, 84% classified as trading or available-for-sale securities. In primarily represents governmental entities, 2002, the value of our defined benefit pension plan municipalities, cooperatives, power pools, or other load- assets decreased by approximately $90 million due to serving entities that we assess are equivalent to declines in the markets in which plan assets are investment grade based on internal credit ratings. invested. We describe our financial investments in more detail in Note 4, and our pension plans in Note 6.
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 11 of this Form 10-K under the heading Market Risk.
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-I Item S. Flnancial Statements and Supplementary Data I.I . ^sfA l The management of Constellation Energy and BGE The Audit Committee of the Board of Directors, which (Companies) is responsible for the information and consists of three independent Directors, meets periodically with representations in the Companies' financial statements. The management, internal auditors, and PricewaterhouseCoopers LLP Companies prepare the financial statements in accordance with to review the activities of each in discharging their accounting principles generally accepted in the United States of responsibilities. The internal audit staff and America based upon available facts and circumstances and PricewaterhouseCoopers LLP have free access to the Audit management's best estimates and judgments of known Committee.
conditions.
The Companies maintain an accounting system and related system of internal controls designed to provide reasonable assurance that the financial records are accurate and that the Companies' assets are protected. The Companies' staff of internal auditors, which reports directly to the Chief Financial Officer, conducts periodic reviews to maintain the effectiveness of internal control procedures. PricewaterhouseCoopers LLP, Mayo A. Shattuck III E. Follin Smith independent accountants, audit the financial statements and Chairman of the Board, Senior Vice-President 6&
express their opinion on them. They perform their audit in Presidentand Chief ChiefFinancialOfficer accordance with auditing standards generally accepted in the Executive Officer United States of America.
-.-. , SI Ubfvg . - j,k To the Shareholders of Constellation Energy Group, Inc. and capitalization of Constellation Energy Group, Inc. and Baltimore Gas and Electric Company Subsidiaries and of Baltimore Gas and Electric Company and In our opinion, the consolidated financial statements listed in Subsidiaries as of December 31, 2000, 1999 and 1998, and the the index appearing under Item 15(a) 1. present fairly, in all related consolidated statements of income, cash flows, and material respects, the financial position of Constellation Energy common shareholders' equity and comprehensive income for the Group, Inc. and Subsidiaries and of Baltimore Gas and Electric years ended December 31, 1999 and 1998 (none of which are Company and Subsidiaries at December 31, 2002 and 2001, presented herein); and we expressed unqualified opinions on and the results of their operations and their cash flows for each those consolidated financial statements. In our opinion, the of the three years in the period ended December 31, 2002 in information set forth in the Summary of Operations and Summary of Financial Condition of Constellation Energy conformity with accounting principles generally accepted in the Group, Inc. included in the Selected Financial Data for each of United States of America. In addition, in our opinion, the the five years in the period ended December 31, 2002, and the financial statement schedule listed in the index appearing under information set forth in the Summary of Operations and Item 15(a) 2. of this Form 10-K presents fairly, in all material Summary of Financial Condition of Baltimore Gas and Electric respects, the information set forth therein when read in Company included in the Selected Financial Data for each of conjunction with the related consolidated financial statements.
the five years in the period ended December 31, 2002, is fairly These financial statements and the financial statement schedule stated, in all material respects, in relation to the consolidated are the responsibility of the Companies' management; our financial statements from which it has been derived.
responsibility is to express an opinion on these financial As discussed in Note I to the consolidated financial statements and financial statement schedule based on our audits.
statements, in 2001, the Companies changed their method of We conducted our audits of these statements in accordance with accounting for derivative and hedging activities pursuant to auditing standards generally accepted in the United States of Statement of Financial Accounting Standards No. 133, America, which require that we plan and perform the audit to Accountingfor Derivative Instruments and Hedging Activities, as obtain reasonable assurance about whether the financial amended by Statement of Financial Accounting Standards statements are free of material misstatement. An audit includes No. 138, Accounting for Certain Derivative Instruments and examining, on a test basis, evidence supporting the amounts and Certain Hedging Activities (an amendment of FASB Statement disclosures in the financial statements, assessing the accounting No. 133).
principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
We have also previously audited, in accordance with PricewaterhouseCoopers LLP auditing standards generally accepted in the United States of Baltimore, Maryland America, the consolidated balance sheets and statement of January 29, 2003 62
Constellation Energy Group, Inc. and Subsidiaries Year Ended December 31, 2002 2001 2000 (In millions, except per share amounts)
Revenues Nonregulated revenues $2,166.9 $1,164.9 $1,035.9 Regulated electric revenues 1,965.6 2,039.6 2,134.7 Regulated gas revenues 570.5 674.3 603.8 Total revenues 4,703.0 3,878.8 3,774.4 Expenses Operating expenses 3,049.9 2,392.2 2,311.4 Workforce reduction costs 62.8 105.7 7.0 Impairment losses and other costs 25.2 158.8 Contract termination related costs - 224.8 Depreciation and amortization 481.0 419.1 470.0 Taxes other than income taxes 259.2 226.6 221.5 Total expenses 3,878.1 3,527.2 3,009.9 Net Gain on Sales of Investments and Other Assets 261.3 6.2 78.1 Income from Operations 1,086.2 357.8 842.6 Other Income 30.5 1.3 4.2 Fixed Charges Interest expense 312.3 283.2 282.4 Interest capitalized and allowance for borrowed funds used during construction (44.0) (57.6) (24.2)
BGE preference stock dividends 13.2 13.2 13.2 Total fixed charges 281.5 238.8 271.4 Income Before Income Taxes 835.2 120.3 575.4 Income Taxes 309.6 37.9 230.1 Income Before Cumulative Effect of Change in Accounting Principle 525.6 82.4 345.3 Cumulative Effect of Change in Accounting Principle, Net of Income Taxes of $5.6 (see Note 1) - 8.5 Net Income $ 525.6 $ 90.9 $ 345.3 Earnings Applicable to Common Stock $ 525.6 $ 90.9 $ 345.3 Average Shares of Common Stock Outstanding 164.2 160.7 150.0 Earnings Per Common Share and Earnings Per Common Share-Assuming Dilution Before Cumulative Effect of Change in Accounting Principle $ 3.20 $ .52 $ 2.30 Cumulative Effect of Change in Accounting Principle - .05 Earnings Per Common Share and Earnings Per Common Share-Assuming Dilution $ 3.20 $ .57 $ 2.30 See Notes to ConsolidatedFinancial Statements.
Certain prior-year amounts have been reclassifiedto conform with the current years presentation.
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Constellation Energy Group, Inc. and Subsidiaries At December 31, 2002 2001 (In millions)
Assets Current Assets Cash and cash equivalents $ 615.0 S 72.4 Accounts receivable (net of allowance for uncollectibles of $41.9 and $22.8, respectively) 1,247.3 738.9 Trading securities 77.1 178.2 Mark-to-market energy assets 144.0 398.4 Risk management assets 72.3 65.2 Fuel stocks 126.5 110.2 Materials and supplies 208.6 210.2 Prepaid taxes other than income taxes 57.1 64.7 Other 153.9 58.0 Total current assets 2,701.8 1,896.2 Investments and Other Assets Real estate projects and investments 86.1 210.7 Investments in qualifying facilities and power projects 439.2 499.1 Investment in Orion Power Holdings, Inc. - 442.5 Financial investments 36.9 60.7 Nuclear decommissioning trust funds 645.4 683.5 Mark-to-market energy assets 1,348.2 1,819.8 Risk management assets 88.8 77.6 Goodwill 115.9 -
Other 167.8 132.8 Total investments and other assets 2,928.3 3,926.7 Property, Plant and Equipment Regulated property, plant and equipment Plant in service 4,952.4 4,862.4 Construction work in progress 118.3 81.8 Plant held for future use . 4.5 4.5 Total regulated property, plant and equipment 5,075.2 4,948.7 Nonregulated generation properry, plant and equipment 6,811.9 6,538.7 Other nonregulated propert, plant and equipment 242.0 192.9 Nuclear fuel (net of amortization) 224.8 174.8 Accumulated depreciation (4,396.8) (4,161.8)
Net property, plant and equipment 7,957.1 7,693.3 Deferred Charges Regulatory assets (net) 405.7 463.8 Other 136.0 129.4 Total deferred charges 541.7 593.2 Total Assets $14,128.9 $14,109.4 See Notes to ConsolidatedFinancialStatements.
Certain prior-year amounts have been reclassified to conform with the currentyears presentation.
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- . e Constellation Energy Group, Inc. and Subsidiaries I I I I I At December 31, 2002 2001 (In millions)
Liabilties and Equity Current Liabilities Short-term borrowings $ 10.5 $ 975.0 Current portion of long-term debt 426.2 1,406.7 Accounts payable 943.4 523.3 Mark-to-market energy liabilities 94.1 323.3 Risk management liabilities 20.1 11.7 Dividends declared 42.8 23.0 Accrued interest 95.5 57.7 Other 392.8 250.4 Total current liabilities 2,025.4 3,571.1 Deferred Credits and Other Liabilities Deferred income taxes 1,330.7 1,431.0 Mark-to-market energy liabilities 881.5 1,476.5 Risk management liabilities 149.5 12.5 Net pension liability 334.6 215.5 Postretirement and postemployment benefits 352.8 330.9 Deferred investment tax credits 85.7 93.4 Other 197.2 130.7 Total deferred credits and other liabilities 3,332.0 3,690.5 Capitalization (See Statement of Capitalization)
Long-term debt 4,613.9 2,712.5 Minority interests 105.3 101.7 BGE preference stock not subject to mandatory redemption 190.0 190.0 Common shareholders' equity 3,862.3 3,843.6 Total capitalization 8,771.5 6,847.8 Commitments, Guarantees, and Contingencies (see Note 11)
Total Liabilities and Equity $14,128.9 $ 14,109.4 See Notes to Consolidated FinancialStatements.
Certainprior-year amounts have been reclassified to conform with the curnt years prsentation.
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Constellation Energy Group, Inc. and Subsidiaries Year Ended December 31, 2002 2001 2000 (In millions)
Cash Flows From Operating Activities Net income $ 525.6 $ 90.9 $ 345.3 Adjustments to reconcile to net cash provided by operating activities Cumulative effect of change in accounting principle - (8.5)
Depreciation and amortization 548.0 468.9 524.8 Deferred income taxes 148.3 (26.5) 42.1 Investment tax credit adjustments (7.9) (8.1) (8.4)
Deferred fuel costs 23.9 37.6 2.8 Pension and postemployment benefits (116.2) 55.3 27.9 Net gain on sales of investments and other assets (261.3) (6.2) (78.1)
Workforce reduction costs 62.8 105.7 7.0 Impairment losses and other costs 25.2 158.8 Contract termination related costs - 26.2 Deregulation transition cost - - 24.0 Equity in earnings of affiliates less than (in excess of) dividends received 67.0 2.0 (5-3)
Changes in Accounts receivable (236.8) 53.7 (214.1)
Mark-to-marker energy assets and liabilities (133.7) 109.5 (379.6)
Risk management assets and liabilities 58.6 (93.2)
Materials, supplies and fuel stocks (11.7) (90.9) 14.5 Other current assets 130.3 (20.5) (31.1)
Accounts payable 188.4 (226.7) 384.9 Other current liabilities 50.4 7.8 21.3 Other (40.9) (62.5) 172.9 Net cash provided by operating activities 1,020.0 573.3 850.9 Cash Flows From Investing Activities Purchases of property, plant and equipment (831.9) (1,302.5) (1,067.0)
Acquisitions, net of cash acquired (221.4) (382.7)
Contributions to nuclear decommissioning trust funds (17.6) (22.0) (13.2)
Payments for structured deal fees (51.4) -
Sale of (investment in) Orion 454.1 26.2 (101.5)
Sale of investments and other assets 383.9 260.9 169.9 Purchases of markerable equity securities (0.2) (33.2) (80.8)
Other investments (35.3) (19.4) (13.9)
Net cash used in investing activities (319.8) (1,472.7) (1,106.5)
Cash Flows From Financing Activities Net issuance (maturity) of short-term borrowings (964.5) 731.4 (127.9)
Proceeds from issuance of Long-term debt 2,529.3 1,175.2 1,374.0 Common stock 28.5 504.4 35.9 Repayment of long-term debt (1,627.7) (1,510.2) (697.0)
Common stock dividends paid (137.8) (120.7) (250.7)
Other 14.6 9.0 11.3 Net cash (used in) provided by financing activities (157.6) 789.1 345.6 Net Increase (Decrease) in Cash and Cash Equivalents 542.6 (110.3) 90.0 Cash and Cash Equivalents at Beginning of Year 72.4 182.7 92.7 Cash and Cash Equivalents at End of Year $ 615.0 $ 72.4 $ 182.7 Other Cash Flow Information:
Cash paid during the year for:
Interest (net of amounts capitalized) $ 230.5 $ 238.3 $ 268.2 Income taxes $ 157.8 $ 101.5 $ 184.7 Non-Cash Transaction:
In connection with our prchase of Nine Mile Point in 2001, the fair value of che net assets purchased was $770.8 million. We paid
$382.7 million in cash, ii uding settlement costs, and incurred a sellers' note of $388.1 million as discussed further in Note 14.
See Notes to Consolidated Fin ial Statements.
Certainprior-year amounts h. been reclassified to conform with the current years presentation.
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_ 014V. qI 4I
- 9. 9 '-t f-I =- & )l I :. I I l l :011 I4 I Constellation Energy Group, Inc. and Subsidiaries Accumulated Other Common Stock Retained Comprehensive Total Years Ended December 31, 2002, 2001, and 2000 Shares Amount Earnings Income Amount (Dollar amounts in millions, number of shares in thousands)
Balance at December 31, 1999 149,556 $1,494.0 $1,499.1 $ 24.4 $ 3,017.5 Comprehensive Income Net income 345.3 345.3 Other comprehensive income (OCI)
Reclassification of net gain on sales of securities from OCI to net income, net of taxes of $18.4 (28.1) (28.1)
Net unrealized gain on securities, net of taxes of $27.9 46.7 46.7 Total Comprehensive Income 363.9 Common stock dividend declared ($1.68 per share) (251.8) (251.8)
Common stock issued 976 35.9 35.9 Other 8.8 (0.3) 8.5 Balance at December 31, 2000 150,532 1,538.7 1,592.3 43.0 3,174.0 Comprehensive Income Net income 90.9 90.9 Other comprehensive income Cumulative effect of change in accounting principle, net of taxes of $22.6 (35.5) (35.5)
Redassification of net gain on sales of securities from OCI to net income, net of taxes of $15.7 (24.0) (24.0)
Net unrealized gain on securities, net of taxes of $87.5 148.5 148.5 Net unrealized gain on hedging instruments, net of taxes of $65.6 102.6 102.6 Minimum pension liability, net of taxes of $29.3 (44.7) (44.7)
Total Comprehensive Income 237.8 Common stock dividend declared ($.48 per share) (77-1) (77.1)
Common stock issued 13,176 504.4 504.4 Other (0.9) 5.4 4.5 Balance at December 31, 2001 163,708 2,042.2 1,611.5 189.9 3,843.6 Comprehensive Income Net income 525.6 525.6 Other comprehensive income Reclassification of net gain on sales of securities from OCI to net income, net of taxes of $87.7 (152.8) (152.8)
Reclassification of net gains on hedging instruments from OCI to net income, net of taxes of $10.9 (17.8) (17.8)
Net unrealized loss on securities, net of taxes of $28.6 (43.2) (43.2)
Net unrealized loss on hedging instruments, net of taxes of $31.7 (52.2) (52.2)
Minimum pension liability, net of taxes of $77.2 (118.1) (118.1)
Total Comprehensive Income 141.5 Common stock dividend declared ($.96 per share) (157.6) (157.6)
Common stock issued 1,135 28.5 28.5 Other 8.2 (1.9) 6.3 Balance at December 31, 2002 164,843 $2,078.9 $1,977.6 $(194.2) $3,862.3 See Notes to Consolidated FinancialStatements.
Certainprior-year amounts have been reclassified to conform with the current years presentation.
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_ __ _ _ _ __ _ _ _ _ _ _ _ _ _ _ l . -I Constellation Energy Group, Inc. and Subsidiaries At December 31, 2002 2001 (In millions)
Long-Term Debt Long-term debt of Constellation Energy Floating rate notes, due January 17, 2002 $ - $ 635.0 77/s% Notes, due April 1, 2005 300.0 300.0 6.35% Fixed Rate Notes, due April 1, 2007 600.0 -
6.125% Fixed Rate Notes, due September 1, 2009 500.0 -
7.00% Fixed Rate Notes, due April 1, 2012 700.0 -
7.60% Fixed Rate Notes, due April 1, 2032 700.0 -
Total long-term debt of Constellation Energy 2,800.0 935.0 Long-term debt of nonregulated businesses Tax-exempt debt transferred from BGE effective July 1, 2000 Pollution control loan, due July 1, 2011 36.0 36.0 Port facilities loan, due June 1, 2013 48.0 48.0 Adjustable rate pollution control loan, due July 1, 2014 20.0 20.0 5.55% Pollution control revenue refunding loan, due July 15, 2014 47.0 47.0 Economic development loan, due December 1, 2018 35.0 35.0 6.00% Pollution control revenue refunding loan, due April 1, 2024 75.0 75.0 Floating rate pollution control loan, due June 1, 2027 8.8 8.8 51/2% Installment series, due July 15, 2002 - 6.7 District Cooling facilities loan, due December 1, 2031 25.0 25.0 Loans under revolving credit agreements 51.7 46.o 11% Installment note, due November 7, 2006 - 388.1 Mortgage and construction loans Floating rate mortgage notes and construction loans, due through 2005 - 13.8 4.25% Mortgage note, due March 15, 2009 3.3 19.7 Total long-term debt of nonregulated businesses 349.8 769.1 First Refunding Mortgage Bonds of BGE 71/4A% Series, due July 1, 2002 124.0 61/2% Series, due February 15, 2003 124.8 124.8 61/s% Series, due July 1, 2003 124.9 124.9 51/22% Series, due April 15, 2004 125.0 125.0 Remarketed floating rate series, due September 1, 2006 111.5 111.5 71/2% Series, due January 15, 2007 123.5 123.5 6'/8% Series, due March 15, 2008 124.9 124.9 71/22% Series, due March 1, 2023 98.1 98.1 71/2% Series, due April 15, 2023 72.2 84.0 Total First Refunding Mortgage Bonds of BGE 904.9 1,040.7 Other long-term debt of BGE 5.25% Notes, due December 15, 2006 300.0 300.0 Floating rate reset notes, due February 5, 2002 - 200.0 Medium-term notes, Series B 12.1 23.1 Medium-term notes, Series C 25.5 25.5 Medium-term notes, Series D 68.0 68.0 Medium-term notes, Series E 199.5 200.0 Medium-term notes, Series G 140.0 140.0 6.75% Remarketable or redeemable securities, due December 15, 2012 - 173.0 Total other long-term debt of BGE 745.1 1,129.6 BGE obligated mandatorily redeemable trust preferred securities of subsidiary trust holding solely 7.16% deferrable interest subordinated debentures due June 30, 2038 250.0 250.0 Unamortized discount and premium (9.7) (5.2)
Current portion of long-term debt (426.2) (1,406.7)
Total long-term debt $4,613.9 $2,712.5 See Notes to Consolidated FinancialStatements.
continued on next page 68
,*Lf E 41 *.1-:A Wu j&IS" L]Nli . -_
Constellation Energy Group, Inc. and Subsidiaries At December 31, 2002 2001 (In millions)
Minority Interests $ 105.3 $ 101.7 BGE Preference Stock Cumulative preference stock not subject to mandatory redemption, 6,500,000 shares authorized 7.125%, 1993 Series, 400,000 shares outstanding, not callable prior to July 1, 2003 40.0 40.0 6.97%, 1993 Series, 500,000 shares outstanding, not callable prior to October 1, 2003 50.0 50.0 6.70%, 1993 Series, 400,000 shares outstanding, not callable prior to January 1, 2004 40.0 40.0 6.99%, 1995 Series, 600,000 shares outstanding, not callable prior to October 1, 2005 60.0 60.0 Total preference stock not subject to mandatory redemption 190.0 190.0 Common Shareholders' Equity Common stock without par value, 250,000,000 shares authorized; 164,842,708 and 163,707,950 shares issued and outstanding at December 31, 2002 and 2001, respectively. (At December 31, 2002, 18,000,000 shares were reserved for the long-term incentive plans, 11,451,868 shares were reserved for the Shareholder Investment Plan, 1,806,100 shares were reserved for the continuous offering programs, and 1,505,863 shares were reserved for the employee savings plan.) 2,078.9 2,042.2 Retained earnings 1,977.6 1,611.5 Accumulated other comprehensive (loss) income (194.2) 189.9 Total common shareholders' equity 3,862.3 3,843.6 Total Capitalization $8,771.5 $6,847.8 See Notes to Consolidated FinancialStatements.
Certainprior-year amounts have been reclassified to conform with the current year's presentation.
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-sj . Su.;
oI. S S Baltimore Gas and Electric Company and Subsidiaries Year Ended December 31, 2002 2001 2000 (In millions)
Revenues Electric revenues $1,966.0 $2,040.0 $2,135.2 Gas revenues 581.3 680.7 611.6 Total revenues 2,547.3 2,720.7 2,746.8 Expenses Operating Expenses Electric fuel and purchased energy 1,080.7 1,192.8 870.7 Gas purchased for resale 316.7 401.3 350.6 Operations and maintenance 355.3 363.0 547.4 Workforce reduction costs 35.3 57.0 7.0 Depreciation and amortization 221.6 221.0 366.1 Taxes other than income taxes 171.4 173.8 192.6 Total expenses 2,181.0 2,408.9 2,334.4 Income from Operations 366.3 311.8 412.4 Other Income 10.7 0.4 7.5 Fixed Charges Interest expense 142.1 156.2 187.2 Allowance for borrowed funds used during construction (1-5) (1.6) (3.2)
Total fixed charges 140.6 154.6 184.0 Income Before Income Taxes 236.4 157.6 235.9 Income Taxes Current 67.4 62.4 142.1 Deferred 28.0 0.2 (44.4)
Investment tax credit adjustments (2.1) (2.3) (5.3)
Total income taxes 93.3 60.3 92.4 Net Income 143.1 97.3 143.5 Preference Stock Dividends 13.2 13.2 13.2 Earnings Applicable to Common Stock $ 129.9 $ 84.1 $ 130.3 See Notes to Consolidated FinancialStatements.
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Baltimore Gas and Electric Company and Subsidiaries At December 31, 2002 2001 (In millions)
Assets Current Assets Cash and cash equivalents $ 10.2 $ 37.4 Accounts receivable (net of allowance for uncollectibles of $11.5 and $13.4, respectively) 357.5 295.2 Investment in cash pool, affiliated company 338.1 439.1 Accounts receivable, affiliated companies 131.2 63.4 Fuel stocks 40.6 52.3 Materials and supplies 31.8 33.1 Prepaid taxes other than income taxes 42.0 43.8 Other 10.3 36.3 Total current assets 961.7 1,000.6 Other Assets Receivable, affiliated company 63.3 183.3 Other 85.9 74.5 Total other assets 149.2 257.8 Utility Plant Plant in service Electric 3,422.3 3,349.9 Gas 1,041.0 1,014.4 Common 489.1 498.1 Total plant in service 4,952.4 4,862.4 Accumulated depreciation (1,851.4) (1,751.4)
Net plant in service 3,101.0 3,111.0 Construction work in progress 118.3 81.8 Plant held for future use 4.5 4.5 Net utility plant 3,223.8 3,197.3 Deferred Charges Regulatory assets (net) 405.7 463.8 Other 39.5 35.0 Total deferred charges 445.2 498.8 Total Assets $ 4,779.9 $ 4,954.5 See Notes to Consolidated Financial Statements.
Certain prior-yearamounts have been reclassifiedto conform with the currentyearspresentation.
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Baltimore Gas and Electric Company and Subsidiaries At December 31, 2002 2001 (In millions)
Liabilitles and Equity Current Liabilities Current portions of long-term debt $ 420.7 $ 666.3 Accounts payable 103.2 63.6 Accounts payable, affiliated companies 85.6 92.6 Customer deposits 54.2 50.0 Accrued taxes 9.0 7.6 Accrued interest 31.4 37.0 Accrued vacation costs 19.5 21.7 Other 30.2 39.2 Total current liabilities 753.8 978.0 Deferred Credits and Other Liabilities Deferred income taxes 528.9 503.1 Postretirement and postemployment benefits 278.0 266.1 Deferred investment tax credits 20.5 22.7 Decommissioning of federal uranium enrichment facilities 14.6 19.3 Other 13.9 17.2 Total deferred credits and other liabilities 855.9 828.4 Long-term Debt First refunding mortgage bonds of BGE 904.9 1,040.7 Other long-term debt of BGE 745.1 1,129.6 Company obligated mandatorily redeemable trust preferred securities of subsidiary trust holding solely 7.16% debentures of BGE due June 30, 2038 250.0 250.0 Long-term debt of nonregulated businesses 25.0 71.0 Unamortized discount and premium (5.2) (3.3)
Current portion of long-term debt (420.7) (666.3)
Total long-term debt 1,499.1 1,821.7 Minority Interest 19.4 5.0 Preference Stock Not Subject to Mandatory Redemption 190.0 190.0 Common Shareholder's Equity Common stock 912.2 711.9 Retained earnings 549.5 419.5 Total common shareholder's equity 1,461.7 1,131.4 Commitments, Guarantees, and Contingencies (see Note 11)
Total Liabilities and Equity $ 4,779.9 $ 4,954.5 See Notes to Consolidated FinancialStatements.
Certain prior-year amounts have been reclassifiedto conform with the currentyears presentation.
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Baltimore Gas and Electric Company and Subsidiaries Year Ended December 31, 2002 2001 2000 (In millions)
Cash Flows From Operating Activities Net income $ 143.1 $ 97.3 $ 143.5 Adjustments to reconcile to net cash provided by operating activities Depreciation and amortization 224.4 223.3 393.6 Deferred income taxes 28.0 0.2 (44.4)
Investment tax credit adjustments (2.1) (2.3) (5.3)
Deferred fuel costs 23.9 37.6 2.8 Pension and postemployment benefits (40.7) 14.7 16.1 Allowance for equity funds used during construction (2.8) (3.0) (2.6)
Workforce reduction costs 35.3 57.0 7.0 Changes in Accounts receivable (62.3) 117.8 (101.4)
Receivables, affiliated companies 52.2 (113.5) (128.7)
Materials, supplies and fuel stocks 13.0 (14.0) 11.1 Other current assets 27.8 (30.5) 31.8 Accounts payable 39.6 (55.7) (88.6)
Accounts payable, affiliated companies (7.0) (10.9) 98.8 Other current liabilities (11.2) (7.7) (7.1)
Other 33.2 61.5 68.1 Net cash provided by operating activities 494.4 371.8 394.7 Cash Flows From Investing Activities Utility construction expenditures (excluding equity portion of AFC) (216.7) (236.4) (309.5)
Investment in cash pool at parent 101.0 (441.1) 2.0 Nuclear fuel expenditures - _ (39.5)
Contributions to nuclear decommissioning trust fund - - (8.8)
Other (17.0) (20.9) 0.1 Net cash used in investing activities (132.7) (698.4) (355.7)
Cash Flows From Fmancing Activities Net maturity of short-term borrowings - (32.1) (96.9)
Proceeds from issuance of long-term debt - 532.1 377.3 Repayment of long-term debt (575.5) (394.1) (121.7)
Preference stock dividends paid (13.2) (13.2) (13.2)
Distribution from (to) parent 200.0 250.0 (188.5)
Other (0.2) - 1.8 Net cash (used in) provided by finandng activities (388.9) 342.7 (41.2)
Net (Decrease) Increase in Cash and Cash Equivalents (27.2) 16.1 (2.2)
Cash and Cash Equivalents at Beginning of Year 37.4 21.3 23.5 Cash and Cash Equivalents at End of Ycar $ 10.2 $ 37.4 $ 21.3 Other Cash Flow Information Cash paid during the year for:
Interest (net of amounts capitalized) $ 147.5 $ 162.0 $ 184.7 Income taxes $ 36.6 $ 102.8 $ 127.6 Noncash Investing and Financing Activities:
On July 1, 2000, BGE transferred $1,578.4 million of generation assets, net of associated liabilities, to nonregulated affiliates of Constellation Energy as a result of the deregulation of electric generation.
See Notes to Consolidated FinancialStatements.
Certainprior-year amounts have been reclassifed to conform with the currentyears presentation.
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i - -
- 9
- S 1 ' 5 I Significant Accounting Policies Nature of Our Business Regulation of Utility Business Constellation Energy Group, Inc. (Constellation Energy) is a The Maryland Public Service Commission (Maryland PSC) and North American energy company that conducts its business the Federal Energy Regulatory Commission (FERC) provide the through various subsidiaries induding a merchant energy final determination of the rates we charge our customers for our business and Baltimore Gas and Electric Company (BGE). Our regulated businesses. Generally, we use the same accounting merchant energy business is a competitive provider of energy policies and practices used by nonregulated companies for solurions for large customers. BGE is a regulated electric and gas financial reporting under accounting principles generally public transmission and distribution utility company with a accepted in the United States of America. However, sometimes service territory that covers the City of Baltimore and all or part the Maryland PSC orders an accounting treatment different of ten counties in central Maryland. We describe our operating from that used by nonregulated companies to determine the segments in Note 3. rates we charge our customers. When this happens, we must This report is a combined report of Constellation Energy defer (include as an asset or liability in our Consolidated Balance and BGE. References in this report to we" and "our" are to Sheets and exclude from our Consolidated Statements of Constellation Energy and its subsidiaries. References in this Income) certain utility expenses and income as regulatory assets report to the "utility business" are to BGE. and liabilities. We have recorded these regulatory assets and liabilities in our Consolidated Balance Sheets in accordance with Consolidation Policy Statement of Financial Accounting Standards (SFAS) No. 71, We use three different accounting methods to report our Accountingfor the Effects of Certain Types of Regulation.
investments in our subsidiaries or other companies: In addition, the FASB through its Emerging Issues Task consolidation, the equity method, and the cost method. Force (EITF) issued EITF 97-4, Deregulationof the Pricingof Electricity-Issues Related to the Application of FASB Statements Consolidation No. 71 and 101. The EITF concluded that a company should We use consolidation when we own a majority of the voting cease to apply SFAS No. 71 when either legislation is passed or stock of the subsidiary. This means the accounts of our a regulatory body issues an order that contains sufficient detail subsidiaries are combined with our accounts. We eliminate to determine how the transition plan will affect the deregulated intercompany balances and transactions when we consolidate portion of the business. Additionally, a company would continue these accounts. We discuss the implications of the Financial to recognize regulatory assets and liabilities in the Consolidated Accounting Standards Board (FASB) Interpretation No. 46, Balance Sheets to the extent that the transition plan provides for Consolidation of Variable Interest Entities on our future their recovery.
consolidation policy later in this Note. We summarize and discuss our regulatory assets and liabilities further in Note 5.
The Equity Method We usually use the equity method to report investments, Use of Accounting Estimates corporate joint ventures, partnerships, and affiliated companies Management makes estimates and assumptions when preparing (including qualifying facilities and power projects) where we financial statements under accounting principles generally hold a 20% to 50% voting interest. Under the equity method, accepted in the United States of America. These estimates and we report: assumptions affect various matters, induding:
+ our interest in the entity as an investment in our
- our reported amounts of assets and liabilities in our Consolidated Balance Sheets, and Consolidated Balance Sheets at the dates of the financial
- our percentage share of the earnings from the entity in statements, our Consolidated Statements of Income.
- our disclosure of contingent assets and liabilities at the The only time we do not use this method is if we can dates of the financial statements, and exercise control over the operations and policies of the company.
- our reported amounts of revenues and expenses in our If we have control, accounting rules require us to use Consolidated Statements of Income during the reporting consolidation. periods.
These estimates involve judgments with respect to The Cost Method numerous factors that are difficult to predict and are beyond We usually use the cost method if we hold less than a 20% management's control. As a result, actual amounts could voting interest in an investment. Under the cost method, we materially differ from these estimates.
report our investment at cost in our Consolidated Balance Sheets. The only time we do not use this method is when we can exercise significant influence over the operations and policies of the company. If we have significant influence, accounting rules require us to use the equity method.
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Reclasslfications
- Credit-spread adjustment-for risk management We have reclassified certain prior-year amounts for comparative purposes, we compute the value of our mark-to-market purposes. These reclassifications did not affect consolidated net assets and liabilities using a risk-free discount rate. In income for the years presented. order to compute fair value for financial reporting purposes, we adjust the value of our mark-to-market Revenues assets to reflect the credit-worthiness of each individual NonregulatedBusinesses counterparty based upon published credit ratings, where We record nonregulated business revenues using two methods of available, or equivalent internal credit ratings and accounting: accrual accounting and mark-to-market accounting. associated default probability percentages. We compute We use accrual accounting for our merchant energy business this reserve by applying the appropriate default transactions, including non-trading long-term power sales probability percentage to our outstanding credit contracts that are not subject to mark-to-market accounting. exposure, net of collateral, for each counterparty.
Transactions subject to accrual accounting include the generation Mark-to-market revenues include:
or purchase and sale of electricity and gas as part of our physical
- gains or losses on new transactions at origination to the delivery activities. Under accrual accounting, we record revenues extent permitted by applicable accounting rules, in the period earned for services rendered, commodities or
- unrealized gains and losses from changes in the fair products delivered, or contracts settled. value of open positions, We use mark-to-market accounting for energy trading
- net gains and losses from realized transactions, and activities and for derivatives and other contracts for which we
- changes in reserves.
are not permitted to use accrual accounting or hedge accounting. We record the changes in mark-to-market energy assets and We discuss our use of hedge accounting in the Risk Management liabilities on a net basis in "Nonregulated revenues" in our and Hedging Activities section later in this Note. These Consolidated Statements of Income. At December 31, 2002, mark-to-market activities include derivative and (prior to EITF mark-to-market energy assets and liabilities consist of a 02-3) non-derivative contracts for energy and other energy- combination of energy and energy-related derivative and related commodities. Under the mark-to-market method of non-derivative contracts. While some of these contracts represent accounting, we record the fair value of energy contracts as commodities or instruments for which prices are available from mark-to-market energy assets and liabilities at the time of external sources, other commodities and certain contracts are not contract execution. We record reserves to reflect uncertainties actively traded and are valued using modeling techniques to associated with certain estimates inherent in the determination determine expected future market prices, contract quantities, or of fair value. To the extent possible, we utilize market-based data both. The market prices and quantities used to determine fair together with quantitative methods for both measuring the risks value reflect management's best estimate considering various for which we record reserves and determining the level of such factors, including closing exchange and over-the-counter reserves and changes in those levels. quotations, time value, and volatility factors. However, future We describe below the main types of reserves we record and market prices and actual quantities will vary from those used in the process for establishing each. recording mark-to-market energy assets and liabilities, and it is
- Close-out reserve-this reserve represents the estimated possible that such variations could be material.
cost to close out or sell to a third-party open During 2002, the FASB issued EITF 02-3, Recognition and mark-to-market positions. This reserve has the effect of Reporting of Gains and Losses on Energy Trading Contracts Under valuing "long" positions at the bid price and "short" EITF Issues No. 98-10 and No. 00-17 that changed the positions at the offer price. We compute this reserve accounting for energy contracts. These changes include requiring based on our estimate of the bid/offer spread for each the accrual method of accounting for energy contracts that are commodity and option price and the absolute quantity not derivatives and clarifying when gains or losses can be of our open positions for each year. Effective July 1, recognized at the inception of derivative contracts. We discuss 2002, to the extent that we are not able to obtain EITF 02-3 in more detail in the Recently Issued Accounting market information for similar contracts, the close-out Standards section later in this Note.
reserve is equivalent to the initial contract margin, Certain transactions entered into under master agreements thereby recording no gain or loss at inception. The level and other arrangements provide our merchant energy business of total close-out reserves increases as we have larger with a right of setoff in the event of bankruptcy or default by unhedged positions, bid-offer spreads increase, or market the counterparty. We report such transactions net in the balance information is not available, and it decreases as we sheets in accordance with FASB Interpretation No. 39, Offietting reduce our unhedged positions, bid-offer spreads of Amounts Related to Certain Contracts.
decrease, or market information becomes available. We also include equity in earnings from our investments in qualifying facilities and power projects in revenues.
Regulated Utility We record utility revenues when we provide service to customers.
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_ -1 Fuel and Purchased Energy Costs Natural Gas We incur costs for: We charge our gas customers for the natural gas they purchase
- the fuel we use to generate electricity, from us using "gas cost adjustment clauses" set by the Maryland
- purchases of electricity from others, and PSC. These clauses operate similarly to the electric fuel rate
- natural gas that we resell. clause described earlier in this Note. However, the Maryland These costs are included in "Operating expenses" in our PSC approved a modification of the gas cost adjustment clauses Consolidated Statements of Income. We discuss each of these to provide a market-based rates incentive mechanism. Under separately below. market-based rates, our actual cost of gas is compared to a market index (a measure of the market price of gas in a given Fuel Used to Generate Electricity and Purchases of Ek'ctricity period). The difference between our actual cost and the market From Others index is shared equally between shareholders and customers.
We assemble a variety of power supply resources, including Effective November 2001, the Maryland PSC approved an order baseload, intermediate, and peaking plants that we own, as well that modifies certain provisions of the market-based rates as a variety of power supply contracts that may have similar incentive mechanism. These provisions require that BGE secure characteristics, in order to enable us to meet our customers fixed-price contracts for at least 10%, but not more than 20%,
energy requirements, which vary on an hourly basis. We of forecasted system supply requirements for the November purchase power when our load-serving requirements exceed the through March period. These fixed price contracts are not amount of power available from our supply resources or when it subject to sharing under the market-based rates incentive is more economic to do so than to operate our power plants. mechanism.
The amount of power purchased depends on a number of factors, including the capacity and availlability of our power Rlsk Management and Hedging Actities plants, the level of customer demand, aand the relative economics Market Risks of generating power versus purchasing Ipower from the spot We are exposed to market risk, including changes in interest market. rates and the impact of market fluctuations in the price and Our accrual-basis third-party fuel and purchased energy transportation costs of electricity, natural gas, and other expenses were as follows: commodities as discussed further in Note 12. SFAS No. 133, as amended by SFAS No. 138, Accountingfor Certain Derivative 2002 2001 2000 Instruments and Certain Hedging Activities, requires that we (In millions) recognize all derivatives not qualifying for the normal purchase Fuel and Purchased Energy 1, 144.2 $479.6 $429.7 and normal sale exemption in our Consolidated Balance Sheets at fair value. Changes in the value of derivatives that are not Effective July 1, 2000, these costs are recorded as incurred. hedges must be recorded in earnings. Under SFAS No. 133, Historically and until July 1, 2000, we were allowed to recover changes in the value of derivatives designated as cash-flow hedges our costs of electric fuel under the elec tric fuel rate clause set by that are effective in offsetting the variability in cash flows of the Maryland PSC. Under the electric fuel rate clause, we forecasted transactions are recognized in other comprehensive charged our electric customers for: income until the forecasted transactions occur. The ineffective
- the fuel we used to generate el ectricity (nuclear fuel, portion of changes in fair value of derivatives used as cash-flow coal, gas, or oil), and hedges is immediately recognized in earnings.
- the net cost of purchases and sales of electricity. In accordance with the transition provisions of SFAS We charged the actual costs of theese items to customers No. 133, we recorded the following at January 1, 2001:
with no profit to us. To do this, we had to keep track of what
- an $8.5 million after-tax cumulative effect adjustment we spent and what we collected from customers under the fuel that increased earnings, and rate in a given period. Usually these rwvo amounts were not the
- a $35.5 million after-tax cumulative effect adjustment same because there was a difference bei ween the time we spent that reduced other comprehensive income.
the money and the time we collected ii from our customers. The cumulative effect adjustment recorded in earnings Under the electric fuel rate clause, we deferred the represents the fair value as of January 1, 2001 of a warrant for difference between our actual costs of ffuel and energy and what 705,900 shares of common stock of Orion. The warrant had an we collected from customers under the fuel rate in a given exercise price of $10 per share and was received in conjunction period. We either billed or refunded oLir customers that with our investment in Orion. As part of the sale of Orion to difference in the future. As a result of the deregulation of Reliant Resources, Inc., we received cash equal to the difference electric generation, the fuel rate was disscontinued effective between Reliant's purchase price of $26.80 per share and the July 1, 2000. exercise price multiplied by the number of shares subject o the warrant.
The cumulative effect adjustment recorded in other comprehensive income represents certain forward sales of electricity that we designated as cash-flow hedges of forecasted transactions primarily through our merchant energy business.
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Interest Rate Swaps Credit Risk We use interest rate swaps to manage our interest rate exposures Credit risk is the loss that may result from counterparty associated with new debt issuances. These swaps are in non-performance. We are exposed to credit risk, primarily anticipation of planned financing transactions and are designated through our merchant energy business. We use credit policies to as cash-flow hedges under SFAS No. 133, with our gains or manage our credit risk, including utilizing an established credit losses recorded in "Risk management assets or liabilities" in our approval process, monitoring counterparty limits, employing Consolidated Balance Sheets and "Accumulated other credit mitigation measures such as margin, collateral or comprehensive income," in our Consolidated Statements of prepayment arrangements, and using master netting agreements.
Common Shareholders' Equity and Consolidated Statements of We measure credit risk as the replacement cost for open energy Capitalization. Any gain or loss on the hedges will be reclassified commodity and derivative positions (both mark-to-market and from "Accumulated other comprehensive income" into "Interest accrual) plus amounts owed from counterparties for setded expense" and be induded in earnings during the periods in transactions. The replacement cost of open positions represents which the interest payments being hedged occur. unrealized gains, net of any unrealized losses, where we have a legally enforceable right of setoff.
Commodity Prices Due to the possibility of extreme volatility in the prices of Our merchanr energy and regulated gas businesses use derivative energy commodities and derivatives, the market value of and non-derivative instruments to manage changes in their contractual positions with individual counterparties could exceed respective commodity prices as discussed in more detail below. established credit limits or collateral provided by those counterparties. If such a counterparty were then to fail to Merchant Energy Business perform its obligations under its contract (for example, fail to Our origination and risk management operation manages market deliver the electricity our origination and risk management risk on a portfolio basis, subject to established risk management operation had contracted for), we could sustain a loss that could policies. Our origination and risk management operation may have a material impact on our financial results.
enter into fixed-price derivative or non-derivative contracts to Additionally, if a counterparty were to default and we were hedge the variability in future cash flows from forecasted sales of to liquidate all contracts with that entity, our credit loss would energy and purchases of fuel. indude the loss in value of mark-to-market contracts, the Under the provisions of SFAS No. 133, we record gains amount owed for setded transactions, and additional payments, and losses on derivative contracts designated as cash-flow hedges if any, we would have to make to settle unrealized losses on of firm commitments or anticipated transactions in accrual contracts.
"Accumulated other comprehensive income" in our Consolidated Electric and gas utilities, cooperatives, and energy marketers Statements of Common Shareholders' Equity and Consolidated comprise the majority of counterparties underlying our assets Statements of Capitalization prior to the settlement of the from our origination and risk management activities. We held anticipated hedged physical transaction. We redassify these gains cash collateral from counterparties totaling $50.1 million as of or losses into earnings upon settlement of the underlying hedged December 31, 2002 and $3.5 million as of December 31, 2001.
transaction. We record derivatives used for hedging activities These amounts are included in "Other deferred credits and other from our merchant energy business in Risk management assets liabilities" in our Consolidated Balance Sheets.
and liabilities" in our Consolidated Balance Sheets.
Taxes Regulated Gas Business We summarize our income taxes in Note 9. Our subsidiary We use basis swaps in the winter months (November through income taxes are computed on a separate return basis. As you March) to hedge our price risk associated with natural gas read this section, it may be helpful to refer to Note 9.
purchases under our market-based rates incentive mechanism.
We also use fixed-to-floating and floating-to-fixed swaps to Income Tax Expense hedge our price risk associated with our off-system gas sales. We have two categories of income taxes-current and deferred.
The fixed portion represents a specific dollar amount that We describe each of these below:
we will pay or receive, and the floating portion represents a
- current income tax expense consists solely of regular tax fluctuating amount based on a published index that we will less applicable tax credits, and receive or pay. Our regulated gas business internal guidelines do
- deferred income tax expense is equal to the changes in not permit the use of swap agreements for any purpose other the net deferred income tax liability, excluding amounts than to hedge price risk. charged or credited to accumulated other comprehensive income. Our deferred income tax expense is increased or reduced for changes to the Income taxes recoverable through future rates (net)" regulatory asset (described later in this Note) during the year.
77
-JL-Investment Tax Credits Our stock options are granted with an exercise price equal We have deferred the investment tax credits associated with our to the market value of the stock at the date of grant.
regulated utility business and assets previously held by our Accordingly, no compensation expense is recorded for these regulated utility business in our Consolidated Balance Sheets. awards. However, when we grant options subject to a The investment tax credits are amortized evenly to income over contingency, we recognize compensation expense when options the life of each property. We reduce income tax expense in our granted have an exercise price less than the market value of the Consolidated Statements of Income for the investment tax underlying common stock on the date the contingency is credits and other tax credits associated with our nonregulated satisfied. We amortize compensation expense for restricted stock businesses, other than leveraged leases. over the performance/service period, which is typically a one to five year period.
Deferred Income Tax Assets and Liabilites The following table illustrates the effect on net income and We must report some of our revenues and expenses differently earnings per share had we applied the fair value recognition for our financial statements than for income tax return purposes. provision of SFAS No. 123 to all outstanding stock option and The tax effects of the differences in these items are reported as stock awards in each year.
deferred income tax assets or liabilities in our Consolidated Balance Sheets. We measure the deferred income tax assets and 2002 2001 2000 liabilities using income tax rates that are currently in effect. (In millions, except per A portion of our total deferred income tax liability relates share amounts) to our regulated utility business, but has not been reflected in Net income, as reported $ 525.6 $90.9 $345.3 the rates we charge our customers. We refer to this portion of Add: Stock-based compensation the liability as "Income taxes recoverable through future rates expense included in reported (net)." We have recorded that portion of the net liability as a net income, net of related tax regulatory asset in our Consolidated Balance Sheets. We discuss effects 6.1 (6.1) 9.8 this further in Note 5. Deduct: Stock-based compensation expense determined under fair State and Local Taxes value based method for all State and local income taxes are included in "Income taxes" in awards, net of related tax effects (16.8) (0.9) (9.0) our Consolidated Statements of Income.
We also pay Maryland public service company franchise tax Pro-forma net income $ 514.9 $83.9 $346.1 on transmission, distribution, and delivery of electricity and Earnings per share:
natural gas. We include the franchise tax in "Taxes other than Basic-as reported $ 3.20 $ .57 $ 2.30 income taxes" in our Consolidated Statements of Income. Basic-pro forma $ 3.14 $ .52 $ 2.31 Diluted-as reported $ 3.20 $ .57 $ 2.30 Earnings Per Share Diluted-pro forma $ 3.13 $ .52 $ 2.31 Basic earnings per common share (EPS) is computed by dividing earnings applicable to common stock by the weighted-average In rhe table above, the stock-based compensation expense number of common shares outstanding for the year. Diluted included in reported net income, net of related tax effects is as EPS reflects the potential dilution of common stock equivalent follows:
shares that could occur if securities or other contracts to issue
- in 2002, $6.1 million, after-tax, or $10.1 million pre-tax common stock were exercised or converted into common stock. comprised of $3.0 million of pre-tax expense for certain Our dilutive common stock equivalent shares consist of stock stock options, $6.6 million for restricted stock, and options. Stock options to purchase approximately 4.1 million $0.5 million for equity grants, shares in 2002, approximately 0.1 million shares in 2001, and
- in 2001, a $(6.1) million, after-tax, or $(10.1) million approximately 1.4 million shares in 2000 were not dilutive and pre-tax reversal of expense for restricted stock as a result were excluded from the computation of diluted EPS for these of non-attainment of performance criteria, and respective years.
- in 2000, $9.8 million, after-tax, or $16.3 million pre-tax for restricted stock grants.
Stock-Based Compensatlon Under our long-term incentive plans, we granted stock options, Cash and Cash Equivalents performance and service-based restricted stock, and equity to All highly liquid investments with original maturities of three officers, key employees, and members of the Board of Directors. months or less are considered cash equivalents.
We discuss this in more detail in Note 13.
As permitted by SFAS No. 123, Accounting or Stock-Based Inventory Compensation, we measure our stock-based compensation in We record our fuel stocks and materials and supplies at the accordance with Accounting Principles Board Opinion (APB) lower of cost or market. We determine cost using the average No. 25, Accountingfor Stock Issued to Employees, and related cost method.
interpretations.
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Real Estate Projects and Investments We determine if long-lived assets are impaired by In Note 4, we summarize the real estate projects and investments comparing their undiscounted expected future cash flows to their that are in our Consolidated Balance Sheets. At December 31, carrying amount in our accounting records. We would record an 2002, the projects and investments primarily consist of: impairment loss if the undiscounted expected future cash flows
- approximately 500 acres of land holdings in various from an asset were less than the carrying amount of the asset.
stages of development located at 6 sites in the central We are also required to evaluate our equity-method and Maryland region, and cost-method investments (for example, in partnerships that own
- an operating waste water treatment plant located in power projects) for impairment. APB No. 18, The Equity Method Anne Arundel County, Maryland. ofAccountingfor Investments in Common Stock, provides the The costs incurred to develop properties are included as accounting for these investments. The standard for determining part of the cost of the properties. whether an impairment must be recorded under APB No. 18 is whether the investment has experienced a loss in value that is Financial Investments and Trading Securities considered an "other than a temporary" decline in value.
In Note 4, we summarize the financial investments that are in We use our best estimates in making these evaluations and our Consolidated Balance Sheets. consider various factors, including forward price curves for SFAS No. 115, Accountingfor Certain Investments in Debt energy, fuel costs, legislative initiatives, and operating costs.
and Equity Securities, applies particular requirements to some of However, actual future market prices and project costs could our investments in debt and equity securities. We report those vary from those used in our impairment evaluations, and the investments at fair value, and we use either specific identification impact of such variations could be material.
or average cost to determine their cost for computing realized gains or losses. We classify these investments as either trading Goodwill securities or available-for-sale securities, which we describe Goodwill is the excess of the purchase price of an acquisition separately below. We report investments that are not covered by over the fair value of the net assets acquired. We do not SFAS No. 115 at their cost. amortize goodwill and certain other intangibles under the provisions of SFAS No. 142, Goodwill and Other Intangible Trading Securities Assets. SFAS No. 142 requires the evaluation of goodwill for Our other nonregulated businesses classify some of their impairment at least annually or more frequently if events and investments in marketable equity securities and financial limited circumstances indicate that the asset might be impaired. We partnerships as trading securities. We include any unrealized discuss our acquisitions in Note 14.
gains or losses on these securities in "Nonregulated revenues" in our Consolidated Statements of Income. Property, Plant and Equipment, Depreciation, Amortization, and Decommissioning Available-for-Sale Securities We report our property, plant and equipment at its original cost, We dassify our investments in the nuclear decommissioning unless impaired under the provisions of SFAS No. 144.
trust funds as available-for-sale securities. We describe the Our original costs include:
nuclear decommissioning trusts and the reserves under the
- material and labor, heading "Nuclear Decommissioning" later in this Note.
- contractor costs, and In addition, our other nonregulated businesses classified
- construction overhead costs and financing costs (where some of their investments in marketable equity securities as applicable).
available-for-sale securities. We own an undivided interest in the Keystone and We include any unrealized gains or losses on our Conemaugh electric generating plants in Western Pennsylvania, available-for-sale securities in "Accumulated other comprehensive as well as in the transmission line that transports the plants' income" in our Consolidated Statements of Common output to the joint owners' service territories. Our ownership Shareholders' Equity and Consolidated Statements of interests in these plants are 20.99% in Keystone and 10.56% in Capitalization. Conemaugh. These ownership interests represented a net investment of $168 million at December 31, 2002 and Evaluation of Assets for Impairment and Other Than $148 million at December 31, 2001. Each owner is responsible Temporary Decline in Value for financing its proportionate share of the plants' working We are required to evaluate certain assets that have long lives funds. Working funds are used for operating expenses and (for example, generating property and equipment and real estate) capital expenditures. Operating expenses related to these plants to determine if they are impaired when certain conditions exist. are included in "Operating Expenses" in our Consolidated SFAS No. 144, Accountingfor the Impairment or Disposal of Statements of Income. Capital costs related to these plants are Long-Lived Assets, provides the accounting for impairments of included in Nonregulated generation property, plant and long-lived assets. We are required to test our long-lived assets for equipment" in our Consolidated Balance Sheets.
recoverability whenever events or changes in circumstances indicate that their carrying amount may not be recoverable.
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The "Nonregulated generation property, plant and Nuclear Decommissioning equipment" in our Consolidated Balance Sheets inc ludes We record an expense and a reserve for the costs expected to be nonregulated generation construction work in progiress of incurred in the future to decommission Calvert Cliffi based on a
$237.2 million at December 31, 2002 and $1,146. 2 million at sinking fund methodology. The accumulated decommissioning December 31, 2001. reserve is recorded in "Accumulated depreciation" in our When we retire or dispose of property, plant and Consolidated Balance Sheets. The total reserve was equipment, we remove the asset's cost from our Co nsolidated $333.7 million at December 31, 2002 and $304.6 million at Balance Sheets. We charge this cost to accumulated depreciation December 31, 2001. Our contributions to the nuclear for assets that were depreciated under the composit, ze, decommissioning trust funds were $17.6 million for 2002, straight-line method. This includes regulated utility property, $22.0 million for 2001, and $13.2 million for 2000.
plant and equipment and nonregulated generating issets Under the Maryland PSC's order deregulating electric previously owned by the regulated utility. For all ot her assets, we generation, BGE's customers must pay a total of $520 million in remove the accumulated depreciation and amortizat ion amounts 1993 dollars, adjusted for inflation, to decommission Calvert from our Consolidated Balance Sheets and record any gain or Cliffs. BGE is collecting this amount on behalf of and passing it loss in our Consolidated Statements of Income. to Calvert Cliffs Nuclear Power Plant, Inc. Calvert Cliffi The costs of maintenance and certain replacen ients are Nuclear Power Plant, Inc. is responsible for any difference charged to "Operating expenses" in our Consolidate-d Statements between this amount and the actual costs to decommission the of Income as incurred. plant.
We recorded a reserve for the costs expected to be incurred Depreciation Expense in the future to decommission Nine Mile Point under the We compute depreciation for our generating, electriic discounted future cash flows methodology. The total reserve was transmission and distribution, and gas facilities ovei r the $242.1 million at December 31, 2002 and $224.4 million at estimated useflul lives of depreciable property using either the: December 31, 2001. We determined that the decommissioning
- composite, straight-line rates (approved by the Maryland trust funds established for Nine Mile Point are adequately PSC for our regulated utility business) appllied to the funded to cover the future costs to decommission the plant and average investment, adjusted for anticipatec I costs of as such, no contributions were made to the trust funds during removal less salvage, in classes of depreciabl Leproperty the years ended December 31, 2002 and December 31, 2001.
based on an average rate of approximately three percent In accordance with Nuclear Regulatory Commission (NRC) per year, or regulations, we maintain external decommissioning trusts to
- modified units of production method (grea ter of fund the costs expected to be incurred to decommission Calvert straight-line method or units of production I method). Cliffs and Nine Mile Point. The NRC requires utilities to Other assets are depreciated using the straight- line method provide financial assurance that they will accumulate sufficient and the following estimated useful lives: funds to pay for the cost of nuclear decommissioning. The assets in the trusts are reported in "Nuclear decommissioning trust Asset Estimateod Useful Lives funds" in our Consolidated Balance Sheets.
Building and improvements 20 - 50 years We classify the investments in the nuclear decommissioning 5 5Yearstrust funds as available-for-sale securities, and we report these Transportation equipment 5-15 Years investments at fair value in our Consolidated Balance Sheets as Office equipment and computer software 3 - 20 years previously discussed in this Note. Investments by nuclear decommissioning trust funds are guided by the "prudent man" investment principle. The funds are prohibited from investing in Amortization Expense in amount in Constellation Energy or its affiliates and any other entity owning Amortization is an accounting process of reducing ad otm a nuclear power plant.
our Consolidated Balance Sheets evenly over a peri d of time As owners of Calvert Cliffs Nuclear Power Plant, we are that approximates the useful life of the related item
'h we required, along with other domestic utilities, by the Energy reduce amounts in our Consolidated Balance Sheet:
ts we Increase Policy Act of 1992 to make contributions to a fund for amortization expense in our Consolidated Statemen tS of Income, decommissioning and decontaminating the Department of Energys uranium enrichment facilities. The contributions are Nuclear Fuel We amortize nuclear fuel based on the energy prod uced over the paid by BGE and generally payable over 15 years with escalation for inflation and are based upon the proportionate amount of life of the fuel including the quarterly fees we pay to te uranium enriched by the Department of Energy for each utility.
Department of Energy for the future disposal of sp pet nuclear We amortize the deferred costs of decommissioning and fuel. These fees are based on the kilowatt-hours of electrici decontaminating the Department of Energy's uranium sold. We report the amortization expense for nucleair fuel in enrichment facilities. The previous owners retained the "Operating expenses" in our Consolidated Statemer itoc,
- obligation for Nine Mile Point.
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Capitalized Interest and Allowance for Funds Used Recently Issued Accounting Standards During Construction SFAS No. 143 CapitalizedInterest In 2001, the FASB issued SFAS No. 143, Accountingfor Asset With the deregulation of electric generation, we ceased accruing Retirement Obligations. SFAS No. 143 provides the accounting AFC (discussed below) for electric generation-related requirements for recognizing legal obligations associated with the construction projects. retirement of tangible long-lived assets. This statement requires a Our nonregulated businesses capitalize interest costs under cumulative effect of a change in accounting principle to be SFAS No. 34, Capitalizing Interest Costs, for costs incurred to reported upon initial adoption and is effective for fiscal years finance our power plant construction projects and real estate beginning after June 15, 2002, with early adoption permitted. In developed for internal use. January 2003, we recognized a net after-tax gain of approximately $68 million in accordance with this statement.
Allowance for Funds Used During Construction (AFC) Substantially all of this net gain relates to the impact of We finance regulated utility construction projects with borrowed adopting SFAS No. 143 on the measurement of the liability for funds and equity funds. We are allowed by the Maryland PSC the decommissioning of our Calvert Cliffs nudear power plant.
to record the costs of these funds as part of the cost of Losses on the adoption of SFAS No. 143 in other areas of our construction projects in our Consolidated Balance Sheets. We do business are offset by the gain relating to the decommissioning this through the AFC, which we calculate using a rate of our Nine Mile Point nuclear power plant. The Calvert Cliffs' authorized by the Maryland [SC. We bill our customers for the gain is primarily due to using a longer discount period as a AFC plus a return after the utility property is placed in service. result of license extension. The existing liability for the The AFC rates are 9.4% for electric plant, 8.6% for gas decommissioning of Calvert Cliffs was determined in accordance plant, and 9.2% for common plant. We compound AFC with ratemaking treatment established by the Maryland PSC and annually. is based on a previous decommissioning cost estimate that contemplated decommissioning being completed at a point in Long-Term Debt time much closer to the expiration of the plant's original We defer all costs related to the issuance of long-term debt. operating license.
These costs include underwriters' commissions, discounts or As discussed earlier in this Note, we use the composite premiums, other costs such as legal, accounting, and regulatory depreciation method for certain generating facilities and for our fees, and printing costs. We amortize these costs to interest utility business. This method is currently an acceptable method expense over the life of the debt. of accounting under generally accepted accounting principles and When we incur gains or losses on debt that we retire prior is widely-used in the energy, transportation, and to maturity in our regulated utility business, we amortize those telecommunication industries. Under the composite depreciation gains or losses over the remaining original life of the debt. method, the anticipated costs of removing assets upon retirement are provided for over the life of those assets as a component of Accounting Standards Adopted depreciation expense.
SFAS No. 148 However, the accounting profession has recendy determined In December 2002, the Financial Accounting Standards Board that SFAS No. 143 precludes the recognition of expected costs (FASB) issued SFAS No. 148, Accounting fr Stock-Based of retiring assets in excess of anticipated salvage proceeds as a Compensation- Transition and Disclosure-anamendment of component of depreciation expense or accumulated depreciation FASB Statement No. 123. SFAS No. 148 provides alternative unless they are legal obligations under SFAS No. 143. Instead, methods of transition for a voluntary change to fair value-based we must recognize these costs as incurred.
methods of accounting for stock-based employee compensation. We currently are evaluating the impact of this new The Statement also amends the disclosure requirements of guidance on our implementation of SFAS No. 143 and on our SFAS No. 123 to require prominent disclosures in both annual financial results. For our merchant energy business, we expect and interim financial statements about the method of accounting the elimination of cost of removal in excess of anticipated for stock-based employee compensation and the effect of the salvage proceeds from accumulated depreciation to increase the method used on reported results. The provisions of the $68 million after-tax gain we recorded in January 2003 discussed Statement were effective for financial statements for fiscal years above. On a comparable basis, we expect depreciation expense ending after December 15, 2002. for 2003 and future years to be lower than prior years since the depreciation expense will no longer include a component for anticipated cost of removal in excess of salvage. Also, effective January 1, 2003 we will only record those asset removal costs that represent legal obligations under SFAS No. 143 prior to their being incurred.
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_ lI -L As of the date of this report, we cannot determine the In order to apply FIN 46, we must evaluate every entity ultimate impact on the cumulative effect adjustment under SFAS with which we are involved through variable interests to No. 143 given the new accounting guidance. However, we determine whether the entity is a VIE and, if it is, whether or expect the impact of this determination to be material to our not we are the primary beneficiary of the entity. The primary financial results. beneficiary of a VIE is the entity that receives the majority of We do not expect the adoption of SFAS No. 143 to be the entity's expected losses, residual returns, or both. FIN 46 material to BGE's financial results. BGE is required by the requires us to disclose information about significant variable Maryland PSC to use the composite depreciation method under interests we hold and to consolidate a VIE for which we are the regulatory accounting. As a result, we expect the impact of the primary beneficiary. As a result, FIN 46 could result in new guidance to be limited to a balance sheet reclassification of consolidation of an entity that we are associated with other than cost of removal from accumulated depreciation to regulatory by (and even in the absence of) a voting ownership interest.
assets and liabilities. The requirements of FIN 46 apply immediately to all VIEs created after January 31, 2003 and are effective beginning in the SFAS No. 146 third quarter of 2003 for all VIEs created before February 1, In July 2002, the FASB issued SFAS No. 146, Accounting for 2003. At the time of initially applying FIN 46 to previously Exit or DisposalActivities. SFAS No. 146 addresses significant unconsolidated VIEs, we will remove from our Consolidated issues regarding the recognition, measurement, and reporting of Balance Sheets any previously recognized amounts related to costs that are associated with exit and disposal activities, those entities and record the carrying value of the assets, induding restructuring activities that are currently accounted for liabilities, and minority interest as reflected in their financial under EITF 94-3. The provisions of the Statement will be statements. The difference between the net amount added to the effective for disposal activities initiated after December 31, 2002, Consolidated Balance Sheets and the amounts removed (if any) with early application encouraged. We will reflect the upon initial adoption of FIN 46 must be recorded in earnings as requirements of this statement in any exit or disposal initiatives the cumulative effect of an accounting change.
after its effective date. Based upon our initial review of entities with which we are involved through variable interests, we believe that some of these FIN 45 entities are VIEs for which we will have to make disclosures or In November 2002, the FASB issued Interpretation No. (FIN) which we will be required to consolidate when we apply FIN 46 45, GuarantorsAccounting and Disclosure Requirementsfor in the third quarter of 2003. The VIEs for which we are the Guarantees, Including Indirect Guarantees of Indebtedness of Others. primary beneficiary (and therefore will have to consolidate)
This Interpretation provides the disclosures to be made by a include the High Desert Power Project, a geothermal power guarantor in interim and annual financial statements about project, the Safe Harbor Water Power Corporation, and an office obligations under certain guarantees. The Interpretation also building in Annapolis, Maryland, that we partially occupy. The clarifies that a guarantor is required to recognize, at the other VIEs with which we are involved (but not as primary inception of a guarantee, a liability for the fair value of the beneficiary) include certain other power projects and fuel obligation. The initial recognition and measurement processing facilities.
requirements are effective prospectively for guarantees issued or Our variable interests in these entities generally consist of modified after December 31, 2002. However, the disclosure equity investments and, in some instances, guarantees of the requirements of the interpretation are effective for this entities' debt or the value of the entities' assets. The following is Form 10-K and are included in Note 11. summary information about these entities as of December 31, 2002:
FIN 46 In January 2003, the FASB issued FIN 46, Consolidation of Primary Significant Variable Interest Entities, that addresses conditions when an entity Beneficiary Interest Total should be consolidated based upon variable interests rather than (In millions) voting interests. Variable interests are ownership interests or Total assets $802 $472 $1,274 contractual relationships that enable the holder to share in the Total liabilities 618 419 1,037 financial risks and rewards resulting from the activities of a Our ownership interest 124 19 143 Variable Interest Entity (VIE). A VIE is a corporation, Other ownership interests 60 34 94 partnership, trust, or any other legal structure used for business Our maximum exposure to purposes that either does not have equity investors with voting loss 662 68 730 rights or has equity investors that do not provide sufficient financial resources for the entity to support its activities.
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We believe that the net amount we will add to our We reviewed our portfolio of mark-to-market contracts to Consolidated Balance Sheets when we consolidate VIEs for identify the contracts that are subject to the requirements of which we are the primary beneficiary is approximately equal to EITF 02-3. The primary contracts that are affected are our full our recorded investment and will not result in recording a requirements load-serving contracts and unit-contingent power cumulative effect of an accounting change upon initial adoption purchase contracts, which are not derivatives. The majority of of FIN 46. The maximum exposure to loss represents the loss these contracts are in Texas and New England and were entered that we would incur if our investment in all of these entities into prior to the shift to accrual accounting earlier in 2002.
were to become worthless and we were required to fund the full Additionally, we reviewed derivatives we use as supply sources amount of all guarantees associated with these entities. Our and hedges of contracts that are subject to EITF 02-3. To the maximum exposure to loss as of December 31, 2002 consists of extent permitted by SFAS No. 133, we designated derivative the following: contracts used to fulfill our load-serving contracts as either
- our guarantee of $507 million of the High Desert lease normal purchases or cash flow hedges under SFAS No. 133 and a portion of other committed expenses as discussed effective January 1, 2003.
in Note 10, We summarize the impact on our Consolidated Balance
- our recorded investment in these VIEs totaling Sheets of applying EITF 02-3 on January 1, 2003 as follows:
$196 million, and
- guarantees of $27 million of the debt of these VIEs. Assets Liabilities Net We assess the risk of a loss equal to our maximum exposure (In millions) to be remote. Mark-to-market energy contracts Current $ 144.0 $ 94.1 $ 49.9 EITF 02-3 Noncurrent 1,348.2 881.5 466.7 On October 25, 2002, the EITF reached a consensus on Issue Total 1,492.2 975.6 516.6 02-3, Recognition and Reporting of Gains and Losses on Energy Other Trading Contracts Under EITF Issues No. 98-10 and No. 00-17, Current 85.7 56.8 28.9 that changed the accounting for certain energy contracts. The Noncurrent 24.2 2.5 21.7 main provisions of EITF 02-3 are as follows:
Total 109.9 59.3 50.6
- EITF 02-3 prohibits the use of mark-to-market accounting for any energy-related contracts that are not Balance at December 31, 2002 1,602.1 1,034.9 567.2 derivatives. Any contracts subject to EITF 02-3 must be Impact of EITF 02-3 Adoption accounted for on the accrual basis and recorded in the Non-derivative net asset reversed income statement gross rather than net upon application as cumulative effect of a change of EITF 02-3. This change applied immediately to new in accounting principle contracts executed after October 25, 2002 and applied Mark-to-market energy contracts (494.7) (119.8) (374.9) to existing non-derivative energy-related contracts Other (109.9) (59.3) (50.6) beginning January 1, 2003.
- We are required to report the impact of initially Total non-derivative net asset applying EITF 02-3 as the cumulative effect of a change reversed as cumulative effect of in accounting principle effective January 1, 2003. a change in accounting principle (604.6) (179.1) (425.5)
- The EITF minutes on Issue 02-3 indicate that an entity Derivatives designated as hedges (88.3) (94.4) 6.1 should not record unrealized gains or losses at the Derivatives designated as normal inception of derivative contracts unless the fair value of purchases and sales (192.6) (128.3) (64.3) the contracts is evidenced by observable market data.
Mark-to-market derivatives Applying EITF 02-3 will not affect our cash flows or our remaining after adoption of accounting for new load-serving contracts for which we have EITF 02-3 on January 1, 2003 $ 716.6 $ 633.1 $ 83.5 been using accrual accounting since early 2002. Additionally, we continued to mark existing non-derivative energy-related contracts to market for the remainder of 2002. However, EITF 02-3 requires us to record a non-cash, cumulative effect adjustment to convert these non-derivative mark-to-market contracts to accrual accounting no later than January 1, 2003.
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I On January 1, 2003, we recorded the $425.5 million Additionally, on January 1, 2003, we reclassified the fair non-derivative net asset removed from our Consolidated value of derivatives designated as hedges as "Risk management Balance Sheets as a cumulative effca of a change in accounting assets and liabilities" in the balance sheet and will account for principle, which will reduce our 2003 net income by these hedges in accordance with the provisions of SFAS
$263 million. The $425.5 million represents $374.9 million of No. 133. At that time, we also reclassified the fair value of non-derivative contracts recorded as "Mark-to-market energy derivatives designated as normal purchases and normal sales as assets and liabilities" and $50.6 million of "Other assets and "Other assets and liabilities" in the balance sheet and will liabilities" from the re-designation of Texas contracts to accrual account for these contracts on the accrual basis, with the fair accounting earlier in 2002. The fair value of these contracts value amortized into earnings over the lives of the underlying will be recognized in earnings as power is delivered. contracts.
2 Impairment Losses, Workforce Reduction, Contract Termination, and Other Special Items 2002 Events
- We reversed $17.8 million of the $25.1 million Pre-Tax After-Tax involuntary severance accrual that was recorded in 2001 (In millions) to reflect the employees that elected the age 50 to 54 Workforce reduction costs: VSERP Ultimately, we involuntarily severed 129 Costs associated with 2001 programs $ (50.8) $ (30.8) employees that resulted in a total cost for the Costs associated with programs involuntary severance program of $7.3 million.
initiated in 2002 (12.0) (7.2)
- We recorded $29.6 million of settlement charges related to our pension plans under SFAS No. 88, Employers' Total workforce reduction costs (62.8) (38.0) Accounting fir Settlements and Curztailments of Defined Impairment losses and other costs: Benefit Pension Plans andf/or Termination Benefits. These Impairments of investments in charges reflect the recognition of actuarial gains and qualifying facilities and power losses associated with employees who have retired and projects (14.4) (9-9) taken their pension in the form of a lump-sum Costs associated with exit of BGE payment. Under SFAS No. 88, the settlement charge Home merchandise stores (9.0) (6.1) could not be recognized until lump-sum pension Impairments of real estate and payments exceeded annual pension plan service and international investments (1.8) (1.2) interest cost, which occurred in 2002.
- We recorded a $1.6 million expense associated with Total impairment losses and other costs (25.2) (17.2) deferred payments to employees eligible for the VSERP.
Net gain on sales of investments and
- Partially offsetting these costs, we reversed approximately other assets 261.3 166.7
$2.6 million of previously accrued workforce reduction Total special items $ 173.3 $ 111.5 costs primarily as a result of the reversal of education and outplacement assistance benefits we accrued that Workforce Reduction Costs employees did not utilize to the extent expected.
During 2002, we incurred costs related to workforce reduction In 2002, we completed the 2001 workforce reduction efforts initiated in the fourth quarter of 2001 as discussed in programs. Accordingly, no involuntary severance liability this Note and additional initiatives undertaken in the third recorded under EITF 94-3, Liability Recognition for Certain quarter of 2002. We discuss these costs in more detail below. Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring) remained at December 31, 2002.
Costs associated with 2001 Programs In 2002, we recorded $63.7 million of net workforce reduction costs associated with our 2001 workforce initiatives as discussed Costs associated with 2002 Programs below. The $63.7 million included $50.8 million recognized as In 2002, we recorded $12.0 million of expenses for anticipated expense, of which BGE recognized $33.8 million. The involuntary severance costs in accordance with EITF 94-3 remaining $12.9 million was recognized by BGE as a regulatory associated with new workforce reduction initiatives as follows:
asset related to its gas business as discussed in Note 5.
- We recorded $8.5 million for workforce reduction costs
- We recorded $52.9 million when 308 employees elected for the severance of 120 employees at Calvert Cliffs the age 50 to 54 Voluntary Special Early Retirement Nuclear Power Plant (Calvert Cliffs).
Program (VSERP).
I I
- We recorded $1.6 million of workforce reduction costs
- We recognized a $6.6 million other than temporary for the severance of 27 employees in our information decline in value of our investment in a partnership that technology organization. BGE recorded $0.6 million of owns a waste burning power project in Michigan. In this amount. 2001, we recognized a $6.1 million pre-tax impairment
- We recorded $1.9 million of workforce reduction costs loss on this investment because we expected operating for the severance of 20 employees in our legal cash flows would not be sufficient to pay existing debt organization. BGE recorded $0.9 million of this service and that we would not be able to recover our amount. equity investment. However, at that time, we believed At December 31, 2002, the involuntary severance liability that we would recover our senior working capital loans recorded under EITF 94-3 for our 2002 workforce reduction receivable and accounts receivable for operating the programs was $12.0 million. project. As of the third quarter of 2002, the operating performance of the project did not improve as expected, Impairment Losses and Other Costs and we believed the expected future cash flows were no Investments in Qualijying Facilitiesand Power Projects longer sufficient to recover these receivables. Therefore, In the third quarter of 2002, our merchant energy business we recognized an additional impairment loss on this recorded impairment losses on certain of the investments in investment.
qualifying facilities and power projects totaling $14.4 million under the provisions of APB No. 18. We describe these Closing of BGE Home Retail Merchandise Stores investments in Note 4. The provisions of APB No. 18 require In September 2002, we announced our decision to close our that an impairment loss be recognized when an investment BGE Home retail merchandise stores. In connection with that experiences a loss in value that is other than temporary as decision, we recognized approximately $9.5 million in exit costs.
discussed in Note 1. We recognized $2.9 million related to expected severance costs During the third quarter of 2002, we performed an analysis for 93 employees and $2.9 million of costs in connection with of whether any of the investments were impaired. As a result of the termination of leases for the eight stores and other exit costs our analysis, we concluded that the declines in value of in accordance with EITF 94-3.
particular investments in certain qualifying facilities and power We also recognized $3.2 million for the write-off of projects were other than temporary in nature under the unamortized leasehold improvements in accordance with SFAS provisions of APB No. 18 and we recognized the following losses No. 144, and $0.5 million for the write-down of inventory to a in 2002: lower-of-cost-or-market valuation in accordance with Accounting
- We recognized a $5.2 million other than temporary Research Bulletin No. 43, Restatement and Revision ofAccounting dedine in value of our investment in a partnership that Research Bulletins. The $0.5 million is included in "Operating owns a geothermal project in Nevada. This project expenses" in our Consolidated Statements of Income.
experienced a well implosion and we believe that the expected cash flows from the project will not be Real Estate and InternationalInvestments sufficient to recover our equity interest in that As discussed in the 2001 Events section on the next page, we partnership. changed our strategy from an intent to hold to an intent to sell
- We recognized a $2.6 million other than temporary for certain of our non-core assets in 2001. During 2002, we decline in value of our investment in a fuel processing determined that the fair value of several real estate projects and site in Pennsylvania where the expected cash flows from our investment in a South American generation project declined a sublease are no longer expected to be sufficient to below their respective book values due to deteriorating market recover our lease costs associated with this site. conditions for these projects. Accordingly, we recorded losses that totaled $1.8 milion for these projects in accordance with SFAS No. 144 and APB No. 18.
Net Gain on Sales of Investments and Other Assets In February 2002, Reliant Resources, Inc. acquired all of the outstanding shares of Orion Power Holdings, Inc. (Orion) for
$26.80 per share, including the shares we owned of Orion. We received cash proceeds of $454.1 million and recognized a gain of $255.5 million on the sale of our investment.
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In the fourth quarter of 2001, we announced our decision Workforre Reduction Costs to focus efforts and capital on core domestic energy businesses Voluntary Special Early Retirement Prograums-VSERP and undertook a plan to sell a number of non-core businesses In the fourth quarter of 2001, we undertook several measures to and investments. In 2002, we made further progress on this reduce our workforce through both voluntary and involuntary initiative, and recognized approximately $5.8 million in net means. The purpose of these programs was to reduce our gains from the sale of several non-core assets including: operating costs to become more competitive. We offered several
- Our other nonregulated businesses recognized gains workforce reduction programs to employees of Constellation totaling $6.7 million on the sale of several parcels of Energy and certain subsidiaries. The first group of these real estate and financial investments. programs offered enhanced early retirement benefits to
- In October 2002, we sold all of our 18 senior-living employees age 55 or older with 10 or more years of service. The facilities for $77.2 million that represents a combination second group of these programs offered enhanced early of cash and the assumption by the buyer of existing retirement benefits to employees age 50 to 54 with 20 or more mortgages. Our other nonregulated businesses recognized years of service.
a $2.8 million gain on the sale of our entire ownership Since employees electing to participate in the age 55 or interest in these facilities. older VSERP had to make their elections by the end of 2001,
- Our merchant energy business recognized a $2.3 million the cost of that program was reflected in 2001. The gain on the sale of a discontinued wind-powered $70.1 million in the above table reflects the portion of the total development project. cost of that program charged to expense for the 507 employees
- In 2001, our merchant energy business recognized an that elected to participate. BGE recorded $37.9 million of this impairment loss on four turbines, associated with a amount. BGE also recorded $13.7 million on its balance sheet discontinued development program as discussed in the as a regulatory asset related to its gas business as discussed in 2001 Events section. Since that time, many other Note 5.
companies canceled development projects and the market values for turbines have declined significantly. Settlement and Curtailment Charges Orders for three of the four turbines were canceled with In connection with the age 55 or older VSERP, a significant termination fees paid to the manufacturer consistent number of the participants in our nonqualified pension plans with the amount recognized in December 2001. The retired. As a result, we recognized a settlement loss of fourth rurbine-generator set was sold during 2002 for approximately $10.5 million and a curtailment loss of
$6.0 million below its book value. approximately $5.8 million for those plans in accordance with SFAS No. 88. BGE recorded $6.6 million of this amount.
2001 Events Additional details on the VSERP and their impact on our pension and postretirement benefit plans are discussed in Note 6.
Pre- After-Tax Tax (In millions) Involuntary Severance Accrual Workforce reduction costs: The voluntary programs were designed, offered, and timed to Voluntary termination benefits-VSERP $ (70.1) $ (42.5) minimize the number of employees who would be involuntarily Settlement and curtailment charges (16.3) (9.9) severed under our overall workforce reduction plan. Our Involuntary severance accrual (19.3) (11.7) workforce reduction plan identified 435 jobs to be eliminated over and above position reductions expected to be satisfied Total workforce reduction costs (105.7) (64.1) through the age 55 or older VSERP and was specific as to Contract termination related costs (224.8) (139.6) company, organizational unit, and position. However, the number of employees that would elect to voluntarily retire under Impairment losses and other costs: the age 50 to 54 VSERP and how many would thereafter be Cancellation of domestic power projects (46.9) (30.5) involuntarily severed was not known until after the election Impairments of real estate, senior-living period of the VSERP ended in February 2002.
and international investments (107.3) (69.7) In accordance with EITF 94-3, the Company recognized a Reduction of financial investment (4.6) (2.8) liabiliry of $25.1 million at December 31, 2001 for the targeted Total impairment losses and other costs (158.8) (103.0) number of involuntary terminations that would have resulted if Net gain on the sales of investments and no employees elected the age 50 to 54 VSERP The other assets 6.2 1.9 $19.3 million in the table above represents involuntary severance charged to expense in 2001 in connection with our workforce Total special items $(483.1) $(304.8) reduction programs. BGE recorded $12.5 million of this amount. BGE also recorded $5.8 million on its balance sheet as a regulatory asset related to its gas business as discussed in Note 5.
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Contract Termination Related Costs Impairments of Real Estate, Senior-Living, and Other International On October 26, 2001, we announced the decision to remain a Investments single company and canceled prior plans to separate our In the fourth quarter of 2001, our other nonregulated businesses merchant energy business from our remaining businesses. recorded $107.3 million in impairments of certain real estate We also announced the termination of our power business projects, senior-living facilities, and international assets to reflect services agreement with Goldman Sachs. We paid Goldman the fair value of these investments. These investments represent Sachs a total of $355 million, representing $196.7 million to non-core assets with a book value of approximately terminate the power business services agreement with our $140.6 million after these impairments. As part of our focus on origination and risk management operation and $159 million capital and cash requirements and on our core energy businesses, previously recognized as a payable for services rendered under the following occurred:
the agreement.
- We decided to sell six real estate projects without further In addition, we terminated a software agreement we had development and all of our 18 senior-living facilities in whereby Goldman Sachs would provide maintenance, support, 2002 and accelerate the exit strategies for two other real and minor upgrades to our risk management and trading system. estate projects that we will continue to hold and own We recognized $17.6 million in expense in the fourth quarter of over the next several years. The real estate projects 2001 representing the unamortized prepaid costs related to this include approximately 1,300 acres of land holdings in agreement. Finally, we incurred approximately $10.5 million in various stages of development located in seven sites in employee-related expenses and advisory costs from investment the central Maryland region and an operating waste bankers and legal counsel. In total, we recognized expenses of water treatment plant located in Anne Arundel County, approximately $224.8 million in the fourth quarter of 2001 Maryland. In 2002, we sold approximately 800 acres of relating to the termination of our relationship with Goldman land holdings.
Sachs and our decision not to separate.
- We decided to accelerate the exit strategy for our interest in a Panamanian delctric distribution company.
Impairment Losses and Other Costs As a non-core asset, management has decided to reduce Cancellation of Domestic Power Projects the cost and risk of holding this asset indefinitely and In the fourth quarter of 2001, our merchant energy business intends to dispose of this asset.
recorded impairments of $46.9 million primarily due to
- We incurred an other than temporary decline in our
$40.8 million in impairments associated with the termination of equity-method investment in the Bolivian Generating our planned development projects in Texas, California, Florida, Group, which owns an interest in an electric generation and Massachusetts not under construction. We decided to concession in Bolivia. This decline in value resulted terminate our development projects due to the expected excess from a deterioration of our investment's position in the generation capacity in most domestic markets and the significant dispatch curve of its capacity market. As a result, we decline in the forward market prices of electricity. The recorded the impairment in accordance with the impairments include amounts paid for the purchase of four provisions of Accounting Principles Board Opinion turbines related to these development projects. In addition, we No. 18.
recognized $6.1 million for an other than temporary decline in The impairments of our real estate, senior-living facilities, the value of our investment in a waste burning power plant in and Panama investments resulted from our change from an Michigan where operating cash flows are not sufficient to pay intent to hold to an intent to sell certain of these non-core existing debt service and we are not likely to recover our equity assets in 2002, and our decision to limit future costs and risks interest in this investment. by accelerating the exit strategies for certain assets that cannot be sold by the end of 2002. Previously, our strategy for these investments was to hold them until we could obtain reasonable value. Under that strategy, the expected cash flows were greater than our investment and no impairment was recognized.
Reduction of FinancialInvestment Our financial investments operation recorded a $4.6 million reduction of its investment in a leased aircraft due to the other than temporary decline in the estimated residual value of used airplanes as a result of the September 11, 2001 terrorist attacks and the general downturn in the aviation industry. This investment is accounted for as a leveraged lease under SFAS No. 13, Accountingfor Leases.
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Net Gain on Sals of Investments and Other Assets 2000 Events During 2001, our other nonregulated businesses recognized In 2000, BGE offered a targeted VSERP to employees ages 55
$49.5 million on the sale of non-core assets, including a or older with 10 or more years of service in targeted positions
$14.9 million gain on the sale of one million shares of our that elected to retire on June 1, 2000 to reduce our operating Orion investment and $34.6 million on the sales of other costs to become more competitive. BGE recorded approximately financial investments. $10.0 million pre-tax for employees that elected to participate in In addition, in 2001, we sold our Guatemalan power plant the program. Of this amount, BGE recorded approximately operations to an affiliate of Duke Energy International, LLC, the $3.0 million on its balance sheet as a regulatory asset of its gas international business unit of Duke Energy. Through this sale, business. BGE is amortizing this regulatory asset over a 5-year Duke Energy acquired Grupo Generador de Guatemala y Cia., period as provided by the June 2000 Maryland PSC gas base S.CA, which owns two generating plants at Esquintla and Lake rate order as discussed in Note 5. The remaining $7.0 million, Amatitlan in Guatemala. The combined capacity of the plants is or $4.2 million after-tax, related to BGE's electric business and 167 megawatts. was charged to expense.
We decided to sell our Guatemalan operations to focus our In addition, we recognized $78.1 million pre-tax, or efforts on our core energy businesses. As a result of this $47.2 million after-tax, gains including $15.7 million pre-tax, or transaction, we are no longer committed to making significant $9.5 million after-tax, on the sale of two million shares of our future capital investments in a non-core operation. We recorded Orion investment and $62.4 million pre-tax, or $37.7 million a $43.3 million loss on this sale. after-tax, on the sales of other financial investments.
3 InformatIon by Operating Segment Our reportable operating segments are-Merchant Energy,
- Our remaining nonregulated businesses:
Regulated Electric, and Regulated Gas: - design, construct, and operate single-site heating,
- Our nonregulated merchant energy business in North cooling, and cogeneration facilities for commercial America indudes: and industrial customers,
- fossil, nuclear, and hydroelectric generating - service electric and gas appliances, and heating facilities and interests in qualifying facilities and and air conditioning systems, engage in home power projects in the United States, improvements, and sell electricity and natural gas,
- origination of structured transactions (such as and load-serving, tolling contracts, and power - own and operate a district cooling system for purchase agreements), and risk management commercial customers.
services (hedging of output from generating In addition, we own several investments that we do not facilities and fuel costs), consider to be core operations. These indude financial
- electric and gas retail energy services to large investments, real estate projects, and interests in a Latin commercial and industrial customers, and American power distribution project and in a fund that holds
- generation and consulting services. interests in two South American energy projects. We decided to
- Our regulated electric business purchases, transmits, sell certain non-core assets and accelerated the exit strategies of distributes, and sells electricity in Maryland. other projects. We sold certin non-core assets in 2002 and
- Our regulated gas business purchases, transports, and closed our retail merchandise stores in December 2002.
sells natural gas in Maryland. These reportable segments are strategic businesses based Effective July 1, 2000, the financial results of the electric principally upon regulations, products, and services that require generation portion of our business are included in the merchant different technology and marketing strategies. We evaluate the energy business segment. Prior to that date, the financial results performance of these segments based on net income. We of electric generation are included in our regulated electric account for intersegment revenues using market prices. We business. present a summary of information by operating segment on the next page.
We have reclassified certain prior-year information for comparative purposes based on our reportable operating segments.
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Unallocated Merchant Regulated Regulated Other Corporate Energy Electric Gas Nonregulated Items and Business Business Business Businesses Eliminations Consolidated (In millions) 2002 Unaffiliated revenues $1,629.5 $1,965.6 $ 570.5 $ 537.4 $ - $4,703.0 Intersegment revenues 1,136.2 0.4 10.8 - (1,147.4)
Total revenues 2,765.7 1,966.0 581.3 537.4 (1,147.4) 4,703.0 Depreciation and amortization 242.8 174.2 47.4 16.6 - 481.0 Fixed charges 102.0 128.4 25.9 25.2 - 281.5 Income tax expense 127.2 67.1 22.4 92.9 - 309.6 Net income (a) 247.2 99.3 31.1 148.0 - 525.6 Segment assets 8,866.0 3,565.1 1,140.4 913.0 (355.6) 14,128.9 Capital expenditures 641.0 167.0 50.0 65.0 - 923.0 2001 Unaffiliated revenues $ 614.3 $2,039.6 $ 674.3 $ 550.6 $ - $3,878.8 Intersegment revenues 1,151.2 0.4 6.4 2.0 (1,160.0)
Total revenues 1,765.5 2,040.0 680.7 552.6 (1,160.0) 3,878.8 Depreciation and amortization 174.9 173.3 47.7 23.2 - 419.1 Fixed charges 25.8 135.8 28.5 48.7 - 238.8 Income tax expense (benefit) 25.2 36.8 25.7 (49.8) - 37.9 Cumulative effect of change in accounting principle - - - 8.5 - 8.5 Net income (loss) (b) 93.1 50.9 37.5 (90.6) - 90.9 Segment assets 8,123.9 3,764.9 1,104.2 1,314.0 (197.6) 14,109.4 Capital expenditures 1,044.0 180.3 58.7 35.0 - 1,318.0 2000 Unaffiliated revenues $ 421.1 $2,134.7 $ 603.8 $ 614.8 $ - $3,774.4 Intersegment revenues 604.6 0.5 7.8 20.4 (633.3)
Total revenues 1,025.7 2,135.2 611.6 635.2 (633.3) 3,774.4 Depreciation and amortization 83.6 319.9 46.2 20.3 - 470.0 Equity in income of equity-method investees (c) 2.4 2.4 Fixed charges 18.3 168.4 27.3 65.8 (8.4) 271.4 Income tax expense 118.5 72.2 21.9 17.5 230.1 Net income (d) 198.6 102.3 30.6 13.8 345.3 Segment assets 7,295.5 3,392.3 1,089.9 1,491.5 (329.9) 12,939.3 Capital expenditures 699.0 290.3 59.7 131.5 1,180.5 (a) Our merchant energy business, our regulatedelectric business, our regulatedgas business, and our other nonregulated businesses recognized after-tax charges (income) of $28.3 million, $20.5 million, $0.8 million, and ($161.1 million), respectively, for workforce reduction costs, business exit costs, impairment lsses and other costs, and net gains on sales of investments and other assets as described in more detail in Note 2.
(b) Our merchant energy business, our regulated elecric business, our rgulatedgas business, and our other nonregulated businesses recognized afier-tax charges of $198.1 million, $33.6 million, $0.8 million, and $72.3 million, respectively, for workforce reduction costs, contract termination related costs, impairment losses and other costs, and a net gain on sales of investments and other assets as described more fully in Note 2.
(c) Our merchant energy business records its equity in the income of equity-method investees in unaffiliated revenues.
(d) Our regulated electric business recorded an after-tax charge of $4.2 million related to employees that ected to participatein a Voluntary Special Early Petirement Program. In addition, our merchant energy business recorded a $15.0 million after-tax deregulation transition cost incurred by our originationand risk management operation. Our other nonregulated businesses also recorded a net gain of $47.2 million on saks of investments and other assets.
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4 Investments Real Estate Projects and Investments The investment in qualifying facilities and domestic power Real estate projects and investments consist of the following. projects were accounted for under the following methods:
At December 31, 2002 2001 At December 31, 2002 2001 (In millions) (In millions)
Operating properties and properties under Equity Method $423.7 $480.3 development $77.8 $101.4 Cost Method 10.5 10.7 Equity interest in real estate investments 8.3 109.3 Total power projects $434.2 $491.0 Total real estate projects and investments $86.1 $210.7 Our percentage voting interest in qualifying facilities and In March 2002, we sold all of our Corporate Office domestic power projects accounted for under the equiry method Properties Trust equity-method investment, approximately ranges from 16% to 50%. Equity in earnings of these power 8.9 million shares, as part of a public offering. We received cash projects were $9.1 million in 2002, $23.1 million in 2001, and proceeds of $101.3 million on the sale, which approximated the $50.2 million in 2000.
book value of our investment. Our power projects accounted for under the equity method See Note 2 for a discussion of impairments recorded in include investments of $260.6 million in 2002 and 2002 and 2001. $296.4 million in 2001 that sell electricity in California under power purchase agreements called "Interim Standard Offer Investments In Qualifying Facilities and Power Projects No. 4" agreements. We discuss these projects further in Note 11.
Our merchant energy business holds up to a 50% ownership Our other nonregulated businesses also held international interest in 28 operating domestic energy projects that consist of energy projects accounted for under the equity method of electric generation, fuel processing, or fuel handling facilities. Of $5.0 million at December 31, 2002 and $8.1 million at these 28 projects, 20 are "qualifying facilities" that receive certain December 31, 2001.
exemptions and pricing under the Public Utility Regulatory See Note 2 for a discussion of impairments recorded in Policy Act of 1978 based on the facilities' energy source or the 2002 and 2001.
use of a cogeneration process.
Investments in qualifying facilities and domestic power Orion and FlnancIal Investments projects held by our merchant energy business consist of the Financial investments consist of the following.
following At December 31, 2002 2001 At December 31, 2002 2001 (In millions)
(In millions) Orion $ - $442.5 Geothermal $151.4 $162.0 Marketable equity securities - 20.2 Coal 133.9 160.4 Financial limited partnerships 24.2 25.8 Hydroelectric 62.6 62.3 Leveraged leases 12.7 14.7 Biomass 52.6 59.4 Total financial investments $ 36.9 $503.2 Fuel Processing 23.2 33.6 Solar 10.5 10.7 We discuss the sale of our investment in Orion in Note 2.
Waste to Energy - 2.6 Total $434.2 $491.0 Investments ClassifIed as Available-for-Sale We classify the following investments as available-for-sale:
- nuclear decommissioning trust funds,
- our other nonregulated businesses' marketable equity securities (shown above), and
- trust assets securing certain executive benefits.
This means we do not expect to hold them to maturity, and we do not consider them trading securities.
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We show the fair values, gross unrealized gains and losses, The preceding tables include $47.4 million in 2002 of net and amortized cost bases for all of our available-for-sale unrealized losses and $21.0 million in 2001 of net unrealized securities, in the following tables. We use specific identification gains associated with the nuclear decommissioning trust funds to determine cost in computing realized gains and losses, except that are reflected as a change in the nudear decommissioning we used the average cost basis for our investment in Orion. trust funds in our Consolidated Balance Sheets.
Gross and net realized gains and losses on available-for-sale Amortized Unrealized Unrealized Fair securities, excluding the gains on our sales of the Orion At December 31, 2002 Cost Basis Gains Losses Value investment, were as follows:
(In millions)
Marketable equity securities $642.6 $18.9 $(69.2) $592.3 2002 2001 2000 Corporate debt and U.S. (In millions)
Government agency 51.5 1.7 (0.1) 53.1 Gross realized gains $ 6.0 $47.6 $54.5 State municipal bonds 22.0 1.3 - 23.3 Gross realized losses (9-5) (7.9) (8.0)
Totals $716.1 $21.9 S(69.3) $668.7 Net realized (losses) gains S(3.5) $39.7 $46.5 The corporate debt securities, U.S. Government agency Amortized Unrealized Unrealized At December 31, 2001 Cost Basis Gains Losses Fair Value obligations, and state municipal bonds mature on the following schedule:
(In millions)
Marketable equity At December 31, 2002 Amount securities $816.1 $270.6 $(10.3) $1,076.4 Corporate debt and U.S. (In millions)
Government agency 47.7 1.5 - 49.2 Less than I year $ 5.4 State municipal bonds 38.4 3.3 (0.2) 41.5 1-5 years 30.7 5-10 years 22.1 Totals $902.2 $275.4 $(10.5) $1,167.1 More than 10 years 18.2 In addition to the above securities, the nuclear Total maturities of debt securities $76.4 decommissioning trust funds included $14.0 million at December 31, 2002 and $7.7 million at December 31, 2001 of cash and cash equivalents.
5 Regulatory Assets (net)
As discussed in Note 1, the Maryland PSC and the FERC We summarize regulatory assets and liabilities in the provide the final determination of the rates we charge our following table, and we discuss each of them separately below.
customers for our regulated businesses. Generally, we use the same accounting policies and practices used by nonregulated At December 31, 2002 2001 companies for financial reporting under accounting principles (In millions) generally accepted in the United States of America. However, sometimes the Maryland PSC orders an accounting treatment Electric generation-related regulatory asset $230.1 $249.0 different from that used by nonregulated companies to Income taxes recoverable through future determine the rates we charge our customers. When this rates (net) 88.8 95.6 happens, we must defer certain utility expenses and income in Deferred postretirement and our Consolidated Balance Sheets as regulatory assets and postemployment benefit costs 32.3 35.5 liabilities. We then record them in our Consolidated Statements Deferred environmental costs 23.2 26.0 of Income (using amortization) when we include them in the Deferred fuel costs (net) 1.9 33.5 rates we charge our customers. Workforce reduction costs 28.2 21.6 Other (net) 1.2 2.6 Total regulatory assets (net) $405.7 $463.8 91
Electric Generation-Related Regulatory Asset Deferred Environmental Costs As a result of the deregulation of electric generation, BGE no Deferred environmental costs are the estimated costs of longer met the requirements for the application of SFAS No. 71 investigating and cleaning up contaminated sites we own. We for the electric generation portion of its business. In accordance discuss this further in Note 11. We are amortizing $21.6 million with SFAS No. 101 and EITF 97-4, all individual generation- of these costs (the amount we had incurred through related regulatory assets and liabilities must be eliminated from October 1995) and $6.4 million of these costs (the amount we our balance sheet unless these regulatory assets and liabilities will incurred from November 1995 through June 2000) over 10-year be recovered in the regulated portion of the business. BGE periods in accordance with the Maryland PSC's orders.
wrote-off all of its individual, generation-related regulatory assets and liabilities. BGE established a single, new generation-related Deferred Fuel Costs regulatory asset for amounts to be collected through its regulated As described in Note 1, deferred fuel costs are the difference transmission and distribution business. The new regulatory asset between our actual costs of natural gas and our fuel rate is being amortized on a basis that approximates the pre-existing revenues collected from customers. We reduce deferred fuel costs individual regulatory asset amortization schedules. as we collect them from or refund them to our customers.
A portion of this regulatory asset represents the In December 2002, a Hearing Examiner from the decommissioning and decontamination hind payment for federal Maryland PSC issued a proposed order related to our annual gas uranium enrichment facilities that does not earn a return on the adjustment clause review proceeding that will allow us to recover rate base investment. These amounts were $16.3 million at $1.7 million of a previously established regulatory asset of December 31, 2002 and $19.2 million at December 31, 2001. $9.4 million for certain credits that were over-refunded to Prior to the deregulation of electric generation, these costs were customers through our market-based rates. BGE reserved the recovered through the electric fuel rate mechanism, and were remaining difference of $7.7 million as disallowed fuel costs.
excluded from rate base. We will continue to amortize this However, we appealed the proposed order. As of the date of this amount through 2008. report, the Maryland PSC has not acted on BGE's appeal.
Our gas deferred fuel costs were $1.9 million at Income Taxes Recoverable Through Future Rates (net) December 31, 2002 and $33.5 million at December 31, 2001.
As described in Note 1, income taxes recoverable through future We exclude gas deferred fuel costs from rate base because rates are the portion of our net deferred income tax liability that their existence is relatively short-lived. These costs are recovered is applicable to our regulated utility business, but has not been in the following year through the market-based rate mechanism.
reflected in the rates we charge our customers. These income taxes represent the tax effect of temporary differences in Workforce Reduction Costs depreciation and the allowance for equity funds used during The portions of the costs associated with the VSERP and construction, offset by differences in deferred tax rates and workforce reduction programs we announced that relate to deferred taxes on deferred investment tax credits. We amortize BGE's gas business are deferred as regulatory assets in accordance these amounts as the temporary differences reverse. with the Maryland PSC's orders in prior rate cases. These costs are amortized over 5-year periods. See Note 2 and Note 6.
Deferred Postretirement and Postemployment Benefit Costs Deferred postretirement and postemployment benefit costs are the costs we recorded under SFAS No. 106 (for postretirement benefits) and No. 112 (for postemployment benefits) in excess of the costs we included in the rates we charge our customers. We began amortizing these costs over a 15-year period in 1998. We discuss these costs further in Note 6.
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6 Penslon, Postretirement, Other Postemployment, and Employee Savings Plan Benefits We offer pension, postretirement, other postemployment, and For our regulated utility business, we accounted for the employee savings plan benefits. We describe each of these increase in annual postretirement benefit costs under two separately below. Nine Mile Point offers its own pension, Maryland PSC rate orders:
postretirement, other postemployment, and employee savings
- in an April 1993 rate order, the Maryland PSC allowed plan benefits to its employees. The benefits for Nine Mile Point us to expense one-half and defer, as a regulatory asset are included in the tables beginning on the next page. (see Note 5), the other half of the increase in annual postretirement benefit costs related to our regulated Pension Benefits electric and gas businesses, and We sponsor several defined benefit pension plans for our
- in a November 1995 rate order, the Maryland PSC employees. These include basic qualified plans that most allowed us to expense all of the increase in annual employees participate in and several nonqualified plans that are postretirement benefit costs related to our regulated gas available only to certain employees. A defined benefit plan business.
specifies the amount of benefits a plan participant is to receive Beginning in 1998, the Maryland PSC authorized us to:
using information about the participant. Employees do not
- expense all of the increase in annual postretirement contribute to these plans. Generally, we calculate the benefits benefit costs related to our regulated electric business, under these plans based on age, years of service, and pay. and Sometimes we amend the plans retroactively. These
- amortize the regulatory asset for postretirement benefit retroactive plan amendments require us to recalculate benefits costs related to our regulated electric and gas businesses related to participants' past service. We amortize the change in over 15 years.
the benefit costs from these plan amendments on a straight-line Effective in 2002, we amended our postretirement medical basis over the average remaining service period of active plans for all affiliates other than Nine Mile Point. Our employees. contributions for retiree medical coverage for future retirees that We fund the plans by contributing at least the minimum were under the age of 55 on January 1, 2002 are capped at the amount required under Internal Revenue Service regulations. We 2002 level. We also amended our plans to increase the Medicare calculate the amount of funding using an actuarial method eligible retirees' share of medical costs.
called the projected unit credit cost method. The assets in all of the plans at December 31, 2002 were mostly marketable equity VSERP and fixed income securities. In 2000, we offered a targeted VSERP to provide enhanced early retirement benefits to certain eligible participants in targeted jobs Postretirement Benefits at BGE that elected to retire on June 1, 2000. BGE recorded We sponsor defined benefit postretirement health care and life approximately $10.0 million ($7.6 million for pension insurance plans that cover substantially all of our employees. termination benefits and $2.4 million for postretirement benefit Generally, we calculate the benefits under these plans based on costs) for employees that elected to participate in the program.
age, years of service, and pension benefit levels. We do not fund Of this amount, BGE recorded approximately $3.0 million on these plans. its balance sheet as a regulatory asset of its gas business. We For nearly all of the health care plans, retirees make amortize this regulatory asset over a 5-year period as provided contributions to cover a portion of the plan costs. for in prior Maryland PSC rate orders. The remaining Contributions for employees who retire after June 30, 1992 $7.0 million related to BGE's electric business was charged to are calculated based on age and years of service. The amount of expense.
retiree contributions increases based on expected increases in In.2001, our Board of Directors approved several voluntary medical costs. For the life insurance plan, retirees do not make retirement programs for Constellation Energy and certain contributions to cover a portion of the plan costs. subsidiaries. The first group of these programs offered enhanced Effective January 1, 1993, we adopted SFAS No. 106, early retirement benefits to employees age 55 or older with 10 Employers' Accounting for Postretirement Benefits Other Than or more years of service. The second group of these programs Pensions. The adoption of that statement caused: offered enhanced early retirement benefits to employees age 50
- a transition obligation, which we are amortizing over to 54 with 20 or more years of service.
20 years, and
- an increase in annual postretirement benefit costs.
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Since employees electing to participate in the age 55 or In 2002, we recorded an additional minimum pension older VSERP had to make their elections by the end of 2001, liability of $189.5 million as a result of the decreases in the fair the cost of that program was reflected in 2001. The total cost of value of plan assets due to continued declines in the equity that program was approximately $83.8 million ($63.5 million in markets. We recorded $5.8 million of this adjustment as a pension termination benefits, $18.5 million in postretirement reduction to an intangible asset. We included the remaining benefit costs, and $1.8 million in education and outplacement $195.3 million, or $118.1 million after-tax, of this adjustment assistance costs). Of this amount, BGE recorded approximately in "Accumulated other comprehensive income."
$13.7 million on its balance sheet as a regulatory asset of its gas The cost of the voluntary retirement programs and the business. settlement and curtailment losses are not included in the tables The age 50 to 54 program allowed employees to make their of net periodic pension and postretirement benefit costs for the elections beginning in 2002. The cost of that program was respective years.
approximately $52.9 million ($43.0 million in pension termination costs, $8.5 million in postretirement benefit costs, Obligations, Assets, and Funded Status and $1.4 million in education and outplacement assistance We show the change in the benefit obligations, plan assets, and costs). Of this amount, BGE recorded approximately funded status of the pension and postretirement benefit plans in
$13.4 million on its balance sheet as a regulatory asset of is gas the following tables.
business. We incurred approximately $0.7 million of postretirement benefit costs related to additional workforce Pensior I Postretirement reduction initiatives in 2002. Benefit ss Benefits In connection with the retirement of a significant number 2002 2001 2002 2001 of the participants in the nonqualified pension plans we (In millions) recognized a settlement loss of approximately $10.5 million and a curtailment loss of approximately $5.8 million for those plans Change in benefit obligation in accordance with SFAS No. 88 in 2001. We recorded Benefit obligation at additional settlement charges of $29.6 million related to our January 1 $1,2'59.2 $1,045.1 $ 475.2 $375.9 qualified and nonqualified pension plans in 2002 as a result of Service cost 29.6 25.8 5.0 8.4 retirees electing to take their pension benefit in the form of a Interest cost 82.2 76.1 26.7 29.2 lump-sum payment.
Plan participants' At December 31, 2002, our pension obligations were contributions 4.7 3.0 greater than the fair value of our plan assets for our qualified Actuarial loss 78.9 42.6 34.9 49.1 and our nonqualified pension plans as follows:
Plan amendments (110.3)
VSERP charge 43.0 63.5 9.2 18.5 Curtailment 9.7 Qualified Plans Non-Qualified Settlement Ci37.9) (23.0)
Nine Mile Other Plans Total Nine Mile Point (In millions) acquisition - 91.8 _ 15.0 Accumulated benefit Benefits paid (21!7.5) (72.4) (30.0) (23.9) obligation $85.7 $981.6 $35.0 $1,102.3 Benefit obligation at Fair value of assets 57.8 709.9 - 767.7 December 31 $1,2' 47.5 $1,259.2 $ 415.4 $475.2 Unfunded obligation $27.9 $271.7 $35.0 $ 334.6 In 2001, we recorded a $133.0 million additional minimum pension liability adjustment primarily as a result of decreases in the fair value of plan assets due to a declining equity market that year. We recorded $59.0 million of this adjustment to an intangible asset included in "Other deferred charges" in our Consolidated Balance Sheets. We included the remaining $74.0 million, or $44.7 million after-tax, of this adjustment in Accumulated other comprehensive income in our Consolidated Statements of Common Shareholders' Equity and Consolidated Statements of Capitalization.
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Pension Postretirement We show the components of net periodic postretirement Benefits Benefits benefit cost in the following table:
2002 2001 2002 2001 (In millions) Year Ended Decenber 31, 2002 2001 2000 Change in plan assets (In millions)
Fair value of plan assets Components of net periodic at January 1 $ 912.2 $1,004.6 $ - $ - postretirement benefit cost Actual return on plan Service cost $ 5.0 $ 8.4 $ 7.7 assets (89.4) (42.7) - - Interest cost 26.7 29.2 26.6 Employer contribution 152.4 22.7 25.3 20.9 Amortization of transition obligation 2.1 7.9 7.9 Plan participants' Recognized net actuarial loss 6.4 3.3 3.1 contributions - - 4.7 3.0 Amortization of unrecognized prior Benefits paid (207.5) (72.4) (30.0) (23.9) service cost (3.5) - -
Fair value of plan assets Amount capitalized as construction at December 31 $ 767.7 $ 912.2 $ - $ cost (9.1) (14.5) (10.8)
Net periodic postretirement benefit cost $27.6 $ 34.3 $34.5 Pension Postretirement Benefits Benefits 2002 2001 2002 2001 Assumptions (In millions) We made the assumptions below to calculate our pension and postretirement benefit obligations.
Funded Status Funded Status at Pension Postretiremenr December 31 $(479.8) $(347.0) $(415.4) $(475.2)
Benefits Benefits Unrecognized net At December 31, 2002 2001 2002 2001 actuarial loss 417.8 207.8 135.5 107.8 Unrecognized prior Discount rate 6.75% 7.25% 6.75% 7.25%
service cost 49.9 56.7 (43.8) (0.4) Expected return on plan Unrecognized transition assets 9.00 9.00 N/A N/A obligation - - 21.3 86.9 Rate of compensation Pension- liability increase 4.00 4.00 4.00 4.00 adjustment (322-5) (133.0) -
We assumed the health care inflation rates to be:
Accrued benefit cost $(334.6) $(215.5) $(302.4) $(280.9)
- in 2002, 11.6% for Medicare-eligible retirees and 14.4%
for retirees not covered by Medicare, and Net Periodic Benefit Cost
- in 2003, 11.0% for both Medicare-eligible retirees and We show the components of net periodic pension benefit cost in retirees not covered by Medicare.
the following table: After 2003, we assumed inflation rates will decrease to 8.0% in 2004, 6.0% in 2005, 5.5% from 2006 through 2008 Year Ended December 31, 2002 2001 2000 and 5.0% annually after 2008.
A one-percent increase in the health care inflation rate from (In millions) the assumed rates would increase the accumulated postretirement Components of net periodic benefit obligation by approximately $34.3 million as of pension benefit cost December 31, 2002 and would increase the combined service Service cost $ 29.6 $ 25.8 $ 25.4 and interest costs of the postretirement benefit cost by Interest cost 82.2 76.1 73.1 approximately $2.6 million annually.
Expected return on plan assets (91.0) (87.5) (83.6) A one-percent decrease in the health care inflation rate Amortization of transition from the assumed rates would decrease the accumulated obligation - (0.2) (0.2) postretirement benefit obligation by approximately $29.0 million Amortization of prior service cost 6.7 6.5 6.5 as of December 31, 2002 and would decrease the combined Recognized net actuarial loss 1.3 2.8 2.6 service and interest costs of the postretirement benefit cost by Amount capitalized as construction approximately $2.2 million annually.
cost (2.9) (2.5) (3.4)
Net periodic pension benefit cost $25.9 $ 21.0 $ 20.4 95
I Other Postemployment Benefits We began to amortize the regulatory asset over 15 years We provide the following postemployment benefits: beginning in 1998. The Maryland PSC authorized us to reflect
- health and life insurance benefits to eligible employees this change in our regulated electric and gas base rates to deternined to be disabled under our Disability recover the higher costs in 1998.
Insurance Plan, We assumed the discount rate for other postemployment
- income replacement payments for Nine Mile Point benefits to be 5.75% in 2002 and 5.0% in 2001.
union-represented employees determined to be disabled, and Employee Savings Plan Benefits
- income replacement payments for other employees We, along with several of our subsidiaries, sponsor defined determined to be disabled before November 1995 contribution savings plans that are offered to all eligible (payments for employees determined to be disabled employees of Constellation Energy and certain employees of after that date are paid by an insurance company, and our subsidiaries. The Savings Plans are qualified 401(k) plans the cost is paid by employees). under the Internal Revenue Code. In a defined contribution The liability for these benefits totaled $49.7 million as of plan, the benefits a participant is to receive result from regular December 31, 2002 and $48.7 million as of December 31, contributions to a participant account. Matching contributions 2001. to participant accounts are made under these plans. Matching Effective December 31, 1993, we adopted SFAS No. 112, contributions to these plans were:
Employers'Accountingfor Postemployment Benefits. We deferred, * $13.3 million in 2002, as a regulatory asset (see Note 5), the postemployment benefit * $12.2 million in 2001, and liability attributable to our regulated utility business as of * $10.8 million in 2000.
December 31, 1993, consistent with the Maryland PSC's orders for postretirement benefits (described earlier in this Note).
7 Short-Term Borrowings Our short-term borrowings may include bank loans, commercial The weighted-average effective interest rates for paper, and bank lines of credit. Short-term borrowings mature Constellation Energy's commercial paper were 2.37% for the within one year from the date of issuance. We pay commitment year ended December 31, 2002 and 3.73% for 2001.
fees to banks for providing us lines of credit. When we borrow under the lines of credit, we pay market interest rates. BOGE BGE had no commercial paper outstanding at December 31, Constellation Energy 2002 and 2001.
Constellation Energy had committed bank lines of credit under BGE maintains $200.0 million in annual committed credit three credit facilities of $1.5 billion at December 31, 2002 for facilities, expiring May through November of 2003, in order to short-term financial needs as follows: allow commercial paper to be issued. At December 31, 2002,
- $640 million 364-day revolving credit facility expiring BGE had $200.0 million in unused credit facilities.
in June 2003,
- $640 million three-year revolving credit facility expiring Other Nonregulated Businesses in June 2005, and Our other nonregulated businesses had short-term borrowings
- $188.5 million revolving credit facility expiring in outstanding of $10.5 million at December 31, 2002 and June 2003. $20.1 million at December 31, 2001. The weighted-average We use these facilities to allow issuance of commercial effective interest rates for our other nonregulated businesses' paper and letters of credit primarily for our merchant energy short-term borrowings were 3.61% at December 31, 2002 and business. These facilities can issue letters of credit up to 4.20% for 2001.
approximately $1.1 billion. Letters of credit issued under all of our facilities totaled $338.7 million at December 31, 2002 and
$245.8 million at December 31, 2001. Constellation Energy had no commercial paper outstanding at December 31, 2002 and
$954.9 million at December 31, 2001.
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B Long-Term Debt and Preference Stock Long-temi Debt Holders of the Remarketed Floating Rate Series due Long-term debt matures in one year or more from the date of September 1, 2006 have the option to require BGE to issuance. We summarize our long-term debt in our Consolidated repurchase their bonds at face value on September I of each Statements of Capitalization. As you read this section, it may be year. BGE is required to repurchase and retire at par any bonds helpful to refer to those statements. that are not remarketed or purchased by the remarketing agent.
BGE also has the option to redeem all or some of these bonds ConstellationEnergy at face value each September 1.
Constellation Energy issued the following fixed rate notes during On August 28, 2002, BGE called $11.8 million principal 2002: amount of its 72% Series, due April 15, 2023 First Refunding Maturity Mortgage Bonds in connection with its annual sinking fund.
and Bonds called were redeemed at the price of 100% of principal, Date Repayment Net Principal Issued Dare Proceeds plus accrued interest from April 15, 2002 to August 28, 2002.
(In miUions) 6.35% Notes (interest BGEs Other Long-Term Debt payable semi-annually) $ 600.0 3/02 4/07 $ 595.4 On July 1, 2000, BGE transferred $278.0 million of tax-exempt 7.00% Notes (interest debt to our merchant energy business related to the transferred payable semi-annually) 600.0 3/02 4/12 592.9 assets. At December 31, 2002, BGE remains contingently liable 7.60% Notes (interest for the $269.8 million outstanding balance of this debt.
payable semi-annually) 600.0 3/02 4/32 592.8 On December 20, 2000, BGE issued $173.0 million of 6.125% Notes (interest 6.75% Remarketable and Redeemable Securities (ROARS) due payable semi-annually) 500.0 8/02 9/09 496.1 December 15, 2012. On December 15, 2002, BGE redeemed all 7.00% Notes (interest the outstanding ROARS at 100% of the principal amount.
payable semi-annually) 100.0 12/02 4/12 102.1 We show the weighted-average interest rates and maturity 7.60% Notes (interest dates for BGE's fixed-rate medium-term notes outstanding at payable semi-annually) 100.0 12/02 4/32 99.6 December 31, 2002 in the following table.
Total $2,500.0 $2,478.9 Weighted-Average Maturity We used a portion of the net proceeds to repay short-term Series Interest Rate Dates borrowings, to prepay the sellers' note of $388.1 million originally issued for the acquisition of Nine Mile Point Nuclear B 8.62% 2006 Station (Nine Mile Point), and to fund other acquisitions. C 7.97 2003 D 6.67 2004-2006 BGE E 6.66 2006-2012 BGEs First Refunding Mortgage Bonds G 6.08 2008 BGE's first refunding mortgage bonds are secured by a mortgage Some of the medium-term notes include a "put option."
lien on all of its assets. The generating assets BGE transferred to These put options allow the holders to sell their notes back to subsidiaries of Constellation Energy also remain subject to the BGE on the put option dates at a price equal to 100% of the lien of BGE's mortgage, along with the stock of Safe Harbor principal amount. The following is a summary of medium-term Water Power Corporation and Constellation Enterprises, Inc. notes with put options.
BGE is required to make an annual sinking fund payment Series E Notes Principal Put Option Dates each August I to the mortgage trustee. The amount of the payment is equal to 1% of the highest principal amount of (In millions) bonds outstanding during the preceding 12 months. The trustee 6.75%, due 2012 $60.0 June 2007 uses these funds to retire bonds from any series through 6.75%, due 2012 $25.0 June 2004 and 2007 repurchases or calls for early redemption. However, the trustee 6.73%, due 2012 $25.0 June 2004 and 2007 cannot call the following bonds for early redemption:
- 6/2% Series, due 2003
- 7% Series, due 2007
- 6s%Series, due 2003
- 65/s% Series, due 2008
- 52% Series, due 2004 97
BGE Obligated Mandatorily Redeemable Trust PreferredSecurities Debt Compliance and Covenants On June 15, 1998, BGE Capital Trust I (Trust), a Delaware The credit facilities of Constellation Energy and BGE have business trust established by BGE, issued 10,000,000 Trust limited material adverse change clauses that only consider a Originated Preferred Securities (TOPrS) for $250 million ($25 material change in financial condition and are not directly liquidation amount per preferred security) with a distribution affected by decreases in credit ratings. If these clauses are rate of 7.16%. violated, the lending institutions can decline making new The Trust used the net proceeds from the issuance of the advances or issuing new letters of credit, but cannot accelerate common securities and the preferred securities to purchase a existing amounts outstanding. The long-term debt indentures of series of 7.16% Deferrable Interest Subordinated Debentures due Constellation Energy and BGE do not contain material adverse June 30, 2038 (debentures) from BGE in the aggregate principal change clauses or financial covenants.
amount of $257.7 million with the same terms as the TOPrS. Certain credit facilities of Constellation Energy contain a The Trust must redeem the TOPrS at $25 per preferred security provision requiring Constellation Energy to maintain a ratio of plus accrued but unpaid distributions when the debentures are debt to capitalization equal to or less than 65%. At paid at maturity or upon any earlier redemption. BGE has the December 31, 2002, the debt to capitalization ratios as defined option to redeem the debentures at any time on or after in the credit agreements were no greater than 57%.
June 15, 2003 or at any time when certain tax or other events A BGE credit facility of $50.0 million that expires in occur. August 2003 requires BGE to maintain a ratio of debt to The interest paid on the debentures, which the Trust will capitalization equal to or less than 70%. At December 31, 2002, use to make distributions on the TOPrS, is included in "Interest the debt to capitalization ratio for BGE as defined in the credit expense" in our Consolidated Statements of Income and is agreement was 54%. At December 31, 2002, no amounts were deductible for income tax purposes. outstanding under the BGE facility.
BGE fully and unconditionally guarantees the TOPrS based Failure by Constellation Energy, or BGE, to comply with on its various obligations relating to the trust agreement, these covenants could result in the maturity of the debt indentures, debentures, and the preferred security guarantee outstanding under these facilities being accelerated. The credit agreement. facilities of Constellation Energy contain usual and customary The debentures are the only assets of the Trust. The Trust cross-default provisions that apply to defaults on debt by is wholly owned by BGE because it owns all the common Constellation Energy and certain subsidiaries over a specified securities of the Trust that have general voting power. threshold. Certain BGE credit facilities also contain usual and For the payment of dividends and in the event of customary cross-default provisions that apply to defaults on debt liquidation of BGE, the debentures are ranked prior to by BGE over a specified threshold. The indentures pursuant to preference stock and common stock. which BGE has issued and outstanding mortgage bonds and subordinated debentures provide that a default under any debt Other Nonregulated Businesses instrument issued under the relevant indenture may cause a In November 2002, our other nonregulated businesses entered default of all debt outstanding under such indenture.
into a long-term bank facility of $51.7 million in principal with Constellation Energy also provides credit support to Calvert an interest rate of 3.25% fixed rate plus 3 months Eurodollar Cliffs and Nine Mile Point to ensure these plants have funds to rate (interest payable quarterly), due December 2008 for net meet expenses and obligations to safely operate and maintain the proceeds of $50.4 million. plants.
Revolving Credit Agreement Maturities of Long-Term Debt ComfortLink had a $50 million unsecured revolving credit All of our long-term borrowings mature on the following agreement that matured September 26, 2002. Under this schedule (includes sinking fund requirements):
agreement, ComfortLink had no amount outstanding at Constellation Nonregulated December 31, 2002 and $46.0 million outstanding at Year Energy Business BGE December 31, 2001. (In millions)
On December 18, 2001, ComfortLink entered into a 2003 $ - $ 5.5 $ 284.2
$25.0 million loan agreement with the Maryland Energy 2004 - 7.5 151.5 Financing Administration (MEFA). The terms of the loan 2005 300.0 8.1 43.2 exactly match the terms of variable rate, tax exempt bonds due 2006 - 9.6 463.8 December 1, 2031 issued by MEFA for ComfortLink to finance 2007 600.0 10.5 127.6 the cost of building a chilled water distribution system. The Thereafter 1,900.0 308.6 829.7 interest rate on this debt resets weekly. These bonds, and the Total long-term debt at corresponding loan, can be redeemed at any time at par plus December 31, 2002 $2,800.0 $349.8 $1,900.0 accrued interest while under variable rates. The bonds can also be converted to a fixed rate at ComfortLink's option.
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At December 31, 2002, we had long-term loans totaling Preference Stock
$394.3 million that mature after 2002 which contain certain put Each series of BGE preference stock has no voting power, except options under which lenders could potentially require us to for the following:
repay the debt prior to maturity. At December 31, 2002,
- the preference stock has one vote per share on any
$136.5 million is classified as current portion of long-term debt charter amendment which would create or authorize any as a result of these provisions. shares of stock ranking prior to or on a parity with the preference stock as to either dividends or distribution of Weighted-Average Interest Rates for Variable Rate Debt assets, or which would substantially adversely affect the Our weighted-average interest rates for variable rate debt were: contract rights, as expressly set forth in BGE's charter, of the preference stock, each of which requires the At December 31, 2002 2001 affirmative vote of two-thirds of all the shares of Nonregulated Businesses (including Constelation preference stock outstanding; and Energy)
- whenever BGE fails to pay full dividends on the Floating rate notes -%/ 4.95% preference stock and such failure continues for one year, Loans under credit agreements 4.42 4.60 the preference stock shall have one vote per share on all Mortgage and construction loans 4.39 matters, until and unless such dividends shall have been Tax-exempt debt transferred from BGE 1.97 3.12 paid in full. Upon liquidation, the holders of the Other tax-exempt debt 1.49 1.75 preference stock of each series outstanding are entitled BGE to receive the par amount of their shares and an amount Remarketed floating rate series mortgage bonds 1.91% 4.49% equal to the unpaid accrued dividends.
Floating rate reset notes - 4.14 99
9 Taxes The components of income tax expense are as follows:
Year Ended December 31, 2002 2001 2000 (Dollar amounts in millions)
Income Taxes Current Federal $ 145.0 $ 45.5 $148.2 State 24.2 27.0 48.2 Current taxes charged to expense 169.2 72.5 196.4 Deferred Federal 131.2 (22.4) 53.9 State 17.1 (4.1) (11.8)
Deferred taxes charged to expense 148.3 (26.5) 42.1 Investment tax credit adjustments (7.9) (8.1) (8.4)
Income taxes per Consolidated Statements of Income $ 309.6 $ 37.9 $230.1 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 before income taxes (excluding BGE preference stock dividends) $ 848.4 $133.5 $588.6 Statutory federal income tax rate 35% 35% 35%
Income taxes computed at statutory federal rate 296.9 46.7 206.0 Increases (decreases) in income taxes due to Depreciation differences not normalized on regulated activities 4.8 5.6 12.6 Amortization of deferred investment tax credits (7.9) (8.1) (8.4)
Synthetic fiel tax credits flowed through to income (20.7) (13.4) (6.5)
State income taxes, net of federal income tax benefit 31.4 13.5 31.7 Other 5.1 (6.4) (5.3)
Total income taxes $ 309.6 $ 37.9 $230.1 Effective income tax rate 36.5% 28.4% 39.1%
The major components of our net deferred income tax liability are as follows:
At December 31, 2002 2001 (Do&r anounts in millions)
Deferred Income Taxes Deferred tax liabilities Net property, plant and equipment $ 1,242.4 $1,156.0 Regulatory assets, net 110.7 130.2 Power marketing and risk management activities, net 285.5 227.3 Financial investments and hedging instruments 3.2 153.9 Other 130.3 147.9 Total deferred tax liabilities 1,772.1 1,815.3 Deferred tax assets Accrued pension and postemployment benefit costs 211.8 132.7 Deferred investment tax credits 30.0 35.1 Nuclear decommissioning liability 34.4 32.1 Reduction of investments 53.8 82.3 Other 111.4 102.1 Total deferred tax assets 441.4 384.3 Deferred tax liability, net $ 1,330.7 $1,431.0 Certainprior-year amounts have been reclassified to conform with the currentyears presentation.
100 I I
I 0 Leases There are two types of leases-operating and capital. Capital Accounting rules presently in effect for SPEs formed prior leases qualify as sales or purchases of property and are reported to February 2003, require that an SPE lessor must have in our Consolidated Balance Sheets. Capital leases are not sufficient independent equity at risk in order for us not to material in amount. All other leases are operating leases and are consolidate it. High Desert Power Trust maintains such a level reported in our Consolidated Statements of Income. We expense of equity at risk, since the owners of the Trust maintain a all lease payments associated with our regulated utility minimum of 3% real equity at risk. In January 2003, the FASB operations. We present information about our operating leases issued Interpretation No. 46, Consolidation of Variable Interest below. Entities, which will require us to consolidate the Trust based on the current lease structure beginning July 1, 2003. We discuss Outgoing Lease Payments this further in Note 1.
We, as lessee, lease some facilities and equipment. The lease Under the terms of the lease, we are required to make agreements expire on various dates and have various renewal payments that represent all or a portion of the lease balance if options. construction is terminated prior to completion or we default Lease expense was: under the lease.
- $19.4 million in 2002, In addition, we may be required to either post cash
- $11.7 million in 2001, and collateral equal to the outstanding lease balance or we may elect
- $11.3 million in 2000 to purchase the property for the outstanding lease balance. At At December 31, 2002, we owed future minimum any time during the term of the lease we have the right to pay payments for long-term, noncancelable, operating leases as off the lease and acquire the asset from the lessor. At follows: December 31, 2002, the outstanding lease balance plus other committed expenses was approximately $585 million.
Year The lease with the Trust contains several events of default (In millions) that are commonly found in financings of this type, including 2003 $ 34.6 failure to make all payments when due, failure to comply with 2004 50.8 all covenants, violation of material representations and warranties 2005 52.9 and change of control. In addition, several events of default are 2006 21.7 applicable to us as guarantor, including defaults in other material 2007 16.3 financing agreements and failure to own 100% of BGE's Thereafter 151.6 common stock.
Total future minimum lease payments $327.9 At the conclusion of the lease term in 2006, we have the following options:
The above table includes the operating lease payments for
- renew the lease upon approval of the lessors, the High Desert project in California through 2006. The project
- elect to purchase the property for a price equal to the is scheduled for completion in mid-2003. lease balance at the end of the term, or The High Desert project uses an off-balance sheet financing
- request the lessor to sell the property.
structure through a special-purpose entity (SPE) that qualifies as If the lessor sells the property, we guarantee the payment of an operating lease. Our wholly owned subsidiary, High Desert any difference between the sale proceeds and the lease balance at Power Project LLC, is supervising the construction of, and the time of sale up to a maximum amount of approximately leasing, the High Desert project from High Desert Power Trust, 83% of such lease balance. The lease balance at the end of the an independent SPE created to own and lease the project to our term is currently estimated to be $600 million, which represents subsidiary. Neither Constellation Energy nor any affiliate owns the estimated cost of the project; however, this may vary based any equity or other interest in High Desert Power Trust, which on the ultimate cost of construction and interest incurred during is owned by a consortium of banks and other financial the construction period.
institutions. We provide a guaranty of High Desert Power Project LLC's obligations to the Trust.
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1 _
I I Commitments, Guarantees, and Contingencies Commitments Our merchant energy business enters into various long-term We have made substantial commitments in connection with our contracts for the procurement and delivery of fuels to supply our merchant energy, regulated gas, and other nonregulated generating plant requirements. In most cases, our contracts businesses. These commitments relate to: contain provisions for price escalations, minimum purchase
- purchase of electric generating capacity and energy, levels, and other financial commitments. These contracts expire
- procurement and delivery of fuels, and in various years between 2003 and 2013. In addition, our
- capital for construction programs and loans. merchant energy business enters into long-term contracts for the Our merchant energy business has a long-term contract for capaciry and transmission rights for the delivery of energy to the purchase of electric generating capacity and energy that meet our physical obligations to our customers. These contracts expires in 2013. Portions of this contract became uneconomical expire in various years between 2003 and 2013.
upon the deregulation of electric generation. Therefore, we Our merchant energy business also has committed to recorded a charge and accrued a corresponding liability based on contribute additional capital for our construction program and the net present value of the excess of estimated contract costs to make additional loans to some affiliates, joint ventures, and over the market-based revenues to recover these costs over the partnerships in which they have an interest.
remaining term of the contract. At December 31, 2002, the At December 31, 2002, we estimate the future obligations accrued portion of this contract was $9.2 million. of our merchant energy business in the following table:
2003 2004 2005 2006 2007 Thereafter Total (In millons)
Purchased capaciry and energy $182.8 $106.5 $ 54.2 $ 33.6 $12.9 $ 73.1 $ 463.1 Fuel and transportation 618.5 243.8 70.4 117.6 27.6 94.2 1,172.1 Capital and loans 32.7 0.5 - - - - 33.2 Total future obligations $834.0 $350.8 $124.6 $151.2 $40.5 $167.3 $1,668.4 Our regulated gas business entered into various long-term Sale of Receivables contracts that expire from 2004 to 2012 for the procurement, BGE Home Products & Services has an agreement to sell on an transportation, and storage of gas. These contracts are ongoing basis an undivided interest in a designated pool of recoverable under BGE's gas cost adjustment clause discussed in customer receivables. Under the agreement, BGE Home Note 1. Products & Services can sell up to a total of $50 million. Under BGE Home Products & Services has gas purchase the terms of the agreement, the buyer of the receivables has commitments of $8.4 million in 2003 and $2.7 million in 2004 limited recourse against BGE Home Products & Services. BGE related to its gas program. Home Products & Services recorded reserves for credit losses. At December 31, 2002, BGE Home Products & Services sold Long-Term Power Sales Contracts $47.7 million of receivables under the agreement.
We entered into long-term power sales contracts in connection with our load-serving activities. We also entered into long-term Guarantees power sales contracts associated with certain of our power plants. The terms of our guarantees are as follows:
Our load-serving power sales contracts extend for terms through 2009 and provide for the sale of full requirements energy to Payments/Expiration electricity distribution utilities and certain retail customers. Our 2004- 2006-2003 2005 2007 Thereafter Total power sales contracts associated with our power plants extend for terms into 2011 and provide for the sale of all or a portion of Competitive Supply $1,758.8 $167.0 $ 35.8 $189.4 $2,151.0 Other 16.5 2.8 602.1 415.9 1,037.3 the actual output of certain of our power plants. All long-term contracts were executed at pricing that approximated market Total Guarantees $1,775.3 $169.8 $637.9 $605.3 $3,188.3 rates, including profit margin, at the time of execution.
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At December 31, 2002, Constellation Energy had a total of The development (involving site selection, environmental
$3,188.3 million guarantees outstanding related to loans, credit assessments, and permitting), construction, acquisition, and facilities, and contractual performance of certain of its operation of electric generating and distribution facilities are subsidiaries as described below. These guarantees do not subject to extensive federal, state, and local environmental and represent our incremental obligations and we do not expect to land use laws and regulations. From the beginning phases of fund the full amount under these guarantees. siting and developing, to the ongoing operation of existing or
- Constellation Energy guaranteed $2,151.0 million on new electric generating and distribution facilities, our activities behalf of its subsidiaries for competitive supply activities. involve compliance with diverse laws and regulations that address These guarantees are put into place in order to allow emissions and impacts to air and water, special, protected and the subsidiaries flexibility needed to conduct business cultural resources (such as wedands, endangered species, and with counterparties without having to post substantial archeological/historical resources), chemical, and waste handling cash collateral. While the face amount of these and noise impacts. Our activities require complex and often guarantees is $2,151.0 million, we do not expect to lengthy processes to obtain approvals, permits, or licenses for fund the full amount as our calculated fair value of new, existing, or modified facilities. Additionally, the use and obligations covered by these guarantees was handling of various chemicals or hazardous materials (including
$519.8 million at December 31, 2002. The recorded wastes) requires preparation of release prevention plans and fair value of obligations in our Consolidated Balance emergency response procedures. As new laws or regulations are Sheets for these guarantees was $489.6 million at promulgated, we assess their applicability and implement the December 31, 2002. necessary modifications to our facilities or their operation, as
- Constellation Energy guaranteed $104.5 million required.
primarily on behalf of Nine Mile Point in connection We discuss the significant matters below.
with our acquisition in 2001.
- Constellation Energy guaranteed $56.6 million on Clean Air Act behalf of our other nonregulated businesses primarily for The Clean Air Act affects both existing generating facilities and loans and performance bonds of which $25.7 million new projects. The Clean Air Act and many state laws require was recorded in our Consolidated Balance Sheets at significant reductions in SO2 (sulfur dioxide) and NO. (nitrogen December 31, 2002. oxide) emissions that result from burning fossil fuels. The Clean
- Constellation Energy guaranteed $600.0 million relating Air Act also contains other provisions that could materially affect to the High Desert project as discussed in more detail some of our projects. Various provisions may require permits, in Note 10. This amount is included in the "Other" inspections, or installation of additional pollution control guarantees for 2006 in the table on the previous page. technology or may require the purchase of emission allowances.
- Our merchant energy business guaranteed $12.9 million Certain of these provisions are described in more detail for loans related to certain power projects in which we below.
have an investment. On October 27, 1998, the Environmental Protection
- BGE guaranteed two-thirds of certain debt of Safe Agency (EPA) issued a rule requiring 22 Eastern states and the Harbor Water Power Corporation, an unconsolidated District of Columbia to reduce emissions of NOx. Among other investment. At December 31, 2002, Safe Harbor Water things, the EPA's rule establishes an ozone season, which runs Power Corporation had outstanding debt of from May through September, and a NOX emission budget for
$20.0 million. The maximum amount of BGE's each state, including Maryland and Pennsylvania. The EPA rule guarantee is $13.3 million. Additionally, BGE requires states to implement controls sufficient to meet their guaranteed the TOPrS of $250.0 million as discussed in NOx budget by May 30, 2004. Coal-fired power plants are a Note 8. principal target of NOx reductions under this initiative.
The total fair value of the obligations for our guarantees Many of our generation facilities are subject to NOX recorded in our Consolidated Balance Sheets was $765.3 million reduction requirements under the EPA rule, including those and not the $3.2 billion of total guarantees. We assess the risk located in Maryland and Pennsylvania. At the Brandon Shores of loss from these guarantees to be minimal. and Wagner facilities, we installed emission reduction equipment to meet Maryland regulations issued pursuant to EPA's rule. The Environmental Matters owners of the Keystone plant in Pennsylvania are installing We are subject to regulation by various federal, state and local emissions reduction equipment by July 2003 to meet authorities with regard to: Pennsylvania regulations issued pursuant to EPA's rule. We
- air quality, estimate our costs for the equipment needed at this plant will be
- water quality, and approximately $35 million. Through December 31, 2002, we
- disposal of hazardous substances. have spent approximately $26 million.
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The EPA established new National Ambient Air Quality Clean Water Act Standards for very fine particulates and revised standards for Our facilities are subject to a variety of federal and state ozone attainment that were upheld after various court appeals. regulations governing existing and potential water/wastewater While these standards may require increased controls at some of and stormwater discharges.
our fossil generating plants in the future, implementation could In April 2002, the EPA proposed rules under the Clean be delayed for several years. We cannot estimate the cost of these Water Act that require that cooling water intake structures reflect increased controls at this time because the states, including the best technology available for minimizing adverse Maryland, Pennsylvania, and California, still need to determine environmental impacts. These rules pertain to existing utilities what reductions in pollutants will be necessary to meet the EPA and non-utility power producers that currently employ a cooling standards. water intake structure and whose flow exceeds 50 million gallons The EPA and several states have filed suits against a per day. A final action on the proposed rules is expected by number of coal-fired power plants in Mid-Western and Southern February 2004. The proposed rule may require the installation states alleging violations of the deterioration prevention and of additional intake screens or other protective measures, as well non-attainment provisions of the Clean Air Act's new source as extensive site specific study and monitoring requirements.
review requirements. In 2000, and again in 2002, using its There is also the possibility that the proposed rules may lead to broad investigatory powers, the EPA requested information the installation of cooling towers on four of our fossil and both relating to modifications made to our Brandon Shores, Crane, of our nuclear facilities. Our compliance costs associated with and Wagner plants in Baltimore, Maryland. The EPA also sent the final rules could be material.
similar, but narrower, information requests to two of our newer Pennsylvania waste-coal burning plants. This information is to Waste Disposal determine compliance with the Clean Air Act and state The EPA and several state agencies have notified us that we are implementation plan requirements, including potential considered a potentially responsible party with respect to the application of federal New Source Performance Standards. We cleanup of certain environmentally contaminated sites owned have responded to the EPA and as of the date of this report the and operated by others. We cannot estimate the cleanup costs EPA has taken no further action. for all of these sites.
In general, such standards can require the installation of However, based on a Record of Decision issued by the EPA additional air pollution control equipment upon the major in 1997, we can estimate that BGE's current 15.47% share of modification of an existing plant. Although there have not been the reasonably possible cleanup costs at one of these sites, Metal any new source review-related suits filed against our facilities, Bank of America, a metal reclaimer in Philadelphia, could be as there can be no assurance that any of them will not be the much as $1.3 million higher than amounts we believe are target of an action in the future. Based on the levels of probable and have recorded as a liability in our Consolidated emissions control that the EPA and states are seeking in these Balance Sheets. There has been no significant activity with new source review enforcement actions, we believe that material respect to this site since the EPA's Record of Decision in 1997.
additional costs and penalties could be incurred, and planned In late December 1996, BGE signed a consent order with capital expenditures could be accelerated, if the EPA was the Maryland Department of the Environment that required it successful in any future actions regarding our facilities. to implement remedial action plans for contamination at and The Clean Air Act requires the EPA to evaluate the public around the Spring Gardens site, located in Baltimore, Maryland.
health impacts of emissions of mercury, a hazardous air The Spring Gardens site was once used to manufacture gas from pollutant, from coal-fired plants. The EPA decided to control coal and oil. BGE submitted the required remedial action plans mercury emissions from coal-fired plants. Compliance could be and they were approved by the Maryland Department of the required by approximately 2007. We believe final regulations Environment. Based on these plans, the costs BGE considers to could be issued in 2004 and would affect all coal-fired boilers. be probable to remedy the contamination are estimated to total The cost of compliance with the final regulations could be $47 million. BGE recorded these costs as a liability on its material. Consolidated Balance Sheets and deferred these costs, net of Future initiatives regarding greenhouse gas emissions and accumulated amortization and amounts it recovered from global warming continue to be the subject of much debate. The insurance companies, as a regulatory asset. Because of the results related Kyoto Protocol was signed by the United States but has of studies at this site, it is reasonably possible that additional since been rejected by the President, who instead has asked for costs could exceed the amount BGE recognized by an 18% decrease in carbon intensity on a voluntary basis. Future approximately $14 million. Through December 31, 2002, BGE initiatives on this issue and the ultimate effects of the Kyoto spent approximately $39 million for remediation at this site.
Protocol and the President's initiatives on us are unknown at the BGE also investigated other small sites where gas was date of this report. As a result of our diverse fuel portfolio, our manufactured in the past. We do not expect the cleanup costs of contribution to greenhouse gases varies by plant type. Fossil the remaining smaller sites to have a material effect on our fuel-fired power plants are significant sources of carbon dioxide financial results.
emissions, a principal greenhouse gas. Our compliance costs with any mandated federal greenhouse gas reductions in the future could be material.
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Litigation Employment Discrimination In the normal course of business, we are involved in various Miller, et. al v. Baltimore Gas and Electric Company et al.-This legal proceedings. We discuss the significant matters below. action was filed on September 20, 2000 in the U.S. District Court for the District of Maryland. Besides BGE, Constellation California Energy Group, Constellation Nuclear, and Calvert Cliffs Nuclear Baldwin Associates, Inc. v. Gray Davis, Governor of Califrnia and Power Plant are also named defendants. The action seeks dass 22 other defendants (including Constellation Power certification for approximately 150 past and present employees Development, Inc., a subsidiary of Constellation Power, Inc.)-This and alleges racial discrimination at Calvert Cliffs Nuclear Power class action lawsuit was filed on October 5, 2001 in the Superior Plant. The amount of damages is unspecified, however the Court, County of San Francisco. The action seeks damages of plaintiffs seek back and front pay, along with compensatory and
$43 billion, recession and reformation of approximately 38 punitive damages. The Court scheduled a briefing process for long-term power purchase contracts, and an injunction against the motion to certify the case as a class action suit. The briefing improper spending by the state of California. process is scheduled to end in July 2003. We do not believe Constellation Power Development, Inc. is named as a class certification is appropriate and we further believe that we defendant but does not have a power purchase agreement with have meritorious defenses to the underlying claims and intend to the State of California. However, our High Desert Power Project defend the action vigorously. However, we cannot predict the does have a power purchase agreement with the California timing, or outcome, of the action or its possible effect on our, Department of Water Resources. In 2002, the court issued an or BGE's, financial results.
order to the plaintiff asking that he show cause why he had not yet served the defendants. In April 2002, a second show cause Asbestos Since 1993, BGE has been involved in several actions order was issued. After several postponements, a hearing is now concerning asbestos. The actions are based upon the theory of scheduled in March 2003 on that order.
"premises liability," alleging that BGE knew of and exposed individuals to an asbestos hazard. The actions relate to two types NewEnergy of daims.
Constellation NewEnery, Inc. v. PowerWeb Technology, Inc.-Prior The first type is direct claims by individuals exposed to to our acquisition, NewEnergy filed a complaint on May 9, asbestos. BGE is involved in these daims with approximately 70 2002 in the U.S. District Court of Eastern Pennsylvania seeking other defendants. Approximately 600 individuals that were never approximately $100,000 in direct damages relating to a contract employees of BGE each claim $6 million in damages ($2 million previously entered into with PowerWeb. PowerWeb Technology compensatory and $4 million punitive). These claims were filed has counter-claimed seeking $100 million in damages against in the Circuit Court for Baltimore City, Maryland in the NewEnergy alleging a breach of a non-disclosure agreement by summer of 1993. BGE does not know the specific facts misappropriation of trade secrets. To date, discovery has just necessary to estimate its potential liability for these claims. The begun. We cannot predict the timing, or outcome, of the action specific facts BGE does not know include:
or its possible effect on our financial results. However, based on
- the identity of BGE's facilities at which the plaintiffs the information available to Constellation Energy at this time, allegedly worked as contractors, we believe NewEnergy has meritorious defenses to the
- the names of the plaintiff's employers, and PowerWeb Technology counterclaim.
- the date on which the exposure allegedly occurred.
To date, 67 of these cases were settled for amounts that Mercury Poisoning were not significant. Approximately 300 cases are scheduled for Beginning in September 2002, BGE, Constellation Energy, and trial in 2003.
several other defendants have been involved in numerous actions The second type is claims by one manufacturer-Pittsburgh alleging mercury poisoning from several sources, including coal Corning Corp. (PCC)-against BGE and approximately eight plants formerly owned by BGE. The plants are now owned by a others, as third-party defendants. On April 17, 2000, PCC subsidiary of Constellation Energy. In addition to BGE and declared bankruptcy.
Constellation Energy, approximately 11 other defendants, These claims relate to approximately 1,500 individual consisting of pharmaceutical companies, manufacturers of plaintiffs and were filed in the Circuit Court for Baltimore City, vaccines and manufacturers of Thimerosal have been sued. Maryland in the fall of 1993. To date, about 375 cases have Approximately 50 cases have been filed to date, with each case been resolved, all without any payment by BGE. BGE does not seeking $90 million in damages from the group of defendants. know the specific facts necessary to estimate its potential liability The claims were filed in the Circuit Court for Baltimore City, for these claims. The specific facts we do not know include:
Maryland beginning in September 2002. The plaintiffs have
- the identity of BGE facilities containing asbestos filed motions to remand the cases back to the Baltimore City manufactured by the manufacturer, Circuit Court. At this time no discovery has occurred. We
- the relationship (if any) of each of the individual believe that we have meritorious defenses and intend to defend plaintiffs to BGE, the action vigorously. However, we cannot predict the timing, or
- the settlement amounts for any individual plaintiffs who outcome, of these cases, or their possible effect on our, or are shown to have had a relationship to BGE, and BGE's, financial results.
- the dates on which/places at which the exposure allegedly occurred.
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Until the relevant facts for both types of claims are If there were an accident or an extended outage at any unit determined, we are unable to estimate what our, or BGE's, of Calvert Cliffs or Nine Mile Point, it could have a substantial liability might be. Although insurance and hold harmless adverse financial effect on us.
agreements from contractors who employed the plaintiffs may cover a portion of any awards in the actions, the potential effect Nuclear Liability Insurance on our, or BGE's, financial results could be material. Pursuant to the Price-Anderson Act, we are required to insure against public liability claims resulting from nuclear incidents to Other the full limit of public liability, approximately $9.6 billion. This McCray t. alv. Baltimore Gas and Electric Company-On limit of liability consists of the maximum available commercial June 10, 2002, a suit was filed in the Circuit Court of insurance of $300 million and the remaining $9.3 billion is Baltimore City, Maryland seeking a total of $585 million in provided through mandatory participation in an industry-wide compensatory and punitive damages from BGE as a result of a retrospective assessment program. Under this retrospective fire in a home that caused five fatalities. Electricity to the home assessment program, we can be assessed up to $352.4 million was shut off. BGE believes it has meritorious defenses and per incident at any commercial reactor in the country, payable at intends to defend the action vigorously. However, we cannot no more than $40 million per incident per year. This assessment predict the timing, or outcome, of the action or its possible also applies in excess of our worker radiation claims insurance effect on our, or BGE's, financial results. and is subject to inflation and state premium taxes. In addition, the U.S. Congress could impose additional revenue-raising Storage of Spent Nuclear Fuel measures to pay claims.
On February 14, 2002, the Secretary of Energy submitted to the The Price-Anderson Act expired in August 2002. However, President a recommendation for approval of the Yucca Mountain the Price-Anderson Act will remain in effect in its current form site for the development of a nuclear waste repository for the for existing reactors until it is renewed. A renewal bill was disposal of spent nuclear fuel and high level nuclear waste from introduced in Congress in January 2003 to extend the Act for the nation's defense activities. In July 2002, the President signed 15 years from August 1, 2002. The bill proposes a change in the a resolution approving the Yucca Mountain site after receiving annual retrospective premium limit from $10 million to the approval of this site from the U.S. Senate and House of $15 million per reactor per incident and a change in the Representatives. This action allows the Department of Energy to maximum potential assessment from $88.1 million to apply to the NRC to license the project. The Department of $98.7 million per reactor per incident. If approved, these Energy expects that this facility will open in 2010. However, the changes would increase the amount we could be assessed to opening of Yucca Mountain could be delayed due to multiple $394.8 million per incident, payable at no more than lawsuits initiated by the State of Nevada and other interested $60 million per incident per year. We do not know what impact parties, the NRC licensing hearings, and other issues related to any other changes to the Act may have on us until a final the site. resolution is reached.
Nuclear Insurance Worker Radiation Claims Insurance We maintain nuclear insurance coverage for Calvert Cliffi and We participate in the American Nuclear Insurers Master Worker Nine Mile Point in four program areas: liability, worker Program that provides coverage for worker tort claims filed for radiation, property, and accidental outage. These policies contain radiation injuries. Effective January 1, 1998, this program was certain industry standard exclusions, including, but not limited modified to provide coverage to all workers whose nuclear-to, ordinary wear and tear, and war. related employment began on or after the commencement date In November 2002, the President signed into law the of reactor operations. Waiving the right to make additional Terrorism Risk Insurance Act ("TRIA") of 2002. Under the claims under the old policy was a condition for coverage under TRIA, property and casualty insurance companies are required to the new policy. We describe the old and new policies below:
offer insurance for losses resulting from Certified acts of
- Nuclear worker claims reported on or after January 1, terrorism. Certified acts of terrorism are determined by the 1998 are covered by a new insurance policy with an Secretary of State and Attorney General and primarily are based annual industry aggregate limit of $200 million for upon the occurrence of significant acts of international terrorism. radiation injury daims against all those insured by this Our nudear property and accidental outage insurance programs, policy.
as discussed later in this section, provide coverage for Certified
- All nuclear worker claims reported prior to January 1, acts of terrorism. 1998 are still covered by the old policy. Insureds under Losses resulting from non-certified acts of terrorism are the old policies, with no current operations, are not covered as a common occurrence, meaning that if non-certified required to purchase the new policy described above, terrorist acts occur against one or more commercial nuclear and may still make claims against the old policies power plants insured by our insurance company within a through 2007. If radiation injury claims under these old 12-month period, they would be treated as one event and the policies exceed the policy reserves, all policyholders owners of the plants would share one full limit of liability could be retroactively assessed, with our share being up (currendy $3.24 billion). to $6.3 million.
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The sellers of Nine Mile Point retain the liabilities for Non-Nuclear Property Insurance existing and potential claims that occurred prior to November 7, Our conventional property insurance provides coverage of 2001. In addition, the Long Island Power Authority, which $1.0 billion per occurrence for Certified acts of terrorism as continues to own 18% of Unit 2 at Nine Mile Point, is defined under the TRIA.
obligated to assume its pro rata share of any liabilities for Losses resulting from non-certified acts of terrorism are retrospective premiums and other premiums assessments. If covered by an industry mutual insurance program. This claims under these policies exceed the coverage limits, the program, which expires May 1, 2003, provides limits of provisions of the Price-Anderson Act would apply. $50 million per occurrence and is subject to a term aggregate limit of $100 million. These limits are shared among all Nuclear Property Insurance companies participating in the program. The mutual insurer may Our policies provide $500 million in primary and an additional renew this program depending upon the availability of
$2.25 billion in excess coverage for property damage, reinsurance at the program's expiration. If terrorist acts at any of decontamination, and premature decommissioning liability for our facilities result in a loss exceeding this coverage, it could Calvert Cliffs or Nine Mile Point. This coverage currently is have a significant adverse impact on our financial results.
purchased through an industry mutual insurance company. If accidents at plants insured by the mutual insurance company California Power Purchase Agreements cause a shortfall of funds, all policyholders could be assessed, Our merchant energy business has $260.6 million invested in with our share being up to $56.2 million. operating power projects of which our ownership percentage represents 137 megawatts of electricity that are sold to Pacific Accidental Nuckar Outage Insurance Gas & Electric (PGE) and to Southern California Edison (SCE)
Our policies provide indemnification on a weekly basis for losses in California under power purchase agreements.
resulting from an accidental outage of a nuclear unit. Coverage As a result of ongoing litigation before the FERC regarding begins after a 12-week deductible period and continues at 100% sales into the spot markets of the California Independent System of the weekly indemnity limit for 52 weeks and then 80% of Operator and Power Exchange, we estimate that we may be the weekly indemnity limit for the next 110 weeks. Our required to pay refunds of between $3 and $4 million for coverage is up to $490.0 million per unit at Calvert Cliffs, transactions that we entered into with these entities for the
$335.4 million for Unit 1 of Nine Mile Point, and period between October 2000 and June 2001. However, our
$412.6 million for Unit 2 of Nine Mile Point. This amount can estimate is based on current information, and because litigation be reduced by up to $98.0 million per unit at Calvert Cliffs and is ongoing, new events could occur that could cause the actual
$82.5 million for Nine Mile Point if an outage of more than amount, if any, to be materially different from our estimate.
one unit is caused by a single insured physical damage loss.
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1 2 Hedging Activities and Fair Value of Financial Instruments SFAS No. 133 Hedging Activities Commodity Prices We are exposed to market risk, including changes in interest Our origination and risk management operation uses a variety of rates and the impact of market fluctuations in the price and derivative and non-derivative instruments to manage the transportation costs of elearicity, natural gas, and other commodity price risk of our competitive supply activities and commodities. our electric generation facilities, including power sales, fuel and energy purchases, emission credits, weather risk, and the market Interest Rates risk of outages. In order to manage these risks, we may enter We use interest rate swaps to manage our interest rate exposures into fixed-price derivative or non-derivative contracts to hedge associated with new debt issuances. These swaps are designated the variability in future cash flows from forecasted sales of as cash-flow hedges under SFAS No. 133 in anticipation of energy and purchases of fuel and energy, including:
planned financing transactions as discussed in Note 1. The
- forward contracts, which commit us to purchase or sell notional amounts of the contracts do not represent amounts that energy commodities in the future; are exchanged by the parties and are not a measure of our
- futures contracts, which are exchange-traded exposure to market or credit risks. The notional amounts are standardized commitments to purchase or sell a used in the determination of the cash setdements under the commodity or financial instrument, or to make a cash contracts. settlement, at a specific price and future date; Prior to the March 2002 issuance of $1.8 billion of debt as
- swap agreements, which require payments to or from discussed in Note 8, we entered into various forward starting counterparties based upon the differential between two interest rate swap contracts to manage our interest rate exposure prices for a predetermined contractual (notional) related to this debt issuance. In 2001, we entered into swaps quantity; and that had notional or contract amounts that totaled $800 million
- option contracts, which convey the right to buy or sell a with an average rate of 4.9%. At December 31, 2001, the fair commodity, financial instrument, or index at a value of these swaps was an unrealized pre-tax gain of predetermined price.
$36.3 million. In the first quarter of 2002, we entered into The objectives for entering into such hedges include:
additional forward starting interest rate swaps with notional
- fixing the price for a portion of anticipated future amounts that totaled $700 million with an average rate of 5.9%. electricity sales at a level that provides an acceptable All of these swap contracts expired at the end of March 2002 return on our electric generation operations, with a gain of $53.7 million.
- fixing the price of a portion of anticipated fuel In addition, we entered into forward starting interest rate purchases for the operation of our power plants, and swap contracts with notional amounts that totaled $400 million
- fixing the price for a portion of anticipated energy with an average rate of 5.1% to manage our interest rate purchases to supply our load-serving customers.
exposure related to the issuance of $500 million of debt in 2002 The portion of forecasted transactions hedged may vary as discussed in Note 8. These swap contracts expired in 2002 based upon management's assessment of market, weather, with a loss of $16.7 million. operational, and other factors.
We will reclassify the $37.0 million net gain from these At December 31, 2002, our merchant energy business had swaps from "Accumulated other comprehensive income" into designated certain fixed-price forward contracts as cash-flow "Interest expense" and include them in earnings during the hedges of forecasted sales of energy and forecasted purchases of periods in which the hedged interest payments occur. We expect fuel and energy for the years 2003 through 2010 under SFAS to reclassify $3.7 million of pre-tax net gains related to our No. 133.
expired swap contracts from "Accumulated other comprehensive At December 31, 2002, our merchant energy business income' into "Interest expense" in 2003. recorded net unrealized pre-tax losses of $45.3 million on these hedges, net of associated deferred income tax effects, in "Accumulated other comprehensive income." We expect to reclassify $24.7 million of net pre-tax gains on cash-flow hedges from "Accumulated other comprehensive income" into earnings during the next twelve months based on the market prices at December 31, 2002. However, the actual amount reclassified into earnings could vary from the amounts recorded at December 31, 2002 due to future changes in market prices. In 2002, we recognized $1.4 million of losses in earnings related to hedge ineffectiveness.
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Fair Value of Financial Instruments We show the carrying amounts and fair values of financial The fair value of a financial instrument represents the amount at instruments induded in our Consolidated Balance Sheets in the which the instrument could be exchanged in a current following table, and we describe some of the items separately transaction between willing parties, other than in a forced sale or later in this Note.
liquidation. Significant differences can occur between the fair value and carrying amount of financial instruments that are At December 31, 2002 2001 recorded at historical amounts. We use the following methods Carying Fair Carrying Fair and assumptions for estimating fair value disclosures for financial Amount Value Amount Value instruments:
(In millions)
- cash and cash equivalents, net accounts receivable, other Investments and other assets current assets, certain current liabilities, short-term for which it is:
borrowings, current portion of long-term debt, and Practicable to estimate fair certain deferred credits and other liabilities: because of value $ 755.1 755.1 $1,183.6 $1,183.6 their short-term nature, the amounts reported in our Not practicable to estimate Consolidated Balance Sheets approximate fair value, fair value 24.2 N/A 25.8 N/A
- investments and other assets where it was practicable to Fixed-rate long-term debt 4,713.9 5,018.8 2,945.3 3,069.6 estimate fair value: the fair value is based on quoted Variable-rate long-term debt 335.9 335.9 1,179.1 1,179.1 market prices where available, and It was not practicable to estimate the fair value of
- for long-term debt: the fair value is based on quoted investments held by our nonregulated businesses in several market prices where available or by discounting financial partnerships that invest in nonpublic debt and equity remaining cash flows at current market rates. securities. This is because the timing and amount of cash flows from these investments are difficult to predict. We report these investments at their original cost in our Consolidated Balance Sheets.
The investments in financial partnerships totaled
$24.2 million at December 31, 2002, representing ownership interests up to 10% and $25.8 million at December 31, 2001, representing ownership interests up to 11%. The total assets of all of these partnerships totaled $5.8 billion at December 31, 2001 (which is the latest information available).
13 Stock-Based Compensation Under our long-term incentive plans, we granted stock options, In February 2002, our Committee on Management of the performance and service-based restricted stock, and equity to Board of Directors granted options, contingent on shareholder officers, key employees, and members of the Board of Directors. approval of our long-term incentive plan, with an exercise price Under the plans, we can grant up to a total of 18,000,000 equal to fair market value of our stock on the date of grant of shares. At December 31, 2002, we had stock options and $27.93. Our shareholders approved the plan at the annual restricted stock grants outstanding as discussed below. meeting in May 2002 when then stock price had increased to
$31.21. The difference between the exercise price and the fair Non-Qualified Stock Options market value in May when the shareholder approval contingency Options are granted at prices not less than the market value of was satisfied was $6.3 million and is being amortized to the common stock at the date of grant, become vested over a compensation expense over a period up to five years. In 2002, period up to five years, and expire ten years from the date of we recorded compensation expense of $3.0 million related to grant. In accordance with APB No. 25, no compensation this grant.
expense is recognized for these stock option awards.
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All other stock options grants have an exercise price equal to or greater than market value on the date of grant and were not subject to any future contingencies, therefore no compensation expense has been recognized. We reverse any expense associated with stock options that are canceled or forfeited prior to the vesting of the grants. Summarized information for our stock option grants is as follows:
2002 2001 2000 Weighted- Weighted- Weighted-Average Average Average Exercise Exercise Exercise Shares Price Shares Price Shares Price (In thousands, except per share amounts)
Outstanding, beginning of year 2,646 $30.73 2,420 $ 34.65 - $ -
Granted with Exercise Prices:
At fair market value 1,708 30.62 1,015 25.08 2,462 34.64 Less than fair market value on the date contingency was satisfied (1) 1,935 27.93 - - - -
Greater than fair market value 103 31.21 - - - -
Total granted 3,746 29.25 1,015 25.08 2,462 34.64 Exercised - - (512) (34.25) - -
Canceled/Expired (311) 34.01 (277) (37.74) (42) (34.25)
Outstanding, end of year 6,081 $29.65 2,646 $ 30.73 2,420 $ 34.65 Exercisable, end of year 1,413 $30.78 235 $ 34.25 - -
Weighted-average fair value per share of options granted 2002 2001 with Exercise Prices: 20 0 2000 At fair market value $ 7.79 $ 9.27 $ 5.60 Less than fair market value on the date contingency was satisfied (1) $ 9.15 -
Greater than fair market value $ 5.89 (1) Shares were granted in February 2002 with an exercise price equal to fair market value of the stock on the grant date, and the grant was subject to shareholder approval of our long-term incentive plan. At the date of shareholder approval, the fair market value of the stock was higher than the grant date fair market value. Therefore, the difference is being amortized to compensation expense.
The following table summarizes information about stock Restricted Stock Awards options outstanding at December 31, 2002 (shares in In addition, we issue common stock based on meeting certain thousands): performance and/or service goals. This stock vests to participants at various times ranging from one to five years if the Weighted- performance and/or service goals are met. In accordance with Average APB No. 25, we recognize compensation expense for our Number Remaining Number performance-based awards using the variable accounting method, Range of Exercise Prices Outstanding Contracrual Life Exercisable whereby we amortize the value of the market price of the
$21.47-34.25 6,081 8.8 years 1,413 underlying stock on the date of grant adjusted for subsequent changes in fair market value through the lapse date to compensation expense over the performance period. We account for our service-based awards using the fixed accounting method, whereby we amortize the value of the market price of the underlying stock on the date of grant to compensation expense over the service period. We reverse any expense associated with restricted stock that is canceled or forfeited during the performance or service period.
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We recorded compensation expense related to our restricted Pro-fonna nfonnation stock awards of $6.6 million in 2002 and $16.3 million in Disclosure of pro-forma information regarding net income and 2000. In 2001, due to non-attainment of performance criteria, earnings per share is required under SFAS No. 123, which uses we recorded a reduction to compensation expense of the fair value method. The fair values of our stock-based awards
$10.1 million. Summarized share information for our restricted were estimated as of the date of grant using the Black-Scholes stock awards is as follows: option pricing model based on the following weighted-average assumptions:
2002 2001 2000 (In thousands, except per 2002 2001 2000 share amounts)
Risk-free interest rate 4.45% 4.79% 6.73%
Outstanding, beginning of year 435 377 323 Expected life (in years) 5.0 5.0 10.0 Granted 344 87 353 Expected market price volatility Released to participants (170) - (277) factors 21.0%
31.9% 41.3%
Canceled (295) (29) (22) Expected dividend yields 3.3% 1.8% 5.7%
Outstanding, end of year 314 435 377 We disclose the pro-forma effect on net income and Weighted-average fair value restricted earnings per share in accordance with SFAS No. 148, Accounting stock granted $27.23 $35.24 $32.89 for Stock-Based Compensation-Transitionand Disclosure, in Note 1.
Equity-Based Grants In 2002, we recorded compensation expense of $0.5 million related to equity-based grants to members of the Board of Directors.
14 Acqulsitions Acquisition of Alliance Our preliminary purchase price allocation for the net assets On December 31, 2002, we purchased Alliance Energy Services, acquired is as follows:
LLC and Fellon-McCord Associates, Inc. (collectively, Alliance) from Allegheny Energy, Inc. These businesses provide gas supply At December 31, 2002 and transportation services and energy consulting services to (In millions) large commercial and industrial customers primarily in the Midwest region, but also in other competitive energy markets Cash $ 4.6 including the Northeast, Mid-Atlantic, Texas and California Other Current Assets 89.1 regions. We acquired 100% ownership of these companies for a Total Current Assets 93.7 note payable of $21.2 million that was settled in cash on Net Property, Plant and Equipment 0.6 January 2, 2003. We acquired cash of $4.6 million as part of the Goodwill 10.0 purchase. We include these companies in our merchant energy Other Assets 3.7 business segment.
Total Assets Acquired 108.0 Current Liabilities 84.5 Deferred Credits and Other Liabilities 2.3 Net Assets Acquired $ 21.2 111
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We recorded the existing contracts at fair value as part of Acquisition of NewEnergy the purchase price allocation. The preliminary net fair value of On September 9, 2002, we purchased AES NewEnergy, Inc.
the contracts was $4.0 million. We recorded the fair value of from AES Corporation. Subsequent to the acquisition, we these contracts as follows: renamed AES NewEnergy, Inc. as Constellation NewEnergy, Inc.
(NewEnergy). NewEnergy is a leading national provider of Net fair value of acquired contracts electriciry, natural gas, and energy services, serving approximately 4,300 megawatts of load associated with large commercial and (In millions) industrial customers in competitive energy markets including the Current Assets $20.8 Northeast, Mid-Atlantic, Midwest, Texas and California. We Noncurrent Assets 3.7 acquired 100% ownership of NewEnergy for cash of Total Assets 24.5 $250.3 million, including $1.4 million of direct costs associated with the acquisition. We acquired cash of $45.5 million as part Current Liabilities 18.2 of the purchase. We include NewEnergy in our merchant energy Noncurrent Liabilities 2.3 business segment.
Total Liabilities 20.5 Our preliminary purchase price allocation for the net assets Net fair value of acquired contracts $ 4.0 acquired is as follows:
We will amortize this value over a period extending through At September 9, 2002 2005. The weighted-average amortization period is approximately one year and represents the expected contract (In millions) duration. Cash $ 45.5 There are further refinements to the preliminary valuation Other Current Assets 376.5 of the existing contracts that have not been finalized that could Total Current Assets 422.0 impact our purchase price allocation. Net Property, Plant and Equipment 7.0 On an unaudited pro-forma basis, had the acquisition of Goodwill 105.0 Alliance occurred on the first day of each of the years presenced Other Assets 46.9 below, our nonregulated revenues and total revenues would have been as follows: Total Assets Acquired 580.9 Current Liabilities 276.3 Year Ended December 31, 2002 2001 2000 Deferred Credits and Other Liabilities 54.3 (In millions) Net Assets Acquired $250.3 Nonregulated revenues We recorded the existing contracts at fair value as part of As reported $2,166.9 $1,164.9 $1,035.9 the purchase price allocation. The preliminary net fair value of Pro-forma 2,706.6 1,659.5 1,381.0 the contracts was $54.8 million. We recorded the fair value of Total revenues these contracts as follows:
As reported $4,703.0 $3,878.8 $3,774.4 Pro-forma 5,242.7 4,373.4 4,119.5 Net fair value of acquired contracts We believe that the pro-forma impact on "Income before (In millions) cumulative effect of change in accounting principle," "Net Current Assets $ 78.6 income," and "Earnings per common share" would not have Noncurrent Assets 45.0 been material had the acquisition of Alliance occurred on the Total Assets 123.6 first day of each of the years presented.
Current Liabilities 46.8 Noncurrent Liabilities 22.0 Total Liabilities 68.8 Net fair value of acquired contracts $ 54.8 We will amortize this value over a period extending through 2007. The weighted-average amortization period is approximately 2 years and represents the expected contract duration.
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Currently, the following items have not been finalized that Niagara Mohawk Power Corporation was the sole owner of could impact our purchase price allocation: Nine Mile Point Unit 1. The co-owners of Unit 2 who sold
- adjustments to the preliminary estimates of severance their interests are: Niagara Mohawk (41 percent), New York costs recorded as current liabilities associated with the State Electric and Gas (18 percent), Rochester Gas & Electric integration of NewEnergy into our operations, and Corporation (14 percent), and Central Hudson Gas & Electric
- outcome of litigation matters. Corporation (9 percent). The Long Island Power Authority will On an unaudited pro-forma basis, had the acquisition of continue to own 18 percent of Unit 2.
NewEnergy occurred on the first day of each of the years We will sell 90 percent of our share of Nine Mile Point's presented below, our nonregulated revenues and total revenues output back to the sellers at an average price of nearly $35 per would have been as follows: megawatt-hour for approximately 10 years under power purchase agreements. The contracts for the output are on a unit Year Ended December 31, 2002 2001 0 contingent basis (if the output is not available because the plant (In millions) is not operating, there is no requirement to provide output from other sources).
Nonregulated revenues As reported $2,166.9 $1,164.9 $1,035. 9 7 Nine Mile Point Net Assets Acquired Pro-forma 3,307.7 1,885.1 1,584.
Total revenues At November 7, 2001 As reported $4,703.0 $3,878.8 $3,774. 4 (In millions)
Pro-forma 5,843.8 4,599.0 4,323. 2 Current Assets $138.4 We believe that the pro-forma impact on "Income before Nuclear Decommissioning Trust Fund 441.7 cumulative effect of change in accounting principle," "Net Net Property, Plant and Equipment 280.3 income," and "Earnings per common share" would not have Intangible Assets (details below) 37.6 been material had the acquisition of NewEnergy occurred on the Total Assets Acquired 898.0 first day of each of the years presented.
Current Liabilities 18.5 Deferred Credits and Other Liabilities 108.7 Acquisition of Nine Mile Point On November 7, 2001, we completed our purchase of Nine Net Assets Acquired 770.8 Mile Point located in Scriba, New York. Nine Mile Point Note to Sellers 388.1 consists of two boiling-water reactors. Unit I is a 609-megawatt Total Cash Paid $382.7 reactor that entered service in 1969. Unit 2 is a 1,148-megawatt reactor that began operation in 1988. The intangible assets acquired consist of the following:
Nine Mile Point Nuclear Station, LLC, a subsidiary of Constellation Nuclear, purchased 100 percent of Nine Mile Weighted-Point Unit I and 82 percent of Unit 2. Approximately one-half Average of the purchase price, or $380 million, in addition to settlement Description Amount Useful Life costs of $2.7 million, was paid at closing. The remainder was financed through the sellers in a note to be repaid over five years (In millions) (In years) with an interest rate of 11.0%. This note was prepaid in Operating procedures and manuals $22.3 10 April 2002. The sellers also transferred to us approximately Permits and licenses 13.0 27
$442 million in decommissioning funds. As a result of this Software 2.3 5 purchase, we own 1,550 megawatts of Nine Mile Point's 1,757 Total intangible assets $37.6 megawatts of total generating capacity.
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- .- ..- lI. -~
I 5 Related Party Transactlons-BGE Income Statement Balance Sheet BGE is providing standard offer service to customers at fixed BGE participates in a cash pool under a Master Demand Note rates over various time periods during the transition period, agreement with Constellation Energy. Under this arrangement, July 1, 2000 to June 30, 2006, for those customers that do not participating subsidiaries may invest in or borrow from the pool choose an alternate supplier. Our origination and risk at market interest rates. Constellation Energy administers the management operation is under contract to provide BGE with pool and invests excess cash in short-term investments or issues the energy and capacity required to meet its standard offer commercial paper to manage consolidated cash requirements.
service obligations for the first three years of the transition Under this arrangement, BGE had invested $338.1 million at period, and 90% of the energy and capacity for the final three December 31, 2002 and $439.1 million at December 31, 2001.
years (July 1, 2003-June 30, 2006) of the transition period. Amounts related to corporate functions performed at the The cost of BGE's purchased energy from nonregulated affiliates Constellation Energy holding company, BGE's purchases to meet of Constellation Energy to meet its standard offer service its standard offer service obligation, and BGE's charges to obligation was $1,080.5 million for the year ended Constellation Energy and its nonregulated affiliates for certain December 31, 2002, $1,150.1 million for the year ended services it provides them result in intercompany balances on December 31, 2001, and $581.0 million for the year ended BGE's Consolidated Balance Sheets.
December 31, 2000. Management believes its allocation methods are reasonable In addition, Constellation Energy charges BGE for the and approximate the costs that would be charged to unaffiliated costs of certain corporate functions. Certain costs are direcdy entities.
assigned to BGE. We allocate other corporate function costs based on a total percentage of expected use by BGE.
Management believes this method of allocation is reasonable and approximates the cost BGE would have incurred as an unaffiliated entity. These costs were $32.2 million for the year ended December 31, 2002, $27.1 million for the year ended December 31, 2001, and $21.6 million for the year ended December 31, 2000.
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16 Quarterly Financial Data (Unaudited)
Our quarterly financial information has not been audited but, in management's opinion, includes all adjustments necessary for a fair presentation. Our utility 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.
2002 Quarterly Data-Constellation Energy 2002 Quarterly Data-BGE Earnings Earnings Earnings Income Applicable Per Share of Income Applicable from to Common Common from to Common Revenues Operations Stock Stock Revenues Operations Stock (In millions, except per-share amounts) (In millions)
Quarter Ended Quarter Ended March 31 $1,040.0 $ 418.6 $228.6 $1.40 March 31 $ 683.7 $113.0 $ 43.9 June 30 1,020.8 184.9 81.3 0.50 June 30 572.9 73.1 20.3 September 30 1,270.3 308.0 150.7 0.92 September 30 668.5 87.3 30.6 December 31 1,371.9 174.7 65.0 0.39 December 31 622.2 92.9 35.1 Year Ended Year Ended December 31 $4,703.0 $1,086.2 $525.6 $3.20 December 31 $2,547.3 $366.3 $129.9 First quarter results indude:
Constellation Energy and BGE
- workforce reduction costs totaling $15.6 million after-tax, of which BGE recorded $12.6 million.
Consteffation Energy
- gain on the sale of investments, including Orion, of $164.2 million after-tax.
Second quarter results include:
Constelation Energy and BGE
- workforce reduction costs totaling $8.0 million after-tax, of which BGE recorded $4.8 million.
ConstellationEnwV
- gain on the sale of investments of $1.9 million after-tax, and
- loss on sale of turbine of $3.9 million after-tax.
Third quarter results include:
Constellation Energy and BGE
- workforce reduction costs totaling $7.5 million after-tax, of which BGE recorded $2.0 million.
ConsteUation Energy
- impairment of investments in qualifying facilities and domestic power projects, costs associated with exit of BGE Home merchandise stores, and impairment of real estate and international investments totaling $17.1 million after-tax.
Fourth quarter results indude:
Constellation Energy and BGE
- workforce reduction costs totaling $6.9 million after-tax, of which BGE recorded $1.9 million.
Constellation Energy
- gains on the sale of investments of $4.5 million after-tax.
We discuss our special items in Note 2.
The sum of the quarterly earningsper share amounts may not equal the totalfor the year due to the effects of rounding and dilution as a result of issuing common shares during the year.
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2001 Quarterly EaaConstella-uon nergy 2001 Quarterly Data-BGE Earnings Earnings Earnings Income Applicable Per Share of Income Applicable from to Common Common from to Common Revenues Operations Stock Stock Revenues Operations Stock (In millions, except per-shareamounts) (In millions)
Quarter Ended Quarter Ended March 31 $1,130.5 $235.0 $111.8 $0.74 March 31 $ 849.9 $141.1 $ 55.1 June 30 826.1 171.0 75.6 0.46 June 30 607.1 74.7 19.9 September 30 1,043.4 317.5 163.6 1.00 September 30 701.4 80.4 23.8 December 31 878.8 (365.7) (260.1) (1.59) December 31 562.3 15.6 (14.7)
Year Ended Year Ended December 31 $3,878.8 $357.8 $ 90.9 $0.57 December 31 $2,720.7 $311.8 $ 84.1 First quarter results indude:
Constellation Energy
- an $8.5 million after-tax gain for the cumulative effect of adopting SFAS No. 133, and
- a gain on sale of investments of $10.0 million after-tax.
Second quarter results indude:
Constelation Enery
- a gain on sale of investments of $10.3 million after-tax.
Third quarter results include:
Constellation Energy
- a gain on sale of investments of $0.5 million after-tax.
Fourth quarter results include:
Constellation Energy and BGE
- workforce reduction costs totaling $64.1 million after-tax, of which BGE recorded $34.4 million after-tax.
Consteflation Energy
- contract termination related costs, and impairment losses and other costs totaling an additional $242.6 million after-tax, and
- a net loss on sale of investments and other assets of $22.7 million after-tax.
We discuss our special items in Note 2.
The sum of the quarterly earnings per share amounts may not equal the totalfor the year due to the effects of rounding and dilution as a result of issuing common shares during the year.
Certainprior-year amounts have been reclassified to conform with the currentyears presentation.
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Item 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure None.
PART III The information required by this item with respect to BGE meets the conditions set forth in General Instruction executive officers of Constellation Energy Group, pursuant to l(l)(a)and (b) of Form 10-K for a reduced disclosure format. instruction 3 of paragraph (b) of Item 401 of Regulation S-K, is Accordingly, all items in this section related to BGE are not set forth in Item 4 of Part I of this Form 10-K under Executive presented. Officers of the Registrant.
Item 10. Directors and Executive Officers of the Item 11. Executive Compensation Registrant The information required by this item is set forth under The information required by this item with respect to directors Directors' Compensation, Compensation Committee Interlocks and is set forth under Election of Constellation Energy Directors in the Insider Participation,Executive Compensation, Common Stock Proxy Statement and is incorporated herein by reference. Performance Graph and Report of Committee on Management on Executive Compensation in the Proxy Statement and is incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters Equlty Compensation Plan Information (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 3,769 $29.60 6,437 Equity compensation plans not approved by security holders 2,312 $29.74 4,320 Total 6,081 $29.65 10,757 The plans that do not require security holder approval are the Constellation Energy Group, Inc. 2002 Senior Management Long-Term Incentive Plan (Designated as Exhibit No. 10(u)) and the Constellation Energy Group, Inc. Management Long-Term Incentive Plan (Designated as Exhibit No. 10(v)). Under these plans, we may grant up to a total of 7,000,000 equity shares. We have granted stock options and performance and service-based restricted stock to officers and key employees.
The additional information required by this item is set forth under Security Ownership in the Proxy Statement and is incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions The additional information required by this item is set forth under Certain Relationships and Transactions in the Proxy Statement and is incorporated herein by reference.
Item 14. Internal Controls and Procedures Within the 90-day period prior to the filing of this report, an evaluation was carried out under the supervision and with the participation of management, including the principal executive officers and principal financial officer of both Constellation Energy and BGE, of the effectiveness of the design and operation of their disclosure controls and procedures (as defined in Rule 13a-14(c) under the Securities Exchange Act of 1934.) Based on that evaluation, such officers have concluded that the design and operation of Constellation Energy's and BGE's disdosure controls and procedures were effective.
No significant changes were made in either Constellation Energy's or BGE's internal controls or in other factors that could significantly affect such controls subsequent to the date of their evaluation.
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I l PART IV Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K (a) The following documents are filed as a part of this Report:
- 1. Financial Statements:
Report of Independent Accountants dated January 29, 2003 of PricewaterhouseCoopers LLP Consolidated Statements of Income-Consellacion Energy Group for three years ended December 31, 2002 Consolidated Balance Sheets-Constellation Energy Group at December 31, 2002 and December 31, 2001 Consolidated Statements of Cash Flows-Constellation Energy Group for three years ended December 31, 2002 Consolidated Statements of Common Shareholders' Equity and Comprehensive Income-Constellation Energy Group for three years ended December 31, 2002 Consolidated Statements of Capitalization-Constellation Energy Group at December 31, 2002 and December 31, 2001 Consolidated Statements of Income-Baltimore Gas and Electric Company for three years ended December 31, 2002 Consolidated Balance Sheets-Baltimore Gas and Electric Company at December 31, 2002 and December 31, 2001 Consolidated Statements of Cash Flows-Baltimore Gas and Electric Company for three years ended December 31, 2002 Notes to Consolidated Financial Statements
- 2. Financial Statement Schedules:
Schedule I-Valuation and Qualifying Accounts Schedules other than Schedule I are omitted as not applicable or not required.
- 3. Exhibits Required by Item 601 of Regulation S-K Exhibit Number
- 2 - Agreement and Plan of Share Exchange between Baltimore Gas and Electric Company and Constellation Energy Group, Inc. dated as of February 19, 1999. (Designated as Exhibit No. 2 in 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) in 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) in Form 8-K vted July 7, 2000, 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 in Form 8-K dated April 30, 1999, File No. 1-1910.)
- 3(b) -Articles Supplementary o the Charter of Constellation Energy Group, Inc., as of July 19, 1999.
(Designated as Exhibit No. 3(a) in Form 0-Q dated August 13, 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 in Form 10-Q dated November 14, 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 January 24, 2003.
- 3(g) - Bylaws of BGE, as amended to October 16, 1998. (Designated as Exhibit No. 3 in Form 10-Q dated November 13, 1998, File No. 1-1910.)
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- 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) in 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) in 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 in Form 10-Q dated August 11, 1995, File No. 1-19 10); and the following Supplemental Indentures between BGE and Bankers Trust Company, Trustee:
Exhibit Dated File No. Designated In Number
- January 15, 1992 33-45259 (Form S-3 Registration) 4(a)(ii) 4
- February 15, 1993 1-1910 (Form 10-K Annual Report for 1992) (a)(i)
- March 1, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(ii)
- March 15, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(iii)
- April 15, 1993 1-1910 (Form 10-Q dated May 13, 1993) 4
- July 1, 1993 1-1910 (Form 10-Q dated August 13, 1993) 4(a)
- October 15, 1993 1-1910 (Form 10-Q dated November 12, 1993) 4
- June 15, 1996 1-1910 (Form I0-Q dated August 13, 1996) 4
- 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 in Registration File No. 2-98443 as Exhibit 4(a)); as supplemented by Supplemental Indentures dated as of October 1, 1987 (Designated in Form 8-K, dated November 13, 1987, File No. 1-1910 as Exhibit 4(a)) and as of January 26, 1993 (Designated in Form 8-K, dated January 29, 1993, File No. 1-1910 as Exhibit 4(b).)
- 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) in Form S-3 dated May 28, 1998, File No. 333-53767.)
- 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) in Form S-3 dated May 28, 1998, File No. 333-53767.)
- 4(g) -Form of Preferred Securities Guarantee (Designated as Exhibit 4(f) in Form S-3 dated May 28, 1998, File No. 333-53767.)
- 4(h) - Form of Junior Subordinated Debenture (Designated as Exhibit 4(h) in Form S-3 dated May 28, 1998, File No. 333-53767.)
- 4(i) - Form of Amended and Restated Declaration of Trust (induding Form of Preferred Security) (Designated as Exhibit 4 (c) in Form S-3 dated May 28, 1998, File No. 333-53767.)
- 10(a) - Executive Annual Incentive Plan of Constellation Energy Group, Inc., as amended and restated.
(Designated as Exhibit No. 10(a) to the Annual Report on Form 10-K for the year ended December 31, 2001, 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 Annual Report on Form 10-K for the year ended December 31, 2000, File Nos. 1-12869 and 1-1910.)
10(c) - Constellation Energy Group, Inc. Nonqualified Deferred Compensation Plan, as amended and restated.
- 10(d) - Constellation Energy Group, Inc. Deferred Compensation Plan for Non-Employee Directors, as amended and rcstated. (Designated as Exhibit No. 10(d) to the Annual Report on Form 10-K for the year ended December 31, 2001, File Nos. 1-12869 and 1-1910.)
- 10(e) - Baltimore Gas and Electric Company Retirement Plan for Non-Employee Directors, as amended and restated. (Designated as Exhibit No. 10(m) in Form 10-Q dated May 14, 1999, File Nos. 1-12869 and 1-1910.)
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I _ ,_ ,
- 10(f) - Summary of severance arrangementfbr Edward A. Crooke. (Designated as Exhibit No. 10(g) to the Annual Report on Form 10-K for the year ended December 31, 1999, File Nos. 1-12869 and 1-1910.)
- 10(g) - Grantor Trust Agreement Dated as of January 1, 2001 between Constellation Energy Group, Inc. and Citibank, NA (Designated as Exhibit No. 10(g) to the Annual Report on Form 10-K for the year ended December 31, 2000, File Nos. 1-12869 and 1-1910.)
10(h) - Form of Severance Agreements between Constellation Energy Group, Inc. and the following named executive officers: Mayo A. Shattuck III, E. Follin Smith, and Frank 0. Heintz.
- 10(i) - Grantor Trust Agreement dated as of April 30, 1999 between Constellation Energy Group, Inc. and T Rowe Price Trust Company. (Designated as Exhibit No. 10(e) in Form 10-Q dated May 14, 1999, File Nos. 1-12869 and 1-1910.)
- 10(j) - Full Requirements Service Agreement between Constellation Power Source, Inc. and Baltimore Gas and Electric Company. (Designated as Exhibit No. 10(a) in Form 10-Q dated August 14, 2000, File Nos. 1-12869 and 1-1910.) (Portions of this exhibit have been omitted pursuant to a request for confidential treatment.)
- 10(k) - Full Requirements Service Agreement between Constellation Power Source, Inc. and Baltimore Gas and Electric Company. (Designated as Exhibit No. 10(a) in Form 0-Q dated September 30, 2001, File Nos. 1-12869 and 1-1910.) (Portions of this exhibit have been omitted pursuant to a request for confidential treatment.)
- 10(1) - Full Requirements Service Agreement between Baltimore Gas and Electric Company and Allegheny Energy Supply Company, L.L.C. (Designated as Exhibit No. 10(b) in Form 10-Q dated September 30, 2001, File Nos. 1-12869 and 1-1910.) (Portions of this exhibit have been omitted pursuant to a request for confidential treatment.)
- 10(m) 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(n) - Constellation Energy Group, Inc. Supplemental Pension Plan, as amended and restated. (Designated as Exhibit No. 10(n) to the Annual Report on Form 10-K for the year ended December 31, 2001, File Nos. 1-12869 and 1-1910.)
- 10(o) - Constellation Energy Group, Inc. Senior Executive Supplemental Plan, as amended and restated.
(Designated as Exhibit No. 10(o) to the Annual Report on Form 10-K for the year ended December 31, 2001, File Nos. 1-12869 and 1-1910.)
- 10(p) - 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(q) - Compensation agreements between Constellation Energy Group, Inc. and Michael . Wallace (Attachment 1-Employment Agreement; Attachment 2-Severance Agreement.)
- 10(r) - Compensation agreements between Constellation Energy Group, Inc. and Thomas V. Brooks (Attachment 1-Offer letter; Attachment 2-Equity letter; Attachment 3-Retention plan summary.) (Designated as Exhibit No. 10(r) to the Annual Report on Form 10-K for the year ended December 31, 2001, File Nos. 1-12869 and 1-1910.)
10(s) - Constellation Energy Group, Inc. Executive Long-Term Incentive Plan.
- 10(t) - Constellation Energy Group, Inc. 2002 Executive Annual Incentive Plan. (Designated as Exhibit No. 11 in the Definitive Proxy Statement on Schedule 14A filed on April 18, 2002.)
10(u) - Constellation Energy Group, Inc. 2002 Senior Management Long-Term Incentive Plan.
10(v) - Constellation Energy Group, Inc. Management Long-Term Incentive Plan.
10(w) - Compensation agreements between Constellation Energy Group, Inc. and E. Follin Smith (Attachment 1.
Offer letter; Attachment 2-Severance agreement.)
12(a) - Constellation Energy Group, Inc. and Subsidiaries Computation of Ratio of Earnings to Fixed Charges.
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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 Accountants.
(b) Reports on Form 8-K:
None.
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I -
CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES AND BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES SCHEDULEIl-VALUATION AND QUALIFYING ACCOUNTS Columin A Column B Column C Column D Column E Additions Balance Charged Charged to at to costs Oter 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 2002 ...................................... $ 22.8 $26.4 $ 12.5 (A) $ (19.8)(B) $ 41.9 2001 ...................................... 21.3 26.5 (25.0)(B) 22.8 2000 ...................................... 34.8 21.1 (34.6)(B) 21.3 Valuation Allowance-Net unrealized (gain) loss on available for sale securities 2002 ...................................... (243.7) - 243.7 (C) 2001 ...................................... (33.7) - (210.0)(C) - (243.7) 2000 ...................................... 0.2 - (33.9)(C) - (33.7)
Net unrealized (gain) loss on nuclear decommissioning trust funds 2002 ...................................... (21.0) - (26.4)(C) - (47.4) 2001 ...................................... (34.7) _ 13.7 (C) - (21.0) 2000 ...................................... (40.5) - 5.8 (C) (34.7)
Mark-to-market energy assets reserves 2002 ...................................... (43.4) - (6.5)(D) _ (49.9) 2001 ...................................... (54.4) _ 11.0 (D) - (43.4) 2000 ...................................... (27.5) - (26.9)(D) - (54.4)
BGE Accumulated Provision for Uncollectibles 2002 ...................................... 13.4 14.5 - (16.4)(B) 11.5 2001 ...................................... 13.4 21.8 - (21.8)(B) 13.4 2000 ...................................... 13.0 16.4 - (16.0)(B) 13.4 Net unrealized (gain) loss on nuclear decommissioning trust fund 2002 ......................................
2001 ......................................
2000 ...................................... (40.5) - (1.8)(E) 42.3 (C)
(A) Represents amounts acquired resulting from our acquisitions of NewEnergy and Alliance.
(B) Represents principally net amounts charged off as uncollectible.
(C) Represents amounts recorded in or reclassified from accumulated other comprehensive income.
(D) Represents reserves from mark-to-market energy assets credited/(charged) to revenues.
(E) Represents net unrealized gains credited to accumulated depreciation.
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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.
(Restrant)
Date: March 7, 2003 By sl MAYO A. SHATUCK III Mayo A. Shattuck III Chairman of the Board Chief Executive Offcer and Prsident 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 litle Date Principal executive officer and director:
By sl M. A. Shattuck III Chairman of the Board, Chief March 7, 2003 M. A. Shattuck III Executive Officer, President and Director Principal financial and accounting officer:
By sl E. E Smith Senior Vice President and March 7, 2003 Chief Financial Officer E. F. Smith Directors:
lsl D. L. Becker Director March 7, 2003 D. L Becker lsl J. T. Brady Director March 7, 2003 J. T. Brady Isl F. P. Bramble, Sr. Director March 7, 2003 F. P. Bramble, Sr.
Is! B. B. Byron Director March 7, 2003 B. B. Byron lsl E. A. Crooke Director March 7, 2003 E. A. Crooke
/s! J. R. Curtiss Director March 7, 2003
- 1. R Curtiss 123
Signature itle Date Is- R W Gale Director March 7, 2003 R. W. Gale is! F. A. Hrabowski, III Director March 7, 2003 F. A. Hrabowski, III is' E. J. Kelly, III Director March 7, 2003 E. J. Kelly, III
/si N. Lampton Director March 7, 2003 N. Lampton Is! R J. Lawless Director March 7, 2003 R. J. Lawless 1sl M. D. Sullivan Director March 7, 2003 M. D. Sullivan 124
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)
Date: March 7, 2003 By sl FRANK 0. HEINTZ Frank 0. Heintz Presidentand Chief xecutive 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 'Ttle Date Principal executive officer and director:
By Isl F. 0. Heintz President, Chief Executive March 7, 2003 F. 0. Heintz Officer, and Director Principal financial and accounting officer and director:
By sf E. E Smith Senior Vice President, Chief March 7, 2003 E. E Srnith Financial Officer, and Director Directors:
/s/ M. A. Shattuck III Director March 7, 2003 M. A. Shattuck III 125
Certification 1, Mayo A. Shattuck III, certify that:
- 1. I have reviewed this annual report on Form 10-K of Constellation Energy Group, Inc.;
- 2. Based on my knowledge, this annual 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 annual report;
- 3. Based on my knowledge, the financial statements, and other financial information included in this annual 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 annual report;
- 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures 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 annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
- 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
- 6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
March 7, 2003
/s/ MAYO A. SHArrUCK III Mayo A. Shattuck III, Chairman of the Board, Chief Executive Officer and President 126
Certification I, E. Follin Smith, certify that:
- 1. I have reviewed this annual report on Form 10-K of Constellation Energy Group, Inc.;
- 2. Based on my knowledge, this annual 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 annual report;
- 3. Based on my knowledge, the financial statements, and other financial information included in this annual 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 annual report;
- 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures 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 annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
- 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
- 6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
March 7, 2003 Isl E. FOLLIN SMITH E. Follin Smith, Senior Vice President and Chief Financial Officer 127
_ _ I -
Certification I, Frank 0. Heintz, certify that:
- 1. I have reviewed this annual report on Form 10-K of Baltimore Gas and Electric Company;
- 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material &ct necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respcct to the period covered by this annual report;
- 3. Based on my knowledge, the financial statements, and other financial information included in this annual 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 annual report;
- 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures 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 annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
- 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
- 6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
March 7, 2003 Is/ FRANK 0. HEINTZ Frank 0. Heintz, President and Chief Executive Officer 128
Certification 1, E. Follin Smith, certify that:
- 1. I have reviewed this annual report on Form 10-K of Baltimore Gas and Electric Company;
- 2. Based on my knowledge, this annual 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 annual report;
- 3. Based on my knowledge, the financial statements, and other financial information included in this annual 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 annual report;
- 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures 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 annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
- 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
- 6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
March 7, 2003 lsl E. FOLLIN SMITH E. Follin Smith, Senior Vice President and Chief Financial Officer 129
Shareholder Information Common Stock Dividends and Price Ranges 2002 2001 Dividend Price* Dividend Price*
Declared High Low Declared High Low First Quarter $0.24 $31.18 $26.16 First Quarter $0.12 $44.65 $34.69 Second Quarter 0.24 32.38 27.65 Second Quarter 0.12 50.14 40.10 Third Quarter 0.24 29.85 21.51 Third Quarter 0.12 43.80 22.85 Fourth Quarter 0.24 29.02 19.30 Fourth Quarter 0.12 28.21 20.90 Total $0.96 Total $0.48
- Based on NYSE composite transactions Dividend Policy Shareholder Investment Plan Constellation Energy pays dividends on its common stock after its Constellation Energy's Shareholder Investment Plan provides common Board of Directors declares them. There are no contractual limitations shareholders an easy and economical way to acquire additional shares on Constellation Energy paying common stock dividends. of common stock. The plan allows shareholders to reinvest all or part of Dividends have been paid continuously on our common stock since their common stock dividends, purchase additional shares of common 1910. Future dividends depend upon future earnings, our financial stock, deposit the common stock they hold into the plan, and request a condition, and other factors. transfer or sale of shares held in their accounts.
Dividend Increase Stock Transfer Agents and Registrars In January 2003, we announced an increase in our quarterly dividend TransferAgent and Registrar:
from 24 cents to 26 cents per share on our common stock payable Constellation Energy Group, Inc.
April 1, 2003, to holders of record on March 10,2003. This is Baltimore, Maryland equivalentto an annual rate of $1.04 per share. Co-Transfer Agent and Registrar:
Common Stock Dividend Dates Continental Stock Transfer and Trust Company Record dates are normally on the 10th of March, June, September, and 8th Floor December. Quarterly dividends are customarily mailed to each share- 17 Battery Place South holder on or about the 1st of April, July, October, and January. New York, NY 10004 Stock Trading Shareholder Assistance and Inquiries Constellation Energy common stock, which is traded under the ticker If you need assistance with lost or stolen stock certificates or dividend symbol CEG, is listed on the New York, Chicago, and Pacific stock checks, name changes, address changes, stock transfers, the exchanges, and has unlisted trading privileges on the Boston, Cincinnati, Shareholder Investment Plan, or other matters, you may visit our and Philadelphia exchanges. Web site at constellation.com or contact our Shareholder Services representatives as follows:
Form 10-K The company has furnished a copy of its Form 10-K as a part of this By telephone (Monday- Friday,8 a.m. - 4:45 p.m. EST):
annual report. In addition, our Form 10-K and other SEC filings can be Baltimore Metropolitan Area 410-783-5920 found on our Web site, constellation.com. Upon written request to our Within Maryland 1-800-492-2861 Shareholder Services group, the company will furnish, without charge, Outside Maryland 1-800-258-0499 additional copies of its Form 10-K.
By U.S. mail:
Auditor Constellation Energy Group, Inc.
PricewaterhouseCoopers LLP Shareholder Services P.O. Box 1642 Forward Looking Disclaimer Baltimore, MD 21203-1642 We make statements inthis Annual Reportthatare considered forward looking within the meaning of the Securities Exchange Act of 1934. In person or by overnight delivery:
These statements are not guarantees of our future results and are Constellation Energy Group, Inc.
subject to risks, uncertainties, and other important factors that could Shareholder Services, Room 800 cause our actual results to differ including those set forth in our Form 39 W.Lexington Street 10-K under the "Forward Looking Statements" section. Baltimore, MD 21201
©Constellation Energy Group 2003
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