ML051170378
| ML051170378 | |
| Person / Time | |
|---|---|
| Site: | Ginna  |
| Issue date: | 04/19/2005 |
| From: | Korsnick M Constellation Energy Group |
| To: | Skay D Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| Download: ML051170378 (172) | |
Text
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Maria Korsnick 1503 Lake Road Vice President Ontario, New York 14519-9364 585.771.3494 585.771.3943 Fax maria.korsnick~constellation.com Constellation Energy I R.E. Ginna Nuclear Power Plant April 19,2005 Ms. Donna M. Skay Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D.C. 20555-0001
Subject:
2004 Annual Financial Report R.E. Ginna Nuclear Power Plant Docket No. 50-244
Dear Ms. Skay:
In accordance with the U.S. Nuclear Regulatory Commission requirements of 10 CFR 50.71 (b) and 10 CFR 140.21(e), enclosed is the Constellation Energy 2004 Annual Report. This report contains the financial data required by both regulations.
Should there be any questions, please contact Thomas L. Harding at (585) 771-3384 for additional information.
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Ms. Donna M. Skay (Mail Stop 0-8-C2)
Project Directorate I Division of Licensing Project Management Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission 11555 Rockville Pike Rockville, MD 20852 Regional Administrator, Region 1 U.S. Nuclear Regulatory Commission 475 Allendale Road King of Prussia, PA 19406 U.S. NRC Ginna Senior Resident Inspector
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IN2005, WE'RE WORKING TO...
Continue creating shareholder value that will produce superior returns.
Continue achieving 10 percent average annual growth in earnings per share.
Further strengthen our balance sheet by using free cash flow to reduce our debt-to- WH WE'RE GROWING total capitalization ratio.
- States and provinces where we seve retai COMMeial and inuta customers.
Drive productivity gains: by loering our cos and increasing output from our generation
- States where we servo retel commercial and fleet-with a target of $180 million in produc- industrial customers and havge r s tivity gains by 2008. Sta whe we hav generating pts.
In additn we serve w a custe throughout the United Sttes and Canada Energy markets throughout I
Achieved a 14 percent market share, making us the No. 1 supplier
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Won a large share of the total electric load awarded by utilities in the North America and commod- of wholesale competitive energy in North America. Northeast and Mid-Atlantic regions.
ity markets across the globe.
Grew peak load served 19 percent to 19,100 megawatts. Built an intemational coal procurement business, sourcing 5.4 million Delivered 80 million megawatt hours of electricity to full requirements tons for international customers. I wholesale customers. I Competitive energy markets Strengthened our No. 1 market position by increasing our share Achieved outstanding customer loyalty and satisfaction-in an independ- II throughout North America. to 21 percent, more than 50 percent larger than our nearest ent survey, 96 percent of our customers said they were happy they market competitor. chose us, 96 percent also said they would choose us again, and Increased peak load served by more than 50 percent, to 94 percent said they would recommend us to others.
12,300 megawatts of electricity. Continued to strengthen our sales force, brand recognition and I product excellence. I Created a special North American sales organization to provide a single point of contact for large customers dealing wilh multi-site energy requirements across multiple markets.
Competitive energy markets II Increased sales volumes by 47 percent, to 279 billion cubic feet of Doubled our market share to 4 percent, ranking us among the top 10 throughout North America. natural gas. competitive gas suppliers.
Competitive whiolsale Generated more than 55 million megawatt hours of electricity from our Completed our acquisition of the Ginna Nuclear Power Ptant ahead of II energy markets across 107 gnerating units, a 7 percet increase over 2003. schedule, adding to our overall earnings.
North America.
Completed the CaOert Clffs outage in 29 days; set an Industry record for Created the option to build a new nuclear plant by submitting an application a low-pressure turbine rotor replant in20 days. to the U.S. Department of Energy for co-funding of activities leading to an eatly site permit for a future plant II I* a D I
I as t Amer as lea gprvder f nrgy E d 12 pe t revenue growhW. II Energy markets across North America.
e heone-yea ranniversry at our N bvl Distict nrgy Achieved eais taets for the fit consecutive yea.
PEant, whicdefveed 100 percent reliability and exceeded all pait-Continued to expand our '8uild-wn-0perat.MaWa pr business.
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I Manylandi Laucth a now advertist and promotional initiatie for the Smart oure wt i ei e ur sales d mornFito n HU Sevie ute Of poduct rslign sale growth Of 66 percent s ale a d e vi e s al noth ar e II Our performance values measure our results: speed, accountability, passion for excellence and creation of value.
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Here's How Were Growing 10 Percent in a 3 Percent Industry.. at Constellation Energy WE'RE... IN 2004, WE...
- A FORTUNE 200 competive energy company headquartered in Baltimore. Provided a 14.8 percent total return to shareholders,
- North America's No. 1 supplier of energy to wholesale and to retail commrcial assuming reinvestment of dividends.
and industrial customers in competitive markets.
- A major generator of electricity with a diversified fleet of power plants located Earned $3.24 per share-excluding spedal items-a 17.4 percent increase over 2003.
strategically throughout the United States.
- A regulated distributor of electricity and natural gas in Central Maryland. Strengthened our balance sheet by reducing our debt-to-total capitalization ratio.
WE GROW ANY ARA06 OF MORE TILW 10 PERCENT ANNUALLY BY...
Built a foundation for ongoing productivity gains
- Increasing our competitivse r t share.
- Taking cost out of our business. by implementing Six Sigma and other programs to
- Investing our cash to achieve superior returns. improve efficiency and output in all our operations.
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Constellation Energy Serving as an intermediary between producers and consumers of electricity, coal Premier wholesale customers who are intensive energy Commodities Group and natural gas-managing the acquisition of fuel for power generators, buying users-includes many of the nation's leading distribution (tomrwy ConstellationPower Source- the power they generate and selling that power to distributors. utilities and cooperatives.
renamedin 2004 to betterreflectour participation in electncity, naturalgas Helping energy producers and customers manage price and supply risk. Energy producers and consumers that require a reliable andhydrocarbons) counterpart to manage their price and supply risk.
Developing our coal and natural gas businesses to meet the underserved and growing needs of energy producers.
Constellation NewEnergy Becoming an extension of our customers energy procurement function-helping More than 10,000 commercial and industrial customers customers effectively manage and control energy costs and usage based on their in all industry segments.
unique business requirements.
Nearly two-thirds of the FORTUNE 100 companies, Delivering superior customer service, offering creative energy products and including Cisco Systems, Ford, General Electric, services and being the only company to provide full coverage of North America's Georgia-Pacific, Kroger, Merck & Co., Inc., Staples competitive energy markets. and others.
Growing our cost more slowly than our gross margin.
Constellation NewEnergy- Providing natural gas supply and transportation-related services and aggressively More than 2,700 large commercial, industrial, municipal Gas Division taking advantage of growth opportunities-targeting sales of more than 450 billion and power generation customers, and some of America's cubic feet over the next five years. largest corporations.
Costellatoin Generation Generating electricity from a strategically located, diversified fleet of plants with Premier wholesale customers who are intensive energy Group capacity totaling more than 12,50O megawatts.. .and driving productivity gains by users-includes many of the nations leading distribution lowering cost and increasing output. utilities, energy companies and cooperatives.
Becoming a recognized wader in energy generation thugh safe, efficient, reliable Constellation Energy Commodities Group sells most of the operations while continuing to grow and integrate new asets into our fleet. power generated by Constellation Generation Group.
F91110#4000oird & Pridinenergycsng and management servie-rs-manging more than Large commercial and industrial customers, including
$2billi natural gasupply and more than $2billion ole y su* y and HanrsonLC, Wabasl aln s and Church & Dwight Co., inc.
Prangporttoiotan t . Xa Constona Energy Proidig custoie otionsxto incease enry ficln~rlaiity and cost Government opert and fai, and lrge Proiects &Services Grow -products inclde tlit inrfrasrcueolurIng, onsieepoer customper including Hein Fied in Pttr a"d OM"Co*10 E _M municipal buildings indont Nann.
SGE HOME Providing ngy ud, products and services that include heati Residential and small commercial customers.
and cooli systiem plumbing and elecalsstems,horne Iovemn ta se11 rv000 ice Our foundational values guide our actions: integrity, teamwork, social and environmental responsibility and customer focus.
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The Way Energy Works-Our success comes from having a strategy for the corn-, , In 2004, total return to shareholders-with dividends' petitive marketplace and the right products and seavces all reinvested- was 14.8 percent. Our stock price appreciated along the value 'chain. Weehave an unmatched conmbinatiorn'- .'.11:6 percent. Our earnings'excluding specia items grew of risk m'a'nagementiexpertise, customer focus and logisti- 17.4 percent to a record $3.24 pe hare-well above our cal capabilities. goal of 10 p aid Swell above the industry average.'
-rcen For us, this is way energy works. We have kept our promises to Wall Street. Fourth We are now the largest provider of power to wholesale quarter 2004 was the 13th conscutive quarter we have and commercial and industrial customers in North America.- met'or exceeded our earnings guidan'ces That's a solid track We are succeeding with our regulated utility Baltimore record of proven performance, and we expect to continue.
Gas and Electric (BGE) swhich ranks among the best'_' thetrend.
.10 percent of comparable companies in operating cost per - We also expect to continue increasing our'dividend custtustomer - in line with our earnings growth In January 2005, we satisfactio raitings from thejJ.D. Power survey. - : "'. announced a 17.5 percent quarterly'dividend increase,
- We' have also demonstrated su'cciess in the integration'h fro m' 28.5 cents per share to 33.5 cents' p'er sheared-of businesses that fit with our strategic model. After equivalent to a new annual rate of $1.34 per share.
adding iecies of acquisitions to complemnent Constellation NewEnergy during 2003, w'e purchased the Ginna Nuclear .- COMPETITIVE MARKETS ARE THE FUTURE:
.Power Plant in 2004 and integrated its 495 megawtts ' Competitive markets are good for 'ustomes, for the econ-and staff f 444 employees into our company quickly omy and for &inPanie thais ieefficiency. Competition and seamlessly. : .' im energy markets has done what itis supposed to do-it :
Throughout our business, we use rigorous method- h.as improved efficiency re no an lowered costs.;
s at ,i~'t' sAS.
Se sre na ta ologies, like Six Sigma, to improve processes and drive' In all, there are now 22 states and three Canadian out inefficiencies. :'. -'-provinces where customers are benefiting from competi- -
By being a low-cost provider, we remain well positioned :tive energy hmarkets.'More customers have more options for the competitive marketplace. Electric power in particular- - in choosin'g their energy supplier, a t~rend we believe is a unique commodity, vital to us and of great economic iwill continue..
importance to many businesses. Our customers rely on'us We are a leading advocate for compeiitivc markets, to help them strategically manage their energy nee dsfor' speaking out on'Capitol Hill and supprting'public policy' their own competitive advantage. ' efforts in states th'at have opened their markets to competi-Others are noticing.- FORTUNE magazine has named tion and in states that art considering further restructuring.,
us America's Most Admired Energyy Company. We were ~ .'>.'.Our earnings growth projections are based oisdthe' also selected as 2004 Energy Company of the'Year at the existing competitive energy market structure. Over time, Platts Global Energy Awards. This type of recognitio5 ' however, we believe customers in other states will demand isgratifying ard rewarding to our employees, customers . : the freedom to choose suppliers p in order to reap the ben-and shareholders. ' efits of competition.: Were well positioned to serve those
'J markets.'
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PRODUCING SUPERIOR RETURNS From November 2001-the start of our competitive strat- WE HAVE WHAT IT TAKES egy-through the end 'of2004,'our stock price appreciated Over the last couple of years, we have seen oil and natural 102 percent. With dividends, that's a'27 percent average gas price volatility and coal prices driven by increased annual return' to shareholders.: - demand from countries like China. -'
2
-1 EARNINGS PER SHARE (excluding special items)
$3.2 4
$2.76_
$2.52 02 03 04 We minimize the effect of price fluctuations by manag- Growing More Than 10 Percent Annually ing toward price neutrality. Because we use a conservative We've been achieving earnings per share growth hedging strategy that balances fuel and power price risk, averaging more than 10 percent annually, and we our earnings growth will be driven by our focus on cus- expect to continue that success.
tomers and operational excellence-rather than commodity Note: See the Financial Highlights table (including price volatility. the GAAP reconciliation) on the inside front cover for Being a competitive entity that operates in an industry more details.
with shifting regulatory rules presents challenges ranging from evolving environmental requirements to more rigorous financial reporting standards mandated by the Sarbanes-Oxley Act. VALUE OF A $100 INVESTMENT We have what it takes to meet these challenges-a great strategy, strong assets and employees who consistently excel $200 at executing our plan. In the end, our shareholders benefit $180.72 from this combination.
WHERE WE'RE HEADED $150 I am proud of what we have accomplished, and I am excited about our future. We are increasing our share in existing electricity markets and expanding our presence in natural gas and coal markets. At the same time, we are $100 $111.12 running our businesses more efficiently, leveraging our scale in competitive energy supply and achieving produc-tivity gains in generation and staff activities. $50 I like where we are headed-continued growth and 12/31/01 12/31/02 12/31/03 12/31/04 ongoing superior returns to shareholders.
We've shown the way energy should work. Our cus-
- Constellation Energy tomers and employees benefit. Our company grows and
- Dow Jones Electric Utility Index
- S&P 500 prospers. And our shareholders are rewarded.
I am glad you are a part of it.
Creating Shareholder Value An investment of $100 in Constellation Energy common stock Regards, on December 31, 2001, was worth-with dividends reinvested-
$180.72 on December 31, 2004. That's significantly better than the Dow Jones Electric Utility Index and the S&P 500.
Mayo A. Shattuck III Chairman, Presidentand CEO March 11, 2005 3
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Old School We're Not We approach energy differently.
INCREASING OUR MARKET SHARE -Upto $150 million of our planned productivity gains We're No. 1 'in competitive energy markets, and we're Will come from our generation fleet, -wherewe're increasing working to increase our market share., the output of our plants, reducing expenses and streamlin--
In wholesale power-where our customers are mosty ing our processes.
distribution utilities-we have a leading 14 percent share in Over the Past year, 'using productivity programs like' competitive markets. In two years, our peak load served- Six Sigma,- we Si Sima we have successfully
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new systems' over 19,000 megawatts-has grown nearly 140 percent. and processes that have boosted efficiency throughout our For retail conmercial and industrial customers, we're company, and we anticipate realizing further benefits from '
the only company hat erves every North American - - these initiatives.
competitive market. Our sales have doubled in the last two years and oui leading 21 Percent marker share is nearly INVESTING TO ACHIEVE SUPERIOR RETURNS three tinies more thin our closest narionil compeit6r.- Our strong cash flow helps us-further streiigthen our For commercial and industrial natural gas customers,' already strong balance sheet-our aim is a 40 percent'debt-our 4 percent'marketshare ranks us among the top 10 pro-" to6-total capitalization ratio by 2006-and will enable 'us' to viders and we're just geting started. invest in opportunities to grow our business.:
tompetitive energy markets wIll continue to grow. Mhe- We're' cautious consumers of capital;continually look-22 states'that have already made the first move continue to ing'at the best way to invest in oour business.
restrucaure their energy markets. As more customers gain ' have a proven track record of successful acquisition n-We the option to choose their energy suppliers, more of them aand integration. The Ginna Nuclear Power Plant and will demand what we offer: reliable, customer-focused' 'NewEnergy-along with the follow-on competitive supply service and risk managetment expertise at fixed prices. -'acquisitions we have made in natural gas ad electricity-'
have produced earnings that are significantly higher than' DRIVING COST OUT OF OUR BUSINESS initial projections.
Better, faster and at a lower cost-our goal isto achieve -We'll continue to look for investments that will build
$180 million in produrctivity gains by 2008. Our objective our competitive energy business and create additional is to lowe&'the per unit cost of what we do. value for our shareholders. - -
PERCEN IN A 3 PERCENT INDU ' ' ' Q WE'VE GROWN IN THREE YEARS.-
Increasing ur'Market Share"2 Grows our ii4s ' 0
- Builds scale that helps bwer our pr Uitcosts [E
- rningsPerShareIudinoscaaters)'S2 41 I $3 24-t 3.24- '
- Creates more opportu stt Of h our business's *p'V.PikLodetitv6Ed~ari 00 110
'~Retail Co'm'ptitive EnergyK Investing in Our Business -"Peik oadS~ve i 0 12,300 21%
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- Earns superior returns. ,c Ia. Market Share go OX-t;-
Creates value for shareholders. Driving Cost OutofOuBusinessr Energy'4 v.TotalCompetitiv-A Enables us to be price competitive
- Improves productivity i ' : Peak Load Served (megawatts) 7 8000 W 340 '
to increase market share.
- Increases output ^
- Produces more cash to invest in [~7 our business.
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GENERATION We generate eli from a strategically located, divi fleet of plants with capacity tota than 12,500 megawatts.', ....S -i'
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z@I mughout North Arm RETAIL ENERGY-As the No. 1 supplier of competitive. retail ,.
energy, we serve 65 of the FORTUNE 100 companies-including Cisco Systems, Ford, Genail Electric, Stapies and others-and 10,000 commercial and industrial customers in 22 states and ,
three Canadian provinces i.,-' '- 5sI '!F+1 d. : .. -S--- x
- .. ' SERVING CUSTOMERS ACROSS THE ENERGY VAL CHAIN Constetation Constellation Ba:timore Ga.
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We Know Energy And our customers benefit.
SERVING CUSTOMERS IN ALL MARKETS We pay particular attention to optimizing the sourc-We serve customers across the energy value chain-from ing and delivery of energy-by generating at low cost and the mouth of the mine or well head where energy has its obtaining it from low-cost producers, delivering it across start... to the homes and businesses where the energy is the best routes and managing it so we have just the right consumed. amount and can deliver it to customers as it's needed.
We know energy and we know it well-providing fuel procurement and logistics services to producers and sup- ADDING VALUE TO OUR CUSTOMERS' BOTTOM LINE pliers ...generating power...supplying wholesale power to Customers choose us because we add value to their bot-distribution utilities and other energy providers in com- tom lines. While energy itself is a commodity, our energy petitive markets...supplying retail energy to commercial products and services are not. We customize our energy and industrial customers in competitive markets...sup- products and services to fit our customers' individual needs plying natural gas to large industrial customers and power or situations.
producers...and delivering natural gas and electricity to Because we provide a superior product at a reasonable residential and business customers. price, an increasing number of customers are choosing us Our world-class energy operation-with our competitive first. They realize that our energy management expertise supply business growth engine-differentiates us from adds value to their bottom line.
traditional regulated utilities. We're the leading company Our participation all along the energy value chain is that serves customers in all North American competitive dynamic, creating new opportunities to add value and energy markets. meet customers' needs. For example, expanding the num-ber ofcoal suppliers to our own generating plants to take FOCUSING ON OPERATIONAL EXCELLENCE advantage of favorable pricing in the world market not We have a shared vision with our customers-to be the only took cost out of our business, it also developed into best at what we do. Our customers operate in competitive an opportunity for us to offer this service to others. We markets, and so do we. We focus on operational excellence now have a growing business that sources 5.4 million tons and crisp execution. of coal for international and U.S. customers.
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- 1. We have thousands 2. We group customer + 3. We take care of the 4. We charge for the 5. Customers benefit fromrn X of customers In corm- needs together and details-making sure energy, earning a our low-cost provider petitive energy mar- procure the energy- our customers get premium for the value position-enabling them kets. We save money either from our own the energy they need we add in managing It to devote more time and for major distribution generating plants or when they need It at a for customers. resources to their own utilities, municipalities from other producers fixed price or within a businesses.
and cooperatives. and sources. set price structure.
Dynamic, Disciplined & Experienced Leveraging our risk management expertise.
GAINING AN ADVANTAGE Our financial strength comes from having a strong In competitive energy markets, winning the business takes cash flow and balance sheet and tremendous liquidity.
competitive price plus customer focus. Being profitable We have a high-performance generation fleet-with a takes risk management expertise and the ability to best concentration of low-cost, baseload plants-that produces aggregate the energy products customers need. electricity using a variety of fuels. Our plants are strategi-In short, being successful takes strong market knowl- cally located in and near competitive markets.
edge and risk management capabilities. Our staff includes Taking advantage of economies of scale, we combine top experts in combining quantitative analytics with de- the power we produce with the electricity that we buy, tailed physical market understanding. We can quantify, creating an optimal source of energy for our customers.
price and reduce variation in expected outcomes with a We operate conservatively. Strong risk management precision that is difficult for competitors to match. controls and metrics provide a powerful tool for safely Our leading risk management platform began with the navigating the energy markets.
first-class experience and technology we gained through our early partnership with Goldman Sachs. Over the last OUR BUSINESS MODEL DELIVERS six years, we've enhanced and optimized it with our own Our strong, disciplined risk management approach energy expertise and investment. has enabled us to develop a proven business model that We've become a great place to work, attracting very delivers results.
talented people and putting together the right mix of Our financial strength, an unwavering commitment entrepreneurialism, intellectual capital, technology and to sound business practices and a dedication to upholding market understanding. the highest ethical standards are hallmarks of the way we It is the combination of those skills-along with the do business.
solid base of core energy expertise that comes from our Our fast-growing competitive energy business and 189 years in the energy business-that gives us an advantage. its backlog of future business-anchored by our regulated utility business-make us a leader in an industry in which SUCCEEDING WITH FINANCIAL STRENGTH customers must procure energy.
We're succeeding because we're a financially strong company That need wornt go away, and we're committed to being that manages risk extremely well. their supplier of choice.
9
On Everybody's Short List We constantly focus on customers.
ENERGY CAN BE A STRATEGIC ASSET and delivery network. It's the nature of the competitive When wholesale and retail customers buy energy wisely,: energy industry.
they gain a competitive advantage.' 'It's easy to do business with us. Dedicated to being the We help customers manage energy as a strategic asset. -best at meeting customers' needs, we're the only supplier As the No. 1 supplier in wholesale and retail markets, we offering coverage in all competitive energy markets.
provide value-added services and products that go beyond Our size and reach enable us to serve large regional the direct supply of energy. We meet the needs of some :wholesale customers, as well as large commercial and Of the biggest distribution utilities in North America, industrial customers, many with multiple sites across as 'well as the needs of more thin 10,000 of the largest several states.
corporations and best-run small b sinesses. Our cusLImers -we've become an extension of our customers' energy include 65 of the FORTUNE 100 companies. ; ; management and procurement function, helping to A group of 78 Texas companies that pooled together op imize their results while meeting their specific needs.
to gain the most competitive rates for electricity chose us because we maximize buying power while also addressing OUR STRATEGY STARTS AND ENDS complex energy requirements. Under the contract-valued WITH OUR CUSTOMERS at more than $100 million-we've become the electricity We provide customers the best value for their energy pro-provider for companies located from Dallas and Fort' .curement. We also advise customers on market conditions,
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Worth to southern Texas. regulatory trends and risk management methods.
Financially prudent customers increasingly look to us.
SIMPLIFYING THE COMPLEX After Ohio finalized regulation for a new 'power structure Simplifying the buying and managing of energy for in 'mid-December, our team worked with 30 customers, our customers requires a thorough understanding of saving them significant expense. It's an example of how we the variability and nuances of the power generation add value to our customers' bottom line.
WE'RE ON EVERYBODY'S SHORT LIST C'USTOMERS INCREASINGLY LOOK To'U We negy aveexensve -~Com petitive Energy Customers: -~
industry knowledge ad nk- " ~ ~ '
.management expertise. ,30 001 U- ,---300custo'mers i 1A0,500 cus-tomers-We tailor energy products and services to meet FRUE10CmaisSre customers' specific needs. Our operational excellence 20 anrwing scale enable us...
to provide low-cost energy, ~ .... o opne produt anvalue-added'~20 services. 2 65 compianiies FiT ' .i.
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WetTell-It Like It Is Answering questions about our business.
Why are we succeeding in competitive energy markets? Even the stronger and more influential traditional We're successful in competitive markets because we use regulated utilities prefer to depend upon what I call the our knowledge of the energy industry and our risk man- false security of slow revenue growth in line with that of agement expertise to constantly focus on meeting our the overall economy and a rate of return determined by customers' needs with superior products and services at their regulators.
a lower cost. In addition, it is not easy to enter competitive energy We're the only company that provides service in all markets. The scale, the assets, the reach and the multi-markets where customers can choose energy suppliers. disciplinary expertise needed to be successful take a lot We're a one-stop energy shop offering electricity and of time, effort and skill to build, develop and implement.
natural gas and related value-added services-acquiring So what we see are niche players. There are financial and supplying the energy and providing energy manage- firms that can trade energy very well but don't have the ment advice and tailored billing. infrastructure that we do to serve customers' diverse We make a complex process simple, enabling our cus- energy needs. There are also small generators and suppliers tomers to spend more time on their specific businesses that do well in small geographic areas but don't have the and less time trying to learn the energy business. national reach and regional expertise that we provide to When we first began developing our strategy a little customers with multiple locations.
more than three years ago, we clearly saw the opportuni-ties and built our company for competitive markets. Now Where is energy restructuring headed?
we're successfully executing the strategy we put in place Competitive markets are the future of the energy industry.
and building on the strength of our business model. I believe very strongly in competition and giving custom-ers choice. It just makes good business sense for customers If our strategy is the right one, why aren't more to be able to choose their energy supplier.
companies entering competitive markets? Competitive energy markets are working, and customers Competitive markets require companies to take charge of are saving money. Markets currently open to competition their own success. Having to compete for customers and are restructuring further, giving more customers more flex-business is a difficult transition for traditional regulated ibility and opportunities to choose their suppliers.
utilities, which are accustomed to having customers and Open electricity markets like those in Nev York, Texas, rates guaranteed to them by regulators. New Jersey, Maryland, the New England states, Illinois, 12
Michigan and the Canadian province of Alberta are solid Do high coal or natural gas prices hurt or help us?
examples of how well-functioning competitive energy Increasing or decreasing prices for coal, natural gas or markets can yield tangible benefits for consumers who other fuels, and the resulting fluctuation in electricity have the option to choose their supplier. prices, have a minimal effect on our earnings. We manage That success is gaining attention. We're dearly seeing toward commodity price neutrality.
more and more regulators become increasingly focused When we make a deal to buy or sell fuel or natural on competitive energy procurement as part of the overall gas or electricity, we hedge to offset risk. That means if energy resource mix. what we've agreed to buy or sell goes up in value, our I believe competitive markets eventually will hedge value goes down. Likewise, if what we've agreed to dominate the energy landscape because it's clear they buy or sell goes down in value, our hedge value goes up.
produce efficiencies, better service and new products As a result, we have protected ourselves from funda-that benefit customers. mental shifts in commodity prices.
What keeps our competitive energy profits from As an investment, how do we differ from a traditional, falling to razor-thin margins? regulated utility?
We do much more than simply provide natural gas I believe that we offer a tremendous value proposition.
and electricity. We optimize the sourcing and delivery We're exceeding our 10 percent average annual earnings of energy-sourcing it from the best providers, delivering growth goal and paying a dividend that we expect to con-it across the best routes and managing it so it can be tinue increasing in line with our earnings growth. At the delivered to customers on an as-needed basis. same time, our stock price has had a price-earnings ratio Because of our size, expertise and market reach, we're significantly below those of what we believe are compa-able to bring together energy from many sources and rable companies and industries.
choose the best delivery options...while also helping our Investing in a traditional, regulated utility generally customers manage their energy use. We have the ability is a standard income proposition. On average, they grow and flexibility to put together the most cost-effective way about 3 percent per year and pay dividends with yields to meet our customers' energy needs. usually in the 5 percent range.
Doing those functions at a low cost per unit or per We see ourselves differently. We see ourselves growing process enables us to earn higher margins. 10 percent in a 3 percent industry.
Board of Directors CORPORATE GOVERNANCE We are an industry leader in corporate governance. We maintain on our website-constellation.com-copies of the charters of each of the committees of the Board of Directors, as well as copies of our Corporate Governance Guidelines, Principles of Business Integrity, Corporate Compliance Program and Insider Trading Policj. In addition, 13 of the 14 members of our Board of Directors are independent. Michael D. Sullivan, one of our independent directors, serves as Lead Director.
INTERESTS ALIGNED WITH SHAREHOLDERS -
In 2004, we adopted share ownership guidelines to further align the interests of our directors with the interests of our shareholders. The new guidelines require directors to acquire and maintain holdings of Constellation Energy stock equal to at least five times the annual cash retainer.
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Mayo A. Shattuck II Yves c. de Balmann I Douglas L Becker James .i Brady Frank P. Bramble, Sr.:- .
Chairman, President and Chief Co-Chairman Chairman and . - ManagingDirector, Mid-Atlantic Consultant '
Executive Officer Bregal Investments Ghief Executive Offtier Ballantrae International, Ud. MBNA Corporation Consteilation Energy Age 58 Laureate Education, Inc. Age 64 Age 56 Age 50 Director since 2003 . Age 39 Director since 1999 Director since 2002 Director since 1999 Director since 1998'
- Formerly a BGE Director, was elected to the Constellation Energy Board of Directors in April 1999 at the formation of the holding company.
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' r Edward A. Crooke James R. Curtiss, Esq. Roger W. Gale Dr. Freeman A. Hrabowskl IlIl Retired Vice Chairman Partner President and President Constellation Energy Winston & Strawn Chief Executive Officer University of Maryland Age 66 Age 51 GF Energy, LLC Baltimore County Director since 1988 - Director since 1994- Age 58 Age 54 Director since 1999 Director since 1994'
*1 Edward J. Kelly Nancy Lampton Robert Lynn M. Martin, -- IMichael D. Sullivan Chairman. Presidentand Chief Chakrnanand CharrnanPresi$entnd, President I Chairman:
Executile Officer ChiefExecutive Officer ChiefExecutive Officer The Martin Hall Group LLC Life Source, Inc.
Mercantile Bankshares Arimerican Life and Accident McCormick a Company Inc. Age 65 Age 65 Corporation Insurance Company of Kentucky Age 58 Director since 2003 Director since 1992-Age 51 Age 62 Director since 2002 Director since 2002 Director since 1994'
.,4' COMMITTEES OF THE BOARD Executive Committee Audit Committee - Compensation Committee Committee on Nuclear Power Nominating and Corporate Mayo ALShattuck IIl,Chairman James T. Brady, Chairman Robert J. Lawless, Chairman James R Curtiss, Chairman Governance Committee Frank P.Bramble, Sr. Yves C. de Balmann Douglas L Becker Edward A. Crooke Michael D.Sullivan, Chairman Edward A.Crooke Dr. Freeman A. Hrabowski IlIl Frank P. Bramble, Sr. Roger W. Gale eind Lead Director Edward J. Kelly IlI Nancy Lampton Edward J. Ketly lit iDouglas L Becker Robert J. Lawless Lynn M. Martin . Frank P.Bramble. Sr.
Michael D.Sullivan Edward J. Kelly IIl Robert J. Lawless Lynn M. Martin 15
Executive Team Our executive team has the right mix of expertise from the energy industry and from competitive busin6sses. Some have a deep knowledge of the energy sector that comes from being -membersof our team and working in the industry before we restructured as a holding company and became Constellation Energy in 1999. Others with competitive business experience joined us after ourstrategic decision in 2001 to build a business that would become the leader in competitive energy markets. That combination results in excellent execution of our strategy. Our success-near-term performance with a long-term.
focus-is'a hallmark of our executive team.
KIT Mayo A. Shattuck III Thomas F. Brady Thomas V. Brooks -
Chairman, President and Chief Executive Vice President, Corporate Executive Vice President Executive Officer Strategy and Retail Competit've Supply President, Constellation Energy Elected Chairman of the Board in July Serves as managing executive for Commodities Group 2002, appointed President and Chef Constelation NewEnergy. BGE HOME Responsible for wholesale energy, Executive Officer in November 2001 i: and Constellation Energy Projects & commodity services and risk management age 50... prior to Constellation Energy, was Services Group... responsible for corporate for electricity, coal, natural gas and related Chairman of the Board at Deutsche Banc strategy. acquisitions and dispositions, commodities ...previously was Vice Alex Brown.., also was Global Head of"- - retail competitive supply, government President, Business Development and Investment Banking and Global Head of.: affairs and corporate branding ...previously Strategy...age 42 .joined Constellation Private Banking at Deutsche Bane AIex. was Chief Accounting Officer at Baltimore Energy in 2001... prior to Constetlation Brown. Vice Chairman at Bankers Tnust Gas and Electric and also served n various Energy worked in the Fixed Income and and President at Alex. Brown and Sons. executive and management positions. Commodities Division at Goldman Sachs.
Induding Vice President of Customer Service and Distnbution...age 55 ...joined Baltimore Gas and Electric in 1969.
16
INTERESTS ALIGNED WITH SHAREHOLDERS In 2004, we adopted share ownership guidelines to further align the interests of our executives with the interests of our shareholders. The new guidelines require our executives to acquire and maintain holdings of Constellation Energy stock ranging from three times base salary for senior vice presidents to seven times base salary for our CEO.
I, .~'i s E. Foilin Smith ' Michael J. Wallace E Paul J. Allen 7 Executive Vce President, ChiefFmiancial Executive Vce President Senior Vce President, Corporate Affairs Officer and ChiefAdministrative Officer President, Constellation Generation Group Responsible for external affairs, Responsible for finance. information Responsible for our power generation government and regulatory relations, technology, human resources, legal, business... age 57 .. joined Constellation environmental policy and corporate audit, risk management and business Energy in 2002... prior to Constellation communications ...age 53...joined process improvement _.age 45 ..joined Energy, was co-founder and Managing Constellation Energy in 2001 priorto Constellation Energy in 2001... prior to Director of Barington Energy Partners, 'Constellation Energy; was Senior Vice Constellation Energy, was Senior Vice LLC2... also was Chief Nuclear Officer and President and Group Head, Ogilvy Public President and Chief Financial Officer served in various executive positions at Relations...also was a senior staff member of Armstrong IHoldings, Inc ....also Unicom/ComEd. at the Natural Resources Defense Council, served in various financial executive and Press Secretary for Senator Christopher management positions at General Motors. Dodd (O-Conn.), and Foreign News Editor and Editor of Morning Edition' at National Public Radio.
John R. Collins Kenneth W. DeFontes, Jr.
lu,"- B, S. Perman.
Beth Marc L Ugolf Senior WcePresident and Senior Vice President . Senior Vice President and Senior Vice President. human Resources Chief Risk Officer President. Baltirrore Gas and ISectric : ChiefInforiation Officer Responsible for organizational Responsible for assessing and managing Responsible for our regulated idistnbution Responsible for information technology effectiveness, staffing, labor relations, risk... previously was Managing Director- utility business ...previously waSVice Initiatives and standardization of systems compensation and benefits...age 46...
Finance and Treasurer of Constellation President, Eectric Transmissio n and and architecture...age 44...Joined joined Constellation Energy in 2002...prior Power Source Holdings and also served Distribution, and also served IrI various . Constellation Energy in2002... prior to to Constellation Energy, was Senior Vice in various leadership positions at executive and management pcoitions ': Consiellation Energy, was Vice President President of Human Resources at Tellabs, Constellation Energy Comrmodities Group ...age 54...Joined Baltimore G.is and of Wholesale Trading Technology and Inc.... also served in human resources and Baltimore Gas and Electric.. age 47... ElectriIn 1972.' -, served in various other technology management positions at Platinum joined Baltimore Gas and Electric in 1988 ,management positions at Enron... Technology, Inc., System Software prior to Baltimore Gas and Electric. served also served in financial and technology Associates, Inc. and Amoco Corporation.
in various financial management positions management positions at Lehman at BetlAt antic Corporation and Perdue Brothers, Kidder, Peabody & Company Farms, Inc. and J.P. Morgan.
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Breaking.Down:Our Form 10-K Our Form 10-K has four parts::
Part I In-depth descriptions of our businesses.
Part I Our financial performance, the information in:which investors are usually mo'st interested.-
Part 1 -Directs readers to our proxy statement for details on 5~x u -e . ic ; th-- '> '-..:...
-;".eir..
our board of directors and executive officers andtheir
'compensation.-':
Part IV A listing of financial statenent schedules and exhibits.
Over the next several pages, we provide descriptions and summaries of some of the 'major topics included'innParts'l and 11.
items in our Form 10-K. Our completelForm 10-Kfollows this, sp~ecial NOTE: This special section is intendled to be aguide. You can find more dletl about all th~ese' section.
19
. Part'll'0dr Businesses .
Part I of our Form 10-K provides details about our businesses:
- Our merchant energy business.
- Our regulated utility-Baltimore Gas and Electric Company.
- Our other nonregulated businesses.,
Also included is information about environmental matters, employees, properties and executive officers.
- BUSINESS PAGES 1-2 OVERVIEW
-Our Company;. i, We have a merchant energy business and a regulated distribution utility.
Operating segments Our reportable operating segments are merchant en-ergy, regulated elecric and regulated gas. We also have certain other nonregulated business activities. Our competition P,- We encounter competition from companies of various PAGES 3-9 sizes-having varying levels of experience and financial MERCHANT ENERGY BUSINESS and human resources-and differing strategies.
Our business Operating statistics for the last five years We provide wholesale electricity and services to distri-Our revenues and megawatt hours generated bution utilities and municipalities... electricity supply- ;
have increased.
and services and natural gas to large commercial and industrial custom'ers ... and we generate electricity.
PAGES 9-13 - -
Fuel source BALTIMORE GAS AND ELECTRIC COMPANY, Our electriciy generated by fil type in' 2004 nudear :Our business
-52 percent, coal-32 percent, natural gas-10 percent,;' 'We're'an electric transmission and distribution utility renewable and alternative-4 percent, and oil and dual -'-ad a natural gas distribution utility with a service;-
oil-natural gas-2 percent. territory that'includes the City of Baltimore'and parts
-of Central Maryland.
Electric and gas operating statistics -
- for the last five years.
--Revenues by type, sales to our customers, and the number of our customers.
NOTE: This special section Is'intended to be a guide. You can find more details about all these Items In our Form 10-K Our complete Form 10-Kfollows this special section.
20
1')atI ur.Businesss(cniued) " "MI PAGE 13 OTHER NONREGULATED BUSINESSES Our businesses Weoffer energy solutions to residential, commercial, industrial andmurniicipal cusoe.
PAGES 13-16 4 ENVIRONMENTAL MATTERS We are subject to regulations concerning air quaiy water quality'and disposal of hazardous stUbstanices~
-over the6 last five years our capital expenditures to .
comply with environmental standards and regulations were $235 million.
PAGES 17-19
":~PROPERTIES PAGE 16 -
EMPLOYEES O offices 'anddurfacilites We ad pprximtey 9570empoyesbur corporate offis are in Baltimore. We have plants 7
at year end 2004. ~rdmreigofcs ogot NzhAerc n walolease space internationally. "
Our generating plants Wbwn-more'than' 12,500'megraw~atts of generating
~capacity diverSified by fueltype 'adlocated sitmtegically thoghout th Uniated States.
- PAGES 1-20
.,EXECUTIVE OFFICERS OF THE REGISTRANT
-,Our executive officers.;%
Our executv oicems have'a diverse' m-,ix" of energ'y; fiania~.d ote priic in competitive and' r:egulatedimarkets.'
NOTE: Thisspecial section isitended to be aguide. You canfind moredetais about allthese items nor Fr -K follows tt~sspecial secton.
-K.Our complete Forml1 21'
a l:.Ou'r Financial Perform'ance ' -~ ,0:
Part 11contains management's discussion and analysis of our results of operations and financial condition. It compares 2004 results to 2003, and 2003 results to 2002.
The sections in Part 1iinclude:
Introductory ltems-the basics.
- Management's Discussion and Analysis-the context.
- Financial Statements-the numbers.
- Notes to the Financial Statements-the details.
- A.Introductory. :ems `.
.The Basics:
Here's information about our common stock, prices and dividends, -
and historical financial data.'
PAGE21 PAGES 22-23 MARKET FOR REGISTRANT'S COMMON EQUITY FINANCIAL DATA AND RELATED SHAREHOLDER MATTERS --.
- - . Summary of urperations and financial Our dividend Information condition and our financial statistics for - -
We declared adividend of51.i4 per share in 2004 aind' . t he last five years increased our .u annual
.n dividend rate rit $1.34 pe
.tO ,.-;.3.: pe-.h
.4 r ini re sare show the success of the
,';- Our'reults h strategy
- - y - .....
January 2005. we've implemenied.
-. Our stock price s b o N York The price fou'rco rnon'stock-basedon Stock ExchangeCompsite Transactions -ranged from-'
$35.89 to $44.90 in 2004.
NOTE: Thsspecial section isIntended tobe aguide.You can fnd more details abouit atthese items in our Forml1 -K. Our complete Form 10 K ollows ~s special section.
22
The 'Context Our. management disc-uss-e-sin detailthe financial resuilts and condition of our company ...and the way We manage our busiess.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
-AND RESULTS OF-OPERATIONS PAGE 24 INTRODUCTION AND OVERVIEW We sumimarize how we have organized our discussion and anilysis.
PAGES 27-30 PAGES 24-25 - CRITICACACCOUNTING POLICIES
' a~ice STATG trt~r~The accounting policies that are moti~~ tato
-Weaire puirsuing a ncstteyodistrib ute energy, the portraypl of ouri fin~cial condition-while also trough our Nort Amrcn~ copt-v splui requiring coemplex j udgi~
eifiulor nesse's'and our regulated Marylahd utility. include reveniue recogniition/mark-toni~rket account-'
in, evaluation of assets for impairment and asset' PAGES 25-27 rtrmnobiaions.
BUSINESS ENVIRONMENT Energy markets conttinuedto'be6 highly volatile in -PAGES 30-31 204with sig~nificant changes in naua ~ Iapower SGIIATEET p~rice:s, and'the Federal Energy Regiiiatory~Comn~insioni Sgificant e-vents tha haeafcted us include a loss has been~reviewing the structure ind variotis aspe~cts of frri'i'otne prtost-rcnt~ f sn the wh~ole~sale, energy market. -thetic fuel tax credits associated with 2003 prdcin, workforce reduction costs, imnpairmxent losses,'selling -
non-core assets, 'our acquisition of the Gifina Nuclear
-Powver Pant and our dividend iricrease.
PAGES 31-47 RESULTS OFOPERATIONS.
~Our overall net income OLur net income for.2Q04 wa $539.7 millioa incre-of $262A. million from 2003-icha'rges in acco..t..g..iAiples rduced ouri'net in'comieby
$198.4 millon ini 2003, wh~ ihV foi u merchan enrybusiness; regulated electric busiries, nuclear assets and certainecniomiic nedges coh'ruted to our 2004 earnings. . -
NOTE: his ipeaseton Isinteddto be aguide. You can lird more details about all theselItems In our Form 10-K. Our complete Form 10-K ollows this special section.
23
Our net income for our merchant energy business Our merchant energy net income was $389.9 million in 2004,;an increase of $275.3 million, from 2003-
-'eflecting our continued 'growth and the effect of changes in accounting prirciples that reduced our merchant energy business net income by $198.4 mil- '
lion in 2003.
Ournet income for our regulated electric
-and gasbusinesses
-Our regulated electric business net income for 2004 -- '
was $131.1 million,'ani increase of $23.6 million from -'
-2003; and our regulated gas business net income for 2004 was $22.2 million, a decrease of $20.8 million from 2003.
PAGES 50-53
,Our net income from our other - CAPITAL RESOURCES nonregulated businesses, Capital requirements We had a net loss of $3.5 miilion from "ourother: Weir eetiating that well need $915 millin in pital.
nonregulited businiesses in 2004, corpared with net: for 2005 and $950 million in 2006 to fund existing income of $12.2 rmillion in 2003-mainly the result of a and anticipated projecs.
$16.4 million net gain on sales of non-core investments and o s in 2003. Funding our capital requirements2003'
-We expect to use internally generated funds 'and other,
'ablesources for theexpansionoour merchant PAGES 48-50aalaeepasooformcat FINANCIAL CONDITION - - energ' btisin d th ds r ruated ndand
'~7businesses otir othe Cash flow eectric and gausinesses er nonreguated p'Cash b o o w $1. billion : businesses. We expect to fund acquisition's with a moix-n :
in 2004. a $29.0 ture of debt and equit, h'an overal goal of main- -
ilinicrase from 2003 -
-aining a strong investment-grade credit profile.
Security ratings
. - - ;. - -- -- : - - :0 -4Cntratuapayment obliga ions :
AlI of our security ratings are solidly investment-grade, C pamn obligations -
al with stable outlooks. :. - Wedetail our contractual payment obligations for
- -,2005'ad beyond.
PAGES 53-58
- MARKET RISK
' e are exposed to energy commodiy price and volatil-
- ity risk, credit risk, intest rate risk, equity pnice risk, foreign exchange risk ard operations risk. Our rsk*
-management program uses an effeaive system ofinter-
'nai contoIs:and is overseen by our Board of Dire tors and the Audit Committee of the' Board.
NOTE: This special section is Intended to be a guide. You can find more details about all these items in our Form 1-K. Our complete Form 10-K follows this special section.
24 - ..
+>.~ Our Sttmet - : -
-The Numbers We provide separate financial statementsfor Constellation Energy and Baltimore Gas and Electric Company. This section also includes our management and auditors reports on our financial information and the effectiveness of our internal controls.
--FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
-PAGE 59 -
-REPORT OF MANAGEMENT Our management accepts responsibility for the informra-tion and representations in our financial statements and concludes that our internal control over financial reporting was effective as of December 31, 2004- -PAGE 65 -.
signed byChairrman ofthe Board, President anid Chief: "' CONSOLIDATED STATEMENTS OF CASH FLOWS E"' cutive'OfficerMa'A. Shattuc IIIandbbyExecu cshp ovidedbyoperrOurtti tingactivities contin- . -
tive Vice President, Chief Financial Ofcer and Chief ued toincree tadily-from $1.01 billion in 2002 to::'
Administrative Officer E. Follin Smith. $1.06 billion in 2003 to $1.09 billion in 2004.'
PAGES 59-61 PAGE 66
- REPORTS OF INDEPENDENT REGISTERED CONSOLIDATED STATEMENTS OF
- sr
- PUBLICACCOUNTINGFIRM - .- _COMMON SHAREHOLDERS'EQUITY - j;,:-
'PricewaterhouseCoopers LP states its opinion'that AND COMPREHENSIVE INCOME
- 'our conisolidated financial statements present fairly, in W-_e declared $196.3 rnillion in dividends during 2004,
-all material respects, the financial condition of our com- " our retained earnings were$2.4 billion at year end.
pany and that we maintained, in all material respects, effective internal control over financial reporting at PAGES 67-68 December 31,2004.' - -CONSOLIDATED STATEMENTS OF CAPITALIZATION.
'PAGE 62 A..December ur total capitalization was
'CONSOLIDATED STATEMENTS OF INCOME :, $9.8 billion-$4.8 billion in iongterm debt, $90.9 il-Our net income for 2004 was $539.7 million in ninoity interests; $190.0 million in prefererce:
-stock, and $4.7 billion in comm'onsnreholders' equity.
'PAGES 63-64 CONSOLIDATED BALANCE SHEETS PAGES 69-72 Our toi O tastsets were $17.3 billion at- BALTIMORE GAS ANDELECTRiC COMPANY Dember31, 2004.-.--:.'-. * -'; .. '-' . FINANCIAL STATEENT We include finandal stateients' for BGE b'ause'it is a.
separate egist rat required t filewith'the' SEC.' '
. .w - ;i a r;, - o NOTE: This special section is hitended to be a guide. You can find more details about all these items in our Form 1O-K Our complete Form 1O-K foflows this special section.
25
TeDe-tails We explain the processes, events, actionsp'ropJects, issues and specifics that produce the amounts reflected in our financial Statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS PAGES 73-84 NOTE 1: SIGNIFICANT ACCOUNTING POLICIES Accontinetodsthat wetuseand how they re~
applied throughout our businesses,4 along with the
-new accountinggstandards issued.
PAGES 84-87
-NOTE 2: WORKFORCE REDUCTION, IMPAIRMENT.
LOSSES AND OTHER EVENTS -PAGE 92 O'urt'otalispecial items in 2004wvere~$_90.2 million pre- NOTE 5: INTAN GIBLE AS-SETS tax, mostly due to a $75.6 nililion loss from dicntiun:- Dcme 1 04,oi arigaon of ued operations-and $21.9 million after-tax, in udin godwl wasI$14. mlin, and "ur'n'et amount
-recognition of $3. milo nsnhtcfuel txcrdt- of intangible assets was $35. million.
relating to2003 production PAGES 93-94 PAGES 88-89 'NOTE 6: REGULATORY ASSETS (NET)
NOTE 3: INFORMATION BY OPERATING SEGMENT, Our reguatory assets, net wr 154mlina
- Our revenues, net inicome ~nd other financial infor- Deee 312004 mation, broken out by-operating segment, shows the-gro wth of our merchant energy business. .- PAGES 94-97
- NOTE 7: PENSION, POSTRETIREMENT, OTHER PAGES 90-91 -POSTEMPLOYMENTAND EMPLOYEET NOTE 4: NVESTMENTS -SAVINGS PLAN BENEFITS
- ur investmnents are mail fi'cilivetets held.I~
7:W 'ori~diisobligations, assets, fuinded status, as asset's for our nuclear decommissionun ftrutfnd,~' assumption details adcom'pany contributions-abou and to secure certain executive benefits. We als 'Ffioremlye eefit plas investments in power plants.
PAGE 9 NOTE 8: CREDIT FACILITIES AND SHORT-TERM BORROWINGS
- -- urshrfrn~ brrvigsdebt that matures within' oneO eafri ih~date it's issued-i miy include bank loans,' commnercial paper and bank lines; of crdit
~NOTE.This special secion isintended to beaguide. Youcan find moredetails ab~outatthese itemsin our Forml10-KCOur complete For 10-K follows thsnspecial sectbon.
26- -
Ntsto Our FnnidStatem'en'tS ~ ~ ~ h~C PAGES98-100 NOTE 9: LONG-TERM DEBT AND PREFERENCE STOCK We provide details about our long-term debt-debt that matures a year or more from the date it's issued-and -
about our preference stock.
PAGES 101-102 NOTE 10: TAXES Our income taxes for 2004 were $172.2 million,'
"-which in'cluided the favorable impact'of $12.2'i million of synthetic fuel tax credits.
-PAGES 110-112 PAGE 103 NOTE 14: STOCK-BASED COMPENSATION NOTE 11: LEASES In 2004, we granted stock options for 1.6 million Our lease expense was $34.1 million in 2004. shares at a weighted-average exercise price of $39.60.
PAGES 103-108 PAGES 112-114 NOTE 12: COMMITMENTS,GUARANTEES NNOTE 15:ACQUISITIONS AND CONTiNGENCIES We completcd ourpurahaseofthe GinnaNuclr '
We provide details about our commitments and Power Plant...and provide details abo ut the transaction, financial guarantees, environmental matters, legal as well as about our other major acquisitions over the proceedinrgs involving us, our nuclear insurance last three years.
coverage and certain issues concerning our California power purchase agreements. - PAGE 115 NOTE 16: RELATED PARTY.TRANSACTIONS-BGE PAGES 10 -110 *Otui rmerchant b sin ssprovides wtha NOTE 13: HEDGING ACTIVITIES AND FAIR VALUE significantportn of t eherg i needs adweprovide
-OF FINANCIAL INSTRUMENTS - - - ' BGE with the services of certain corpo rate fuctions.
We explain how we manage interest rate exposure and commodityprice fluctuations.. ard disclose the' air P',
A 116-117 value of our financial i trumnts NOTE 17: QUARTERLY FINANCIAL DATA, (UNAuDITED) -
Webek out our fna~ilrslsand thdose of BGE-by quarter for the last two years. -
NOTE:Thisspecial sectionis intended to be aguide. You can find more details aboutall these items InourForm 10-K Ourcomplete Form 10-KMollows thisspecial section.
27
.:$>GIossary * 'K aggregator-a company or agent that combines the energy, merchant energy business-our nonrcgulated business, needs of nultipl customers and then buys'or providei the- which combines generation from our power plants and cnergyr encrgy and services needed. we purchase with marketin'gad other services to provide' energy solutions to meetcthe needs of custoinier throughout
-British thermal unit (Btu)-the basic unit used to measure North America.
natural gas the amount of natural gas needed to raise th'e temperature of o'n pound of wat'er by onc degrec Fahrenheit. nonregulated business-the portion of our business that operates in competitive markets.
competitive supply business-our growth engine; the por-tion of our merchant energy business that provides enr'gy and 'nuclear'decommissioning trust fund-a federally mandated valuic-added servicci to wholesale and retail customers located funi set up to ensure that nuclear power plant owners put in competitive markets. aside enough money to payjfor deaning up and dismantling a: -;- -'- -.':--- of natural
-, .- S, -: measurement : .- gas; - ten therms or one. ;-' the plants at the cnd of their useful lives.: -'-
dekatherm-a
-, t l a t en o te u million Btu.:':- - Nuclear Regulatory Comrnmision-the U.S.'agency that deregulation-in-the energy iindustry, si th p b.--ich regulates commercial nuclcar power plants and the civilian use by wyhich . -. 0onudcamatcrials.
-.. deregulation-in --th .Xenergy ..- . .---. i. -th< process-.-. t--- - .- - :: ~ :;-- --
reutatced markets become comptitive markets, giving cus- .aterials.
tomers the opportunity to choosc their supplier origination-the initiation ofwholesale cnergy'purdhases' to h .n ,n ,D; ; - ,- ,-,f in , - , -gy , *l distri.tio- d of er ddistribution thc. delivrryt ocncrgy to locations whr to location.- wand -- :--:s ------ he' sales that may include value-added - serviccs'along with customers use it-incuding homes, businesses, offnce busidings ergy.
and industrial facilities.- regional transmission organization (RTO)-a group of Emerg'n 'ssues s Force (EITF)-a go of 'iancial -' ' '-'-':companies with rcsponsibilityfor thecplanning and use merging Issues Ep.ofes~ionals Task Force (EITF)-a group of finda . -- -,---- -
,tha . h i ,ccounting' .,adrds ,-of power transmission lincs in a geographic region
,prorcssionals tat adv ecstcFnanclal Accountm~g Sadrs'-. -
Board (FASB) ib'out tianaards for reportng new transacions regulated busness- the porton of our busincss whose
'that may be unique nd complex. ' '-.',primary operatoris and prices aic set and coiitrolle by thc edrEneirgy RSegulatory Commission (' '- -. th -- s 'rules and activities offa state utility conmmission.'
Federal Energy Regulatory Commission (EERC)-thc U.S- ,: - , -:, --
agency that regulates interstate energy activities. : retail market-the market in which energy iss'old directly to full requirements service-a product offering that handles, - the customers who use it.
- all oacusmer's nery needs through a combined srvicc dard Offer Service-in Mar'land, the oblitin :
thtfa inc~s~cl c serviceg Stndar ary ogalon hatscand nude generaung or buyig en anaging load .of a utiliy-suh as Baltimore Gas and Elcdric- to suiply mrg
-,ana power purchase agreements, scheduling delivery, manag- - electricity to residenial stomerand as the provider of last
'ing risk,'settiigaccounts and other related services. ,' resort'(POLR) foir th ose customers iwho hae notch'ose 'an generabng apacity-thamount of electricity thatcan, alte,...rnate supp ier..
be produced by a specified gencrating plant or utiiy. - transmission-the sending of clearicity athigh voltage,:
-. ~ on lines running along high'towcrsfromngencrating
- ener-ti-.-r th pr^,-
.generation-the
-h.' -.-
process ss'oftransf ofrtransformmYg other,usually forms forms of + - --
to volt-a lower energy-coal .ata g. -iani o- w ,. r -r . - plants to substations, where it is then reduced energy-coal, 'naturalgauramum, oil, wind, water -or -- ; .-. '- - - ;-
- age that sdelivered to homes, busi es, office buidings and
- s-.- .-
sun-mmnt c ectticiy. -
--.. : - -S -
industrial facilities.
E r nydrocron-fics-c u gg coal!, riatuial gasa . , '--value --- at risk (VaR)-a statistical measure that helps cvaluatc
.-=_',, '" *', ,'-'-1 bo oal, natral ga. and' '
-ou-uscd
,,d.o,
.ndependent
.,-fl-,
to producc encrgy.
' r-gulaied .,-,,: .sk o l ma ',-'- n ri.; by showing how much the value of mark-to-market assets vis circumstances.
independent systern operator-2i'icdcrialliy eguiatcd, ; .- 'or liabLiitis may change un er various circumstances. 0--,
organization that.-manages regional transmission lines to - it w' - ' 'th ui- -t-o measur 1-
- ' - fr e xa mp
-..> , . --. . ,?? - . -. , - -:w'att-thci basic unit uscd tomcsr caitfrxmp, -
deliver electricity a10wt sdccrct-a i00-watt light bulb requires morec lecaiicity and provides load serving-th process of providing wholesalc cust6mers brightcr light than a 60-watt light bulb.
, with thc cncrgy they need- - to servc their r'ctail customers. wholesale market-the market in which chergy is sold in megawatt-one million watts of electricity, enough elearicity , large blocks to other utlities, distribution companies, elearic to light 10,000 i oo vatr light bulbs. ' -' cooperatives,'municipaliticaand powcr marketes who 'then
- , sel or distribute th cenergy to others.'., ;
megawatt hour-one million watts of elecitirity consumed over one hour; cnough electriciry to kcep'i0,000 100-watt light bulbs lit for one hour.
28
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, 2004 Commission IRS Employer file number Exact name of registrant as specified in its charter Identification No.
1-12869 CONSTELLATION ENERGY GROUP, INC.- 52-1964611 1-1910 BALTIMORE GAS AND ELECTRIC COMPANY 52-0280210 MARYLAND (States of incorporation) 750 E. PRATT STREET BALTIMORE, MARYLAND 21202 (Address of principal executive offices) (Zip Code) 410-783-2800 (Registrants' telephone number, including area code)
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
Name of Each Exchange on Title of each dass Which Registcre n
. New York Stock Exchange, Inc.
Constellation Energy Group, Inc. Common Stock-Without Par Value j'- Chicago Stock Exchange, Inc.
J Pacific Exchange, Inc.
6.20% Trust Preferred Securities ($25 liquidation amount per preferred security) issued by BGE Capital Trust II, fully and unconditionally guaranteed, based on several obligations, by New York Stock Exchange, Inc.
Baltimore Gas and Electric Company J SECURITIES REGISTERED PURSUANT TO SECGHON 12(G) OF THE ACT:
Not Applicable Indicateby check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months, and (2) have been subject to such filing requirements for the past 90 days. Yes[>3 No El.
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. E Indicate by check mark whether Constellation Energy Group, Inc. is an accelerated filer [ Yes El No Indicate by check mark whether Baltimore Gas and Elecaric Company is an accelerated filer El Yes [X No Aggregate market value of Constellation Energy Group, Inc. Common Stock, without par value, held by non-affiliates as of June 30, 2004 was approximately $6,391,974,086 based upon New York Stock Exchange composite transaction dosing price.
CONSTELLATION ENERGY GROUP, INC. COMMON STOCK, WITHOUT PAR VALUE 176,847,227 SHARES OUTSTANDING ON FEBRUARY 28, 2005.
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 May 20, 2005.
Baltimore Gas and Electric Company meets the conditions set forth in General Instruction I(l)(a) and (b) of.Form 10-K and is therefore filing this Form in the reduced disclosure format.
TABLE OF CONTENTS Page Forward Looking Statements ............................. .............................
PART I Item 1 - Business ............................................................................ I Overview ........................................................................ I Merchant Energy Business ............. .......................................... 3 Baltimore Gas and Electric Company .............................................. 9 Other Nonregulated Businesses .................... 13 Consolidated Capital Requirements ................. ................................. 13 Environmental Matters .13 Employees .................... 16 Item 2 - Properties .................... . 17 Item 3 - Legal Proceedings .................... 19 Item 4 - Submission of Matters to Vote of Security Holders ................. .. ...................... 19 Executive Officers of the Registrant (Instruction 3 to Item 401(b) of Regulation S-K) ..... .... 19 PART II Item 5 - Market for Registrant's Common Equity and Related Shareholder Matters ........ ........... 21 Item 6 - Selected Financial Data .................................. 22 Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations ...... 24 Item 7A - Quantitative and Qualitative Disdosures About Market Risk .. 58 Item 8 - Financial Statements and Supplementary Data ......... ............ ...................... 59 Item 9 - Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ...... 118 Item 9A - Controls and Procedures ... .......... .
.118 Item 9B - Other Information ........................ ........................................... 118 PART Ill Item 10 - Directors and Executive Officers of the Registrant ......................................... 118 Item II - Executive Compensation .............................. ................................ 118 Item 12 - Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters .......................... 119 Item 13 - Certain Relationships and Related Transactions ................... ....................... 120 Item 14 - Principal Accountant Fees and Services ............................ 120 PART IV Item 15 - Exhibits and Financial Statement Schedules ............................ 121 Signatures ................... 126
Forward Looking Statements
- the effectiveness of Constellation Energy's and We make statements in this report that are considered BGE's risk management policies and procedures forward looking statements within the meaning of the and the ability and willingness of our Securities Exchange Act of 1934. Sometimes these counterparties to satisfy their financial and statements will contain words such as "believes," performance commitments, - {
"anticipates," "expects," "intends," "plans," and other
- operational factors affecting commercial similar words. We also disclose non-historical . operations of our generating facilities (including information that represents management's expectations, nuclear facilities) and BGE's transmission and which are based on numerous assumptions. These distribution facilities, including catastrophic statements and projections are not guarantees of our weather-related damages, unscheduled outages future performance and are subject to risks, or repairs, unanticipated changes in fuel costs uncertainties, and other important factors that could or availability, unavailability of coal or gas cause our actual performance or achievements to be- transportation or electric transmission services, materially different from those we project. These risks, workforce issues, terrorism, liabilities associated uncertainties, and factors include, but are not limited with catastrophic events, and other events to: beyond our control,
- the timing and extent of changes in commodity
- the actual outcome of uncertainties associated prices and volatilities for energy and energy with assumptions and estimates using judgment related products including coal, natural gas, oil, when applying critical accounting policies and electricity, nuclear fuel, and emission preparing financial statements, including factors allowances, that are estimated in determining the fair value
- the liquidity and competitiveness of wholesale of energy contracts, such as the ability to markets for energy commodities, obtain market prices and, in the absence of
- the effect of weather and general economic and verifiable market prices, the appropriateness of business conditions on energy supply, demand, models and model inputs (including, but not and prices, limited to, estimated contractual load
- the ability co attract and retain customers in obligations, unit availability, forward our competitive supply activities and to commodity prices, interest rates, correlation and adequately forecast their energy usage,
- the timing and extent of deregulation of, and volatility factors),
competition in, the energy markets, and the
- changes in accounting principles or practices, rules and regulations adopted on a transitional
- losses on the sale or write down of assets due basis in those markets, to impairment events or changes in
- regulatory or legislative developments that affect management intent with regard to either deregulation, transmission or distribution rates holding or selling certain assets, and and revenues, demand for energy, or increases
- cost and other effects of legal and in costs, including costs related to nuclear - administrative proceedings that may not be power plants, safety, or environmental covered by insurance, including environmental compliance, liabilities.
- the inability of Baltimore Gas and Electric Given these uncertainties, you should not place Company (BGE) to recover all its costs undue reliance on these forward looking statements.
associated with providing electric residential Please see the other sections of this report and our customers service during the electric rate freeze other periodic reports filed with the Securities and period, Exchange Commission (SEC) for more information on
- the conditions of the capital markets, interest these factors. These forward looking statements rates, availability of credit, liquidity, and general represent our estimates and assumptions only as of the economic conditions, as well as Constellation- date of this report.
Energy Group's (Constellation Energy) and Changes may occur after that date, and neither BGE's ability to maintain their current credit Constellation Energy nor BGE assume responsibility to ratings, update these forward looking statements.
PART I Constellation Energy was incorporated in' Item 1. Business Maryland on September 25, 1995. On April 30, 1999, Constellation Energy became the holding company for Overview BGE and its subsidiaries. References in this report to Constellation Energy is a North American energy company which includes a merchant energy business 'we and "our" are to Constelation Energy and its and BGE, a regulated electric and gas public utility in subsidiaries, collectively. References in this report to the "regulated business(es)" are to BGE.
central Maryland.
1
Our merchant energy business is a competitive Constellation Energy maintains a website at provider of energy solutions for a variety of customers. constellation.com where copies of our annual reports on It has electric generation assets located in various Form 10-K, quarterly reports on Form 10-Q, current regions of the United States and provides energy reports on Form 8-K, and any amendments may be solutions to meet customers' needs. Our merchant obtained free of charge. These reports are posted on our energy business focuses on serving the full energy and website the same day they are filed with the SEC. The capacity requirements (load-serving) of, and providing SEC maintains a website (sec gov), where copies of our other energy products and risk management services for filings may be obtained free of charge. The website various customers, such as utilities, municipalities, address for BGE is bge.com. These website addresses are cooperatives, retail aggregators, and commercial and inactive textual references and the contents of these websites are nor part of this Form 10-K.
industrial customers.
In addition, the website for Constellation Energy Our merchant energy business includes:
includes copies of our Corporate Governance
- a generation operation that owns, operates, and Guidelines, Principles of Business Integrity, Corporate maintains fossil, nuclear, and hydroelectric Compliance Program and Insider Trading Policy, and generating facilities and interests in qualifying the charters for the Audit, Compensation and facilities, fuel processing facilities and power Nominating, and Corporate Governance Committees of projects in the United States, the Board of Directors. Copies of each of these
- a marketing and risk management operation documents may be printed from the website or may be that provides energy products and services obtained from Constellation Energy upon written primarily to distribution utilities, power request to the Corporate Secretary.
generators, and other wholesale customers, The Principles of Business Integrity is a code of
- an electric and gas retail operation that provides ethics which applies to all of our directors, officers, and energy services to commercial and industrial employees, including the chief executive officer, chief customers, and financial officer, and chief accounting officer. We will
- an operations and maintenance consulting post any amendments to, or waivers from, the services operation. Principles of Business Integrity applicable to our chief BGE is a regulated electric transmission and executive officer, chief financial officer, or chief distribution utility company and a regulated gas accounting officer on our website.
distribution utility company with a service territory that Operating Segments covers the City of Baltimore and all or part of ten The percentages of revenues, net income, and assets counties in central Maryland. BGE was incorporated in attributable to our operating segments are shown in the Maryland in 1906. tables below. We present information about our Our other nonregulated businesses:
operating segments, including certain special items, in
- design, construct, and operate heating, cooling, Note 3 to Consolidated FinancialStatements.
and cogeneration facilities for commercial, Unaffiliated Revenues industrial, and governmental customers Merchant Regulated Regulated Other throughout North America, and Energy Electric Gas . Nonregulated
- provide home improvements, service heating, air conditioning, plumbing, electrical, and 2004 75% 16% 6% 3%
indoor air quality systems, and provide natural 2003 67 20 7 6 gas to residential customers in central 2002 35 42 12 11 Net Income (1)
In addition, we own several investments that we Merchant Regulated Regulated Other Energy Electric Gas Nonregulated do not consider to be core operations. These include financial investments, real estate projects, and interests 2004 75% 22% 4% (1)%
in a Panamanian distribution facility and in a fund that 2003 66 23 9 2 holds interests in two South American energy projects. 2002 .47 19 6 28 We discuss these non-core assets in more detail in -Total Assets Item 7. Management! Discussion andAnalysis-Results of Merchant Rezated Regulated Other Energy Electric Gas . Nonregulated Operations section.
For a discussion of recent events that have 2004 71% 20% 7% 2%
impacted us, please refer to Item 7. Management's 2003 67. 23 7 3 Discussion and Analysis-Significant Events section. For a 2002 65 24 7 4
'discussion of our strategy, please refer to Item 7. (I) Excludes loss on' discontinued operations in 2004 Managements Discussion andAnalysis-:Strategy section. and cumulative effects of changes in accounting For a discussion of the seasonality of our business, principles in 2003 as discussed in more detail in please refer to Item 7. Managements Discussion and Item 8. FinancialStatements and Sutpplementary Analysis-Business Environment section. Data.
2
Merchant Energy Business
- Retail Competitive Supply-our operation that introduction provides electric and gas energy products and Our merchant energy business integrates electric services to commercial and industrial customers.
generation assets with the marketing and risk
- Other-our investments in qualifying facilities management of energy and energy-related commodities, and domestic power projects and our operations allowing us to manage energy price risk over geographic and maintenance consulting services.
regions and time. We present details about our generating properties Constellation Energy Commodities Group in Item 2. Properties.
(formerly known as Constellation Power Source), our wholesale marketing and risk management operation, Mid-Atlantic Region dispatches the energy from our generating facilities and We own 6,418 MW of fossil, nuclear and hydroelectric facilities with which we have power purchase generation capacity in the Mid-Atlantic Region. The agreements, manages the risks associated with selling the output and obtaining non-nuclear fuels, and enters into output of these plants is managed by our wholesale transactions to meet customers' energy and risk marketing and risk management operation and is management requirements. Constellation NewEnergy, hedged through a combination of power sales to our electric and gas retail operation, provides elearicity, wholesale and retail market participants.
natural gas, transportation, and other energy services to BGE transferred all of these facilities to our commercial and industrial customers. merchant energy generation subsidiaries on July 1, 2000 Constellation Generation Group, our merchant as a result of the implementation of electric customer generation operation, oversees the ownership, choice and competition among suppliers in Maryland, operations, maintenance, and performance of our fossil except for the Handsome Lake project that commenced and nuclear generation and fuel processing facilities. operations in mid-2001. The assets transferred from Our generation capacity supports our wholesale and BGE are subject to the lien of BGE's mortgage.
retail operations by providing a source of reliable power Our merchant energy business provides standard supply that provides a physical hedge for some of our offer service to BGE as discussed in the Baltimore Gas load-serving activities. and Electric Company-StandardOffer Service section.
Our merchant energy business: Our merchant energy business meets the load-serving
- provided service to distribution utilities, requirements of various contracts using the output from municipalities, and commercial and industrial the Mid-Atlantic Region and from purchases in the customers with approximately 31,000 wholesale market. For 2004, the peak load supplied to megawatts (MW) of peak load in the aggregate during 2004, BGE was approximately 4,100 MW.
- provided approximately 279,000 million British Plants with Power Purchase Agreements Thermal Units (mmBTUs) of natural gas to commercial and industrial customers during We own 3,855 MW of nuclear and natural'gas/oil generation capacity with power purchase agreements for 2004, and
- managed approximately 12,530 MW of their output. Our facilities with power purchase generation capacity. agreements consist of:
We analyze the results of our merchant energy
- the Nine Mile Point facility, business as follows:
- the Ginna facility, which was acquired in
- Mid-Atlantic Region-our fossil, nuclear, and June 2004, hydroelectric generating facilities and
- the High' Descrt facility, load-serving activities in the PJM
- the Oleander facility, and Interconnection (PJM) region for which the
- the University Park facility.
output is primarily used to serve BGE. This We own 100% of Nine Mile Point Unit 1 also includes active portfolio management of (609 MW) and 82% of Unit 2 (941 MW). The the generating assets and other physical and remaining interest in Nine Mile Point Unit 2 is owned financial contractual arrangements, as well as by the Long Island Power Authority. Unit I entered other PJM competitive supply activitses.. service in 1969 and Unit 2 in 1988. Nine Mile Point is
- Plants with Power Purchase Agreements-our' located within the New York Independent System generating facilities outside the Mid-Atlantic Operator (NYISO) region.
Region with long-term power purchase We sell 90% of our share of Nine Mile Point's agreements, including our Nine Mile Point output to the former owners of the plant at an average Nuclear Station (Nine Mile Point), RE. Ginna Nuclear Plant (Ginna), Oleander, University price of nearly $35 per megawatt-hour (MWH) under Park, and High Desert'generating facilities. agreements that terminate between 2009 and 2011. The
- Wholesale Competitive Supply-our marketing agreements are unit contingent (if the output is not and risk management operation that provides available because the plant is not operating, there is no energy products and services outside the requirement to provide output from other sources). The Mid-Atlantic Region primarily to distribution remaining 10% of Nine Mile Point's output is managed utilities, power generators, and other wholesale by our wholesale marketing and risk management customers. operation and sold into the wholesale market.
3
After termination of the power purchase runs until December 2010, the project will provide agreements, a revenue sharing agreement with the energy exclusively to the CDWR.
former owners of the plant will begin and continue We have sold portions of the output of the through 2021. Under this agreement, which applies Oleander and University Park facilities ranging from only to Unit 2, a predetermined price is compared to 50% to 100% under tolling contractsfor terms ending the market price for electricity. If the market price in 2005 through 2009. Under these tolling contracts, exceeds the strike price, then 80% of this excess amount our respective counterparties will pay a fixed amount is shared with the former owners of the plant. The per month and have the right, but not the obligation, revenue sharing agreement is unit contingent and is to purchase power from us at prices linked to the based on the operation of the unit. variable fuel and other costs of production.
We exclusively operate Unit 2 under an operating agreement with the Long Island Power Authority. The Competitive Supply Long Island Power Authority is responsible for 18% of We are a leading supplier of energy products and the operating costs (and decommissioning costs) of services in North America to wholesale customers and Unit 2 and has representation on the Nine Mile Point retail commercial and industrial customers. We discuss Unit 2 management committee which provides certain our acquisitions of retail commercial and industrial oversight and review functions. operations in Note 15 to the ConsolidatedFinancial In May 2004, we filed an application with the Statements. During 2004, our competitive supply Nuclear Regulatory Commission (NRC) for a 20-year activities served approximately 22,400 MW of peak license extension for both units at Nine Mile Point. load and approximately 279,000 mmBTUs of natural The license on Nine Mile Point's Unit I expires in gas. Our competitive supply activities also include 2,015 2009 and in 2026 on Unit 2. We must demonstrate MW from our Rio Nogales, Holland Energy, Big Sandy, that we can ensure that the units will continue to and Wolf Hills natural gas-fired generating facilities.
perform their intended functions through the renewal These four facilities are not sold forward under period. The NRC will also consider the impact of the long-term agreements, and their output is used to serve 20-year license extension on the environment. We customer requirements.
expect approval of our application by early 2007 and Wholesale and Retail Load-ServingActivities have assumed license extension for purposes of We structure transactions that serve the full energy and recording depreciation expense and asset retirement capacity requirements of various customers outside the obligations. However, we cannot predict the actual PJM region such as distribution utilities, municipalities, timing of the NRC's decision, or the impact of the cooperatives, and retail aggregators that do not own decision, if any, on our financial results. If we do not sufficient generating capacity or in-house supply receive the license extension, we will not be able to functions to meet their own load requirements. We also operate the Nine Mile Point units beyond 2009 and structure transactions to supply full energy and capacity 2026.
requirements and provide natural gas, transportation, In June 2004, we completed our purchase of the and other energy products and services to retail Ginna nuclear facility which is located in Ontario, New commercial and industrial customers.
York from Rochester Gas & Electric Corporation These activities typically occur in regional markets (RG&E). Ginna consists of a 495 megawatt reactor that in which end user customers' electricity rates have been entered service in 1970 and is licensed to operate until deregulated and thereby separated from the cost of 2029. The acquisition includes a long-term unit generation supply. These markets include:
contingent power purchase agreement under which we
- the Northeast (New England and New York),
sell 90% of the plant's output and capacity to RG&E
-
- the Midwest region, for 10 years at an average price of $44.00 per MWH.
'
- the West region (Texas and California), and The remaining 10% of the plant's output is managed
- certain areas of Canada.
by our wholesale marketing and risk management Contracts with these customers generally extend operation and sold into the wholesale market..
from one to ten years, but some can be longer. To meet The High Desert facility has a long-term power our customers' load-serving requirements, our merchant sales agreement with the California Department of energy business obtains energy from various sources, Water Resources (CDWR). The contract is a "tolling" including:
structure, under which the CDWR pays a fixed amount
- bilateral power purchase agreements with third of $12.1 'million per month which provides CDWR the parties, right, but not the obligation, to purchase power from
- our generation assets, the project at a price linked to the variable cost of'
- regional power pools, and production. During the term of the contract, which 4
- tolling contracts with generation companies, management operation provides products and services to which provide us the right, but not the upstream (exploration and production) and downstream obligation, to purchase power at a price linked (transportation and storage) natural gas customers. We to the variable cost of production, including also include in our other competitive supply activities fuel, with terms that generally extend from the results from our synthetic fuel processing facility in several months to several years but can be South Carolina.
longer.
Other Porfolio Management We hold up to a 50% voting interest in 24 operating Our wholesale marketing and risk management energy projects that consist of electric generation operation actively uses energy and energy-related (primarily relying on alternative fuel sources), fuel commodities in order to manage our portfolio of energy processing, or fuel handling facilities and are either purchases and sales to customers through structured qualifying facilities under the Public Utility Regulatory transactions. As part of our risk management activities Policies Act of 1978 or otherwise exempt from, or not we trade energy and energy-related commodities to subject to, the Public Utility Holding Company Act of enable price discovery and facilitate the hedging of our 1935. Each electric generating plant sells its output to a load-serving and other risk management products and local utility under long-term contracts.
services. Within our trading function we allow limited We also provide operation and maintenance risk-taking activities for profit. These activities are services, including testing and start-up to owners of actively managed through daily value at risk and electric generating facilities.
liquidity position limits. We discuss value at risk in more detail in Item 7. Managements Discussion and Fuel Sources Analysis-Market Risk. Our power plants use diverse fuel sources. Our fuel mix These activities involve the use of a variety of based on capacity owned at December 31, 2004 and instruments, including: our generation based on actual output by fuel type in
- forvard contracts (which commit us to 2004 were as follows:
purchase or sell energy commodities in the future), Fuel Capacity Owned Generartion
- swap agreements (which require payments to or Nuclear .............. 30% 52%
from counterparties based upon the difference Coal ............... 22 32 between two prices for a predetermined Natural Gas ........... 30 10 contractual (notional) quantity), Oil ............... 6 1
- option contracts (which convey the right to buy Renewable and or sell a commodity, financial instrument, or Alternative (1) ...... 3 4 index at a predetermined price), and Dual (2) ....- 9 1
- futures contracts (which are exchange traded (1) Includes solar, geothermal, hydro, and biomass.
standardized commitments to purchase or sell a (2) Switches between natural gas and oil.
commodity or financial instrument, or make a cash settlement, at a specified price and future We discuss our risks associated with fuel in more date). detail in Item 7. Managtmentl Discussion andAnalysis-Active portfolio management allows our wholesale Market Risk.
marketing and risk management operation the ability to: Nuclear
-
- manage and hedge its fixed-price purchase and The output at our nuclear facilities over the past five sale commitments, years (including periods prior to our acquisition of Nine
- provide fixed-price commitments to customers Mile Point and Ginna) is presented in the following and suppliers, table:
- reduce exposure to the volatility of cash market Calvert aiffs Nine Mile Point Ginna prices, and Capacity Capacity Capacity
. hedge fuel requirements at our non-nuclear MWH Factor MVH 5
Factor MWH Factor generation facilities.
(AIWW in millions)
Other Competitive Supply Activities 2004 .. 14.5 96% 12.1 89% 4.3 100%
Our wholesale marketing and risk management - 2003 .. 13.7 93 12.2 90 3.9. 90 operation participates in global coal sourcing activities 2002 .. 12.1 82 11.7 87 3.8 89 by providing coal for the variable or fixed supply needs 2001.. 13.6 92 11.6 86 4.3 100 of North American and international power generators. 2000 .. 13.8 83 11.2 83 3.8 88 In addition, our wholesale marketing and risk *represents our proportionate ownership interest 5
The supply of fuel for nuclear generating stations and sold to pay for the cost of long-term nuclear fuel includes the: storage and disposal. We continue to pay those fees into
- purchase of uranium (concentrates and uranium the DOE's Nuclear Waste Fund for Calvert Cliffs, hexafluoride), Ginna, and Nine Mile Point. The NWPA and our
- conversion of uranium concentrates to uranium contracts with the DOE required the DOE to begin hexafluoride, taking possession of spent nuclear fuel generated by
- enrichment of uranium hexafluoride, and nuclear generating units no later than January 31, 1998.
- fabrication of nuclear fuel assemblies. The DOE has stated that it will not meet that obligation until 2010 at the earliest. This delay has Uranium: We have commitments for sufficient required that we undertake additional actions to provide quantities of uranium (concentrates and on-site fuel storage at Calvert Cliffs, Ginna, and Nine uranium hexafluoride) to meet 100% of Mile Point, including the installation of on-site dry fuel our total requirements through 2006, storage capacity at Calvert Cliffs, as described in more 63% in 2007, and 35% in 2008. We experienced price increases in 2004 due detail below. In 2004, complaints were filed against the federal government in the United Stares Court of to the federally designated Russian export agent terminating its contract with one of Federal Claims seeking to recover damages caused by our key uranium suppliers. These the DOE's failure to meet its contractual obligation to increases are not expected to continue begin disposing of spent nuclear fuel by January 31, into 2005. 1998. These cases are currently stayed, pending litigation in other related cases.
Conversion: We have commitments providing for the In connection with our purchase of.Ginna, all of conversion of all of our uranium RG&E's rights and obligations related to recovery of concentrates into uranium hexafluoride for our nuclear facilities through 2006 damages from the DOE were assigned to us. However, we have an obligation to reimburse RG&E for up to and 63% in 2007 and 35% in 2008.
the first $10 million of any recovered damages. We and Enrichment: We have commitments that provide RG&E are currently requesting to allow us to replace 100% of our uranium enrichment RG&E as the party in interest in the complaint filed requirements tlrough 2010 and 25% of against the federal government by RG&zE.
these requirements in 2011 and 2012.
Fuel Assembly Storage of Spent Nuclear Fuel-On-Site Facilities Fabrication: We have commitments for the fabrication Calvert Cliffs has a license from the NRC to operate an of fuel assemblies for reloads required on-site independent spent fuel storage installation that through 2008 for Nine Mile Point, expires in 2012. We have storage capacity at Calvert through 2013 at Calvert Cliffs, and Cliffs that will accommodate spent fuel from operations through 2017 for Ginna. through 2008. In addition, we can expand our The nuclear fuel markets are competitive, and temporary storage capacity at Calvert Cliffs to meet although prices for uranium and conversion are future requirements until approximately 2025.
increasing, we do not anticipate any significant Currently, Nine Mile Point and Ginna do not have problems in meeting our future requirements. independent spent fuel storage capacity. Rather, Nine Mile Point's Unit 1 and Ginna have sufficient storage Storage of Spent Nuclear Fuel-FederalFacilities capacity within the plants until 2010. Nine Mile Point's One of the issues associated with the operation and Unit 2 has sufficient storage capacity within the plant decommissioning of nuclear generating facilities is until 2012. After that time, independent spent fuel disposal of spent nuclear fuel. There are no facilities for storage capability may need to be developed at each the reprocessing or permanent disposal of spent nuclear site.
fuel currently in operation in the United States, and the NRC has not licensed any such facilities. The Nuclear Cost for Decommissioning Uranium Enrichment Facilities Waste Policy Act of 1982 (NWPA) required the federal The Energy Policy Act of 1992 contains provisions government through the Department of Energy (DOE), requiring domestic nuclear utilities to contribute to a to develop a repository for the disposal of spent nuclear fund for decommissioning and decontaminating fuel and high-level radioactive waste. uranium enrichment facilities that had been operated by As required by the NWPA, we are a party to DOE. These contributions are generally payable over a contracts with the DOE to provide for disposal of spent 15-year period with escalation for inflation and are nuclear fuel from our nuclear generating plants. The based upon the amount of uranium enriched by DOE NWPA and our contracts with the DOE require for each utility through 1992. The 1992 Act provides payments to the DOE of one tenth of one cent (one that these costs are recoverable through utility service mill) per kilowatt hour on nuclear electricity generated rates. BGE is solely responsible for these costs as they 6
relate to Calvert Cliffs. The sellers of the Nine Mile renew supply contracts as they expire or enter into Point plant and the Long Island Power Authority are contracts with other coal suppliers. Our primary coal responsible for the costs relating to the Nine Mile Point burning facilities have the following requirements:
plant. The seller of Ginna is responsible for the costs Approximate related to that facility. Annual Coal Requirement Special Coal Cost for Decommissioning (tons) Restrictions We are obligated to decommission our nuclear plants at Brandon Shores Sulfur content less the time these plants cease operation. Every two years, Units 1 and 2 than 1.20 lbs per the NRC requires us to demonstrate reasonable (combined) ... 3,500,000 mmBTU assurance that funds will be available to decommission C. P. Crane the sites. When BGE transferred all of its nuclear Units 1 and 2 Low ash melting generating assets to our merchant energy business, it (combined) ... 850,000 temperature also transferred the trust fund established to pay for H. A. Wagner decommissioning Calvert Cliffs. At December 31, 2004, Units 2 and 3 Sulfur content no more the trust fund assets were $331.9 million. (combined) ... 1,100,000 than 1%
Under the Maryland Public Service Commission's Coal deliveries to these facilities are made by rail (Maryland PSC) order regarding the deregulation of and barge. The primary source of coal we use is electric generation, BGE ratepayers must pay a total of -produced from mines located in central and northern
$520 million, in 1993 dollars adjusted for inflation, to Appalachia. The timely delivery of coal together with decommission Calvert Cliffs through fixed annual the maintenance of appropriate levels of inventory is collections of approximately $18.7 million until necessary to allow for continued, reliable generation June 30, 2006, and thereafter in an annual amount from these facilities.
determined by reference to specified factors. BGE is During 2003, we expanded our coal sources collecting this amount on behalf of Calvert Cliffs. Any including restructuring our rail contracts, increasing the costs to decommission Calvert Cliffs in excess of this range of coals we can consume, adding synthetic fuel as
$520 million must be paid by Calvert Cliffs. If BGE an alternate source, and finding potential other coal ratepayers have paid more than this amount at the time supply sources including shipments from Columbia, of decommissioning, Calvert Cliffs must refund the Venezuela, South Africa, and other international sources.
excess. If the cost to decommission Calvert Cliffs is less - All of the Conemaugh and Keystone plants' annual than the amount BGE's ratepayers are obligated to pay, coal requirements are purchased by the plant operators Calvert Cliffs may keep the difference. from regional suppliers on the open market. The sulfur The sellers of Nine Mile Point transferred a restrictions on coal are approximately 2.3% for the
$441.7 million decommissioning trust fund to us at the Keystone plant and approximately 5.3% for the time of sale. In return, we assumed all liability for the Conemaugh plant.
costs to decommission Unit I and 82% of the costs to
- The annual coal requirements for the ACE, decommission Unit 2. We believe that this amount is Jasmin, and Poso plants, which are located in adequate to cover our responsibility for California, are supplied under contracts with mining decommissioning Nine Mile Point to a greenfield status operators. The Jasmin and Poso plants are restricted to (restoration of the site so that it substantially matches coal with sulfur content less than 4.0% and ACE is the natural state of the surrounding properties and the restricted to less than 2.0%.
site's intended use). At December 31, 2004, the Nine All of our requirements reflect historical levels. The Mile Point trust fund assets were $492.2 million. actual fuel quantities required can vary substantially Upon the closing of the Ginna acquisition, the from historical levels depending upon the relationship seller transferred $200.8 million in decommissioning between energy prices and fuel costs, weather funds to us. In return, we assumed all liability for the conditions, and operating requirements.
costs to decommission the unit. We believe that this transfer will be suffcient to cover our responsibility for Gas - -
decommissioning Ginna to a greenfield status. At We purchase natural gas, storage capacity, and December 31, 2004, the Ginna trust fund assets were transportation, as necessary, for electric generation at
$209.6 million. certain plants.- Some of our gas-fired units can use residual fuel oil or distillates instead of gas. Gas is Coal purchased under contracts with suppliers on the spot We purchase the majority of our coal for electric market and forward markets, including financial generation under supply contracts with mining ' exchanges and bilateral agreements. The actual fuel operators, and we acquire the remainder in the spot or quantities required can vary substantially from year to forward coal markets. We believe that we will be able to year depending upon the relationship between energy 7
prices and fuel costs, weather conditions, and operating With respect to power generation, we compete in requirements. However, we believe that we will be able the operation of energy-producing projects, and our to obtain adequate quantities of gas to meet our competitors in this business are both domestic and requirements. international organizations, induding various utilities, industrial companies and independent power producers Oil (including affiliates of utilities), some of which have Under normal burn practices, our requirements for financial resources that are greater than ours.
residual fuel oil (No. 6) amount to approximately Difficulties in making competitive assessments of 1.5 million to 2.0 million barrels of low-sulfur oil per our company arise from states considering different year. Deliveries of residual fuel oil are made from the types of regulatory initiatives concerning competition in suppliers' Baltimore Harbor marine terminal for the power industry. Increased competition that resulted distribution to the various generating plant locations.
from some of these initiatives in several states Also, based on normal burn practices, we require contributed in some instances to a reduction in approximately 5.0 million to 6.0 rriillion gallons of electricity prices and put pressure on electric utilities to distillates (No. 2 oil and kerosene) annually, but these lower their costs, induding the cost of purchased requirements can vary substantially from year to year electricity. While many states continue their support for depending upon the relationship between energy prices retail competition and industry restructuring, other and fuel costs, weather conditions, and operating states that were considering deregulation have slowed requirements. Distillates are purchased from the their plans or postponed consideration of deregulation.
suppliers' Baltimore truck terminals for distribution to In addition, other states are reconsidering deregulation.
the various generating plant locations. We have' We believe there is adequate growth potential in contracts with various suppliers to purchase oil at spot the current deregulated market and that further market prices, and for future delivery, to meet our changes could provide additional opportunities for our requirements. merchant energy business. Our wholesale marketing and risk management operation also participates in global Competition coal sourcing activities by providing coal for the variable Market developments over the past several years have or fixed supply needs of North American and changed the nature of competition in the merchant international power generators. In addition, our energy business. Certain companies within the merchant
.wholesale marketing and risk management operation energy sector have curtailed their activities or withdrawn provides products and services to upstream and completely from the business. However, new downstream natural gas customers.
competitors (e.g., financial investors) are entering the As the economy continues to recover and the market. We encounter competition from companies of market for commercial and industrial supply continues various sizes, having varying levels of experience, to grow, we have experienced increased competition in financial and human resources, and differing strategies.
our retail commercial and industrial supply activities.
We face competition in the market for energy, The increase in retail competition and the impact of capacity, and ancillary services. In our merchant energy wholesale power prices compared to the rates charged business, we compete with international, national, and by local utilities may affect the margins that we will regional full service energy providers, merchants, and realize from our customers. However, we believe that producers to obtain competitively priced supplies from a our experience and expertise in assessing and managing variety of sources and locations, and to utilize efficient risk will help us to remain competitive during volatile transmission or transportation. We principally compete or otherwise adverse market circumstances.
on the basis of price, customer service, reliability, and availability of our products.
8
Merchant Energy Operating Statistics 2004 2003 2002 2001 2000 Revenues (In millions)
Mid-Atlantic Fleet $ 1,925.6 $1,696.2 $1,415.1 $1.379.2 $ 731.7 Plants with Power Purchase Agreements 756.9 620.0 456.4 70.8 -
Competitive Supply-Rerail 4,280.0 2,567.7 312.7 - -
Competitive Supply-Wholesale 3,353.8 2,703.9 540.7 233.5 149.6 Other 73.6 45.1 56.4 80.5 142.5 Total Revenues $10,389.9 $7,632.9 $2,781.3 $1,764.0 $1,023.8 Generation (In mifions) -MWH 55.3 51.6 44.7 37.4 18.8 Operatingstatistics do not refect the elimination of intercompany transactions.
Certain prior-year amounts have been reclassifiedto conform with the current year! presentation.
Baltimore Gas and Electric Company Commercial and industrial customers have BGE is an electric transmission and distribution utility several service options that fix competitive company and a gas distribution utility company with a transition charges (CTC) through June 30, service territory that covers the City of Baltimore and 2006. CTC revenues were provided to allow all or part of ten counties in central Maryland. BGE is BGE to recover stranded costs that resulted regulated by the Maryland PSC and Federal Energy from the deregulation of BGE's generating Regulatory Commission .(FERC) with respect to rates assets.
and other aspects of its business. BGE residential base rates for delivery service BGE's electric service territory includes an area of will not change before July 2006. While total approximately 2,300 square miles. There are no. residential base rates remain unchanged over municipal or cooperative wholesale customers within the initial transition period (July 1, 2000 BGE's service territory. BGE's gas service territory through June 30, 2006), annual standard offer includes an area of approximately 800 square miles. service rate increases are offset by corresponding BGE's electric and gas revenues come from many decreases in the CTC that BGE receives from customers-residential, commercial, and industrial. In its customers.
2004, BGE's largest electric customer provided While BGE does not sell electric commodity to approximately two percent of BGE's total electric all customers in its service territory, BGE revenues and BGE's largest gas customer provided continues to deliver electricity to all customers approximately one percent of BGE's total gas revenues. and provides meter reading, billing, emergency response, regular maintenance, and balancing Electric Business services.
Electric Regulatory Matters and Competition BGE transferred, at book value, its generating assets and related liabilities to the merchant Deregulation energy business. At December 31, 2004, BGE Effective July 1, 2000, electric customer choice and remains contingently liable for the competition among electric suppliers was implemented in
$269.8 million outstanding balance for Maryland. As a result of the deregulation of electric liabilities transferred to the merchant energy generation, the following occurred business.
- All customers can choose their electric energy supplier.
Standard Offer Service
- BGE provided fixed-price standard offer service BGE provides fixed-price standard offer service for for commercial and industrial customers residential customers that do not select an alternative through either June 30, 2002 or June 30, 2004, supplier through June 30, 2006. Beginning July 1, depending on customer type. For the
-2006, BGE's current obligation to provide fixed-price commercial and industrial customers that did standard offer service to residential customers ends, and not select an alternative supplier after those all residential customers that receive their electric supply time periods, BGE provided a market-based from BGE will be charged market-based standard offer standard offer service. Base rates for commercial service rates, as discussed in the Standard Offer and industrial customers were frozen until Service-Providerof Last Resort (POLR) section.
June 30, 2004.
9
BGE provided fixed-price standard offer service for Electric Load Management most of its large commercial and industrial customers BGE has implemented various programs for use when through June 30, 2002. The large commercial and system-operating conditions or market economics industrial customers that did not select an alternative indicate that a reduction in load would be beneficial.
supplier were provided market-based standard offer We refer to these programs as active load management service through June 30, 2004. BGE provided fixed- programs. These programs include:
price standard offer service to its remaining commercial
- two options for commercial and industrial and industrial customers through June 30, 2004. customers to voluntarily reduce their electric Beginning July 1, 2004, all commercial and industrial loads, customers that receive their electric supply from BGE
- air conditioning control for residential and are charged market-based standard offer service rates, as commercial customers, and discussed in the Standard Offer Service-Provider of Last
- residential water heater control.
Resort (POLR) section. These programs generally take effect on summer days when demand and/or wholesale prices are relatively Standard Offer Service-Provider ofLast Resort (POLR) high. These programs had the capability during the BGE is obligated to provide market-based standard offer 2004 summer to reduce load up to approximately 220 service to residential customers from July 1, 2006 MW.
through May 31, 2010, and for commercial and industrial customers for one, two, or four-year periods Transmission and Distribution Facilities beyond June 30, 2004, depending on customer load.
BGE maintains approximately 250 substations and The POLR rates charged during these time periods will 1,300 circuit miles of transmission lines throughout recover BGE's wholesale power supply costs and include central Maryland. BGE also maintains nearly 22,900 an administrative fee. The administrative fee includes a circuit miles of distribution lines. The transmission shareholder return component and an incremental cost facilities are connected to those of neighboring utility component.
systems as part of the PJM Interconnection. Under the Bidding to supply BGE's standard offer service to PJM Tariff and various agreements, BGE and other commercial and industrial customers for one, two, or market participants can use regional transmission*
four-year periods beyond June 30, 2004, and to facilities for energy, capacity, and ancillary services residential customers beyond June 30, 2006, will occur transactions including emergency assistance.
from time to time through a competitive bidding We discuss various FERC initiatives relating to process approved by the Maryland PSC. Successful wholesale electric markets in more detail in Item 7.
bidders, which may include affiliates of Constellation Managements Discussion andAnalysis-FederalRegulation Energy, will execute contracts with BGE for varying section.
terms depending on the load being served under the contract.
We discuss the market risk of our regulated electric business in more detail in Item 7. Management's Discussion and Analysis-Market Risk section.
10
Electric Operating Statistics 2004 2003 2002 2001 2000 Revenues (In millions)
Residential $1,015.8 $ 959.0 $ 946.6 $ 885.3 $ 922.6 Commercial Excluding Delivery Service 708.9 694.2 776.0 903.0 926.2 Delivery Service Only 78.6 66.1 33.5 - -
Industrial Excluding Delivery Service 92.3 137.0 158.7 218.1 203.6 Delivery Service Only 21.3 18.2 10.9 - -
System Sales 1,916.9 1,874.5 1,925.7 2,006.4 2,052.4 Interchange Sales - - - - 53.8 Other (A) 50.8 47.1 40.3 33.6 29.0 Total $1,967.7 $1,921.6 $1,966.0 $2,040.0 $2,135.2 Distribution Volumes (In thousands)-MWH Residential 13,313 12,754 12,652 11,714 11,675 Commercial Excluding Delivery Service 9,286 9,937 11,840 14,147 14,042 Delivery Service Only 5,767 4,982 2,762 -
Industrial
~Excluding Delivery Service 1,429 2,556 3,478 4,445 4,476 Delivery Service Only 2,62 1,780 997-Total 32,357 32,009 31,729 30,306 30,193 Customers (In thousands)
Residential* 1,072.1 1,061.7 1,052.3 1,040.5 1,033.4 Commercial 113.6 112.1 110.8 110.9 108.9 Industrial 4.8 4.9 4.9 5.0 5.0 Total 1,190.5 1,178.7 1,168.0 1,156.4 1,147.3 (A) Primarily includes transmission service integration revenues, late payment charges, miscellaneous service fees, and tower leasing revenues.
Operatingstatistics do not reflect the elimination of intercompany transactions.
'Delivery service only' refers to BGEs delivery of commodity to customers that was purchased by the customerfrom an alternate supplier.
Gas Business For customers that buy their gas from BGE, there The wholesale price of natural gas as a commodity is is a market-based rates incentive mechanism. Under not subject to regulation. All BGE gas customers have market-based rates, our actual cost of gas is compared the option to purchase gas from alternative suppliers, to a market index (a measure of the market price of gas including subsidiaries of Constellation Energy. BGE in a given period). The difference between our actual continues to deliver gas to all customers within its cost'and the market index is shared equally between service territory. This delivery service is regulated by the shareholders and customers. BGE must secure fixed-Maryland PSC. price contracts for at least 10%, but not more than BGE also provides customers with meter reading, 20%, of forecasted system supply requirements for the billing, emergency response, regular maintenance, and November through March period.
balancing services. BGE purchases the natural gas it resells to Approximately 50% of the gas delivered on BGE'S customers directly from many producers and marketers.
distribution system is for customers that-purchase gas BGE has transportation and storage agreements that from alternative suppliers. These customers are charged expire from 2005 to 2023.
fees to recover the costs BGE incurs to deliver the' customers' gas through our distribution system.
11
BGE's current pipeline firm transportation during the summer months for operations of its entitlements to serve BGE's firm loads are 334,053 liquefied natural gas facility during peak winter periods.
dekatherms (DTH) per day during the winter period BGE historically has been able to arrange and 309,053 DTH per day during the summer period. short-term contracts or exchange agreements with other BGE's current maximum storage entitlements are gas companies in the event of short-term disruptions to 235,080 DTH per day. To supplement its gas supply at gas supplies or to meet additional demand.
times of heavy winter demands and to be available in IBGE also participates in the interstate markets by temporary emergencies affecting gas supply, BGE has: releasing pipeline capacity or bundling pipeline capacity
- a liquefied natural gas facility for the with gas for off-system sales. Off-system gas sales are liquefaction and storage of natural gas with a low-margin direct sales of gas to wholesale suppliers of total storage capacity of 1,092,977 DTH and a natural gas outside BGE's service territory. Earnings daily capacity of 311,500 DTH, and from these activities are shared between shareholders
- a propane air facility with a mined cavern with and customers. BGE makes these sales as part of a a total storage capacity equivalent to 564,200 program to balance our supply of, and cost of, natural DTH and a daily capacity of 85,000 DTH. gas.
BGE has under contract sufficient volumes of propane for the operation of the propane air facility and is capable of liquefying sufficient volumes of natural gas Gas Operating Statistics 2004 2003 2002 2001 2000 Revenues (In millions)
Residential Excluding Delivery Service $ 478.0 $ 444.5 $ 342.1 $ 378.4 $ 328.4 Delivery Service Only 14.2 13.6 16.5 16.3 23.5 Commercial Excluding Delivery Service 135A 128.6 89.4 115.5 97.9 Delivery Service Only 28.0 24.6 29.2 21.4 25.8 Industrial Excluding Delivery Service 9A 11.5 9.3 12.8 10.9 Delivery Service Only 7.8 11.4 13.9 13.8 16.3 System Sales 672.8 634.2 500.4 558.2 502.8 Off-System Sales 77.2 84.8 74.8 113.6 101.0 Other 7.0 7.0 6.1 8.9 7.8 Total $ 757.0 $ 726.0 $ 581.3 $ 680.7 $ 611.6 Distribution Volumes (in showands)-DTH Residential Excluding Delivery Service 39,080 40.894 35,364 33,147 34,561 Delivery Service Only 6,053 6,640 6,404 7,201 9,209 Commercial Excluding Deivery Service 13,248 13,895 11,583 12,334 13,186 Delivery Service Only 34,120 29,138 28,429 25,037 22,921 Industrial Excluding Delivery Service - 865 1,143 1,207 1,386. 1,386 Delivery Service Only 14,310 18,399 23,689 23,872 32,382 System Sales 107,676 110,109 106,676 102,977 113,645 Off-System Sales 9,914 12.859 18,551 20,012 22,456 Toal . 117,590 122.968 125,227 122,989 136,101 Customers (In shousands)
Residential 582.0 575.2 567.3 558.7 553.7 Commercial 41.6 41.1 40.7 40.2 40.1 Industrial - 1.2 1.2 1.3 1.4 1.4 Total 624.8 617.5 609.3 600.3 595.2 Operating statistics do not reflect the elimination of intercompany transactions.
- "Delivery service only' refers to BGEs delivery of commodity to customers that was purchased by the customerfiom an alternate supplier.
12
Franchises BGE has nonexdusive electric and gas franchises to use sufficient to permit them to engage in their present streets and other highways that are adequate and business. Conditions of the franchises are satisfactory.
Other Nonregulated Businesses Energy Prolects and Services Other We offer energy projects and services designed primarily - Our other nonregulated businesses include investments to provide energy solutions to large commercial and that we do not consider to be core operations. These industrial and governmental customers. These energy include financial investments, real estate projects, and products and services include: interests in a Panamanian distribution facility and in a
- designing, constructing, and operating heating, fund that holds interests in two South American energy cooling, and cogeneration facilities, projects. While our intent is to dispose of these assets,
+ energy consulting and power-quality services, market conditions and other events beyond our control
- services to enhance the reliability of individual may affect the actual sale of these assets. In addition, a electric supply systems, and future decline in the fair value of these assets could
- customized financing alternatives. result in losses. We discuss these non-core assets in more detail in Item 7. Managements Discussion and Home Products and Gas Retail Marketing Analysis-Results of Operations section.
We offer services to customers in Maryland including:
- home improvements,
- the service of heating, air conditioning, plumbing, electrical, and indoor air quality systems, and
- the sale of natural gas to residential customers.
Consolidated Capital Requirements Our total capital requirements for 2004 were We continuously review and change our capital
$762 million. Of this amount, $497 million was used expenditure programs, so actual expenditures may vary in our nonregulated businesses and $265 million was from the estimate above. We discuss our capital used in our regulated business. We estimate our total requirements further in Item 7 Management's Discussion capital requirements will be $915 million in 2005. and Analysis-CapitalResources section.
Environmental Matters regulations. Our estimated environmental capital The development (involving site selection, requirements for the next three years arc approximately environmental assessments, and permitting), $5 million in 2005, $45 million in 2006, and construction, acquisition, and operation of electric $80 million in 2007.
generating and distribution facilities are subject to extensive federal, state, and local environmental and Air Quality land use laws and regulations. From the beginning The Clean Air Act created the basic framework for the phases of development to the ongoing operation of federal and state regulation of air pollution. The existing or new electric generating and distribution cornerstone of the Act is the requirement that National facilities, our activities involve compliance with diverse Ambient Air Quality Standards be established to protect laws and regulations that address emissions and impacts public health and public welfare. In addition, the Act to air and water, protection of natural and cultural also includes technology-driven emission requirements.
resources, and chemical and waste handling and Many of these provisions could materially affect our disposal. facilities and are described in more detail below.
We continuously monitor federal, state, and local National Ambient Air Quality Standards (NAAQS) environmental initiatives to determine potential impacts on our financial results. As new laws or regulations are The NAAQS are federal air quality standards that promulgated, we assess their applicability and establish maximum ambient air concentrations for the following specific pollutants: ozone (smog), carbon implement the necessary modifications to our facilities monoxide, lead, particulates, sulfur dioxides (SO2), and or their operation to maintain on-going compliance.
nitrogen dioxides (NO2 ). Our generating facilities are Our capital expenditures were approximately
$235 million during the five-year period 2000-2004 to primarily affected by ozone and particulates standards.
comply with existing environmental standards and Ozone is formed when sunlight interacts with emissions 13
of nitrogen oxides (NOx) and volatile organic emissions as compared to its emissions when the area compounds (such as from motor vehicle exhaust). Our filled to meet the deadline. The exact method of generating facilities are subject to various permits and computing these fees has not been established and will programs meant to achieve or preserve attainment of depend in part on state implementation regulations that the standards for all these pollutants. have not been finalized.
In order for states to achieve compliance with the There are various deadlines for Maryland and NAAQS, federal and/or state legislation or regulation is California to meet the NAAQS for ozone with the likely to be adopted that will require additional earliest' being November 2005. Assessment of fees would emission reductions from our facilities. The commence in 2006 if the current effective dates are Environmental Protection Agency (EPA) has proposed maintained. However, there is significant uncertainty the Clean Air Interstate Rule (CAIR) to further reduce regarding the date when fees would be assessed and SO2 and NOx emissions by addressing the interstate whether they would be applicable to our facilities transport of SO 2and NOx emissions from fossil because the EPA is involved in litigation regarding these fuel-fired plants located primarily in the Eastern United issues. Consequently, we are unable to estimate the States. In addition to CAIR, the Bush Administration is ultimate applicability, timing or financial impact of the proposing a legislative approach (Clear Skies) which fees in light of the uncertainty surrounding the effective would require similar reductions in emissions of SO 2 dates and the methodology that will be used in and NOx. Depending on the timing and requirements calculating the fees.
of any federal proposal, one or more states in which we HazardousAir Emissions operate may impose more stringent or earlier emission The Clean Air Act requires the EPA to evaluate the reduction requirements. We favor the Clear Skies public health impacts of hazardous air emissions from approach to achieve future emission reductions as the electric steam generating facilities. In December 2003, fairest and most expeditious manner in which to meet the EPA proposed to regulate the emissions of mercury the NAAQS.
from coal-fired facilities and nickel from residual As a result of these regulatory and legislative oil-fired facilities. Under the mercury proposal, the EPA proposals, along with new rules to impose limits on has proposed compliance alternatives, including a unit' hazardous substances, we expect more stringent air specific standard and a cap and trade program. As emission standards to be adopted. If new requirements proposed, compliance with the unit specific limits are promulgated as expected we will install additional would be required as early as March 2008, but could be air emission control equipment at our coal-fired delayed for at least one year as allowed under the generating facilities in Maryland and at our co-owncd proposed requirements. Compliance with the mercury coal-fired facilities in Pennsylvania to meet air quality cap and trade program would be required by standards. We include in our estimated environmental January 2010. The Bush Administration's Clear Skies capital requirements capital spending for these projects, legislative proposal also addresses regulation of mercury which we expect will be approximately $2 million in through a cap and trade approach. The nickel emission 2005, $32 million in 2006, and $75 million in 2007. If limits for residual oil-fired facilities would require these rules are promulgated as we have assumed in our compliance by March 2008 but could be delayed for at projections, we will spend another $400-$500 million least one year as allowed under the proposed of capital from 2008-2010. Our estimates are subject to requirements. We believe final regulations could be significant uncertainties including the timing of any issued in 2005 and could affect all coal and oil-fired regulatory or legislative change, its implementation boilers at our generating facilities. The cost of timetable, and the amount of emissions reductions that compliance with the final regulations could be material.
will be required. As a result, we cannot predict our capital spending or the scope or timing of these projects New Source Review with certainty, and the actual expenditures, scope and The EPA and several states filed lawsuits against a timing could differ significantly from our estimates. number of coal-fired power plants primarily in On March 10, 2005, the EPA adopted CAIR. We Mid-Western and Southern states alleging violations of are in the process of evaluating the impact of the rules the Prevention of Significant Deterioration and on our financial results. Non-Attainment provisions of the Clean Air Act's new We own several generating facilities in Maryland source review requirements. The EPA requested and California, states that do not meet the NAAQS for information relating to modifications made to our ozone. The Clean Air Act requires states to assess fees Brandon Shores, Crane, and Wagner plants located in against every major stationary source of NOx and Maryland: The EPA also sent similar, but narrower, volatile organic compounds in areas that have not met information requests to two of our newer Pennsylvania the NAAQS for ozone if the NAAQS is not achieved waste-coal burning plants in which we have an by a specified deadline. If implemented, the fees would ownership interest. We have responded to the EPA, and be assessed based on the magnitude of a source's 14
as of the date of this report the EPA has taken no or other protective measures, as well as extensive.
further action. site-specific study and monitoring requirements. We Based on the level of emissions control that the currently have six facilities affected by the regulation.
EPA and states are seeking in these new source review The rule allows for a number of compliance options enforcement actions, we believe that material additional that will be assessed through 2007, following which we costs and penalties could be incurred, and planned will determine whether any action is required and what capital expenditures could be accelerated, if the EPA our most viable options are if any action is required.
was successful in any future actions regarding our Until we determine our most viable option under the facilities. final rules, we cannot estimate our compliance costs.
In August 2003, the EPA's equipment replacement However, the costs associated with the final rules could rule was promulgated. The rule establishes an be material.
equipment replacement cost threshold for determining when major new source review requirements are Hazardous and Solid Waste triggered. The rule provides that plant owners may .The Comprehensive Environmental Response, spend up to 20% of the replacement value of a Compensation and Liability Act (CERCLA) established generation unit on certain component replacements the basic framework for federal and state regulations each year without triggering requirements for new that can require any individual or entity that may have pollution controls. A legal challenge to this rule was owned or operated a disposal site, as well as transporters filed with the United States Court of Appeals and a stay or generators of hazardous substances sent to such site, was issued which delayed its effective date. The EPA to share in remediation costs. Except to the extent has also determined to seek additional comment on discussed in Note 12 to the Consolidated Financial certain features of the rule, including the 20% Statements, compliance with CERCLA requirements is threshold. We cannot predict the timing or outcome of not expected to have a material adverse effect on our the legal challenge or the EPA comment process, or financial results.
their possible effect on our financial results. The Resource Conservation and Recovery Act (RCRA) gives the EPA authority to control hazardous Global Climate Change waste from "cradle-to-grave." This includes the Future initiatives regarding greenhouse gas emissions generation, transportation, treatment, storage, and and global warming continue to be the subject of much disposal of hazardous waste. RCRA also sets forth a debate. As a result of our diverse fuel portfolio, our framework for the management of non-hazardous contribution to greenhouse gases varies by plant type.
wastes. Although RCRA focuses only on active and Fossil fuel-fired power plants are significant sources of future facilities and, unlike CERCLA, does not address carbon dioxide emissions, a principal greenhouse gas.
abandoned or historical sites, there are provisions that Our compliance costs with any mandated federal require phasing-out land disposal of hazardous waste, greenhouse gas reductions in the future could be more stringent hazardous waste management standards, material.
and a comprehensive underground storage tank program.
Water Quality Our coal-fired generating facilities produce The Clean Water Act established the basic framework approximately two million tons of combustion for federal and state regulation of water pollution by-products ("ash") each year, including approximately control. The Act requires facilities that discharge waste 700,000 tons at our Maryland plants. Of the two or storm water into the waters of the United States to million tons, approximately half is beneficially re-used obtain permits requiring them to meet effluent limits in in various projects, including as structural fill in surface order to achieve ambient water quality standards in the mine reclamation, and half is placed in landfills. In receiving waters. Under current provisions of the Clean 2000, the EPA decided not to regulate combustion ash Water Act, existing discharge permits are renewed every as a hazardous waste under RCRA. Instead, the EPA five years, at which time permit effluent limits come announced its intention to develop national standards, under extensive review and can be modified to account currently scheduled to be proposed in April 2006, to for more stringent regulations. In addition, the permits regulate this material as a non-hazardous waste, and is can be modified at any time. developing regulations governing the placement of ash Water Intake Regulations in landfills, surface impoundments, and sand/gravel In July 2004, the EPA published final rules under the surface mines. The EPA is also developing regulations Clean Water Act that require cooling water intake for ash placement in coal mines, which are expected to structures to reflect the best technology available for be proposed in October 2007. Federal regulation has minimizing adverse environmental impacts. The final the potential to result in additional requirements such rules require the installation of additional intake screens as groundwater monitoring, liners, and leachate 15
collection and treatment systems for all landfills, surface and the scope of the final requirements. As a result, we impoundments, and sand and gravel mines used for ash cannot predict our capital spending or the scope and management. Depending on the scope of any final timing of this project with certainty, and the actual requirements, our compliance costs could be material. expenditures, scope and timing could differ significantly As a result of these regulatory proposals, the from our estimates.
remaining ash placement capacity at our current mine reclamation site and our current ash generation Employees projections, we are exploring our options for the Constellation Energy and its subsidiaries had placement of ash, including construction of an ash approximately 9,570 employees at December 31, 2004.
placement facility. Over the next five years, we estimate At the Nine Mile Point plant, approximately 700 that our capital expenditures for this project will be as employees are represented by the International follows: approximately $10 million in 2006 and, if we Brotherhood of Electrical Workers, Local 97. The labor decide to construct a facility, approximately $55 million contract with this union expires in June 2006. We in 2008 towards the purchase of land. Our estimates are believe that our relationship with this union is subject to significant uncertainties including the timing satisfactory, but there can be no assurances that this will of any regulatory change, its implementation timetable, continue to be the case.
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Item 2. Properties expiration of the rights-of-way does not affect BGE's Constellation Energy's corporate offices occupy ability to use the rights-of-way during the renewal approximately 106,000 square feet of leased office space process.
in Baltimore, Maryland. The corporate offices for most - BGE has electric transmission and electric and gas of our merchant energy business occupy approximately distribution lines located:
172,000 square feer of leased office space in another
- in public streets and highways pursuant to building in Baltimore, Maryland. We describe our franchises, and electric generation properties on the next page. We also
- on rights-of-way secured for the most part by have leases for other offices and services located in the grants from owners of the property.
Baltimore metropolitan region, and for various real All of BGE's property is subject to the lien of property and facilities relating to our generation BGE's mortgage securing its mortgage bonds. All of the projects. generation facilities transferred to affiliates by BGE on BGE's principal headquarters building is located in July 1, 2000, along with the stock we own in certain of downtown Baltimore. In January 2004, BGE sold a our subsidiaries, are subject to the lien of BGE's portion of its headquarters building and is in the mortgage.
process of consolidating its operations into the We believe we have satisfactory title to our power remainder of the building. In addition, BGE owns project facilities in accordance with standards generally propane air and liquefied natural gas facilities as accepted in the energy industry, subject to exceptions, discussed in Item 1. Business-Gas Business section. which in our opinion, would not have a material BGE also has rights-of-way to maintain 26-inch adverse effect on the use or value of the facilities.
natural gas mains across certain Baltimore Ciry-owned We also lease office space throughout North property (principally parks) which expired in 2004. America, in the United Kingdom, and in Australia to BGE is in the process of renewing the rights-of-way support our merchant energy business.
with Baltimore City for an additional 25 years. The 17
The following table describes our generating facilities:
- Installed o Capacity ' Primary Plant Location Capacity (M ) Owned Owned (MW) Fuel
- (at December 31, 2004)
Mid-Atlantic Re'ion Calvert Cliffs Calvert Co., MD 1,735 100.0 1,735 Nudear Brandon Shores Anne Arundel Co., MD 1,286 100.0 1,286 Coal
}1. A. Wagner Anne Arundel Co., MD 1,009 100.0 1,009 Coal/Oil/Gas C. P Crane Baltimore Co., MD 399 100.0 399 Oil/Coal Keystone Armstrong and Indiana Cos., PA 1,711 21.0 359 (A) Coal Conensaugh Indiana Co., PA 1,711 10.6 181 (A) Coal Perryman Harford Co., MD 360 100.0 360 Oil/Gas Riverside Baltimore Co., MD 249 100.0 249 Oil/Gas Handsome Lake Rockdand 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 Philadelphia Road Baltimore City, MD 64 100.0 64 Oil Safe Harbor Safe Harbor, PA 416 66.7 277 Hydro Total Mid-Atlantic Region 9,439 6,418 Plants with Power Purchase Atreements High Desert Victorville, CA 830 100.0 830 Gas Nine Mile Point Unit 1 Scriba, NY - 609 100.0 609 Nuclear Nine Mile Point Unit 2 Scriba, NY 1,148 82.0 941 Nuclear R.E. Ginna Ontario, NY 495 100.0 495 Nuclear Oleander Brevard Co., FL : 680 100.0 680 Oil/Gas University Park Chicago, IL 300 100.0 300 Gas
-Total Plants with PowerPurchase Agreements 4,062 3,855 Competitiv'e Supply Rio Nogales Seguin, TX 800 100.0 800 Gas Holland Energy Shelby Co., IL 665 100.0 665 Gas Big Sandy Ncal, WV 300 100.0 300 Gas Wolf Hills Bristol, VA 250 100.0 250 Gas Total Competitive Supply 2,015 2,015 Other Panther Creek Nesquehoning, PA 83 50.0 42 Waste Coal Colver Colvcr Township, PA -- 110 25.0 28 Waste Coal Sunnyside Sunnyside, UT 53 50.0 26 Waste Coal ACE- Trona, CA 102 31.1 31 Coal Jasmin Kern Co., CA 33 50.0 17 Coal POSO Kern Co., CA 33 50.0 17 Coal 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 II Fallon, NV .13 50.0 7 Geothermal Rocldin 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 SEGS IV Kramer Junction, CA 30 12.0 4 Solar SEGS V Kramer Junction. CA 30 4.0
- 1 Solar SEGS VI Kramer Junction, CA
- 30 9.0 3 Solar Total Other 654 244 Total Generatinig Facilities 16,170 12,532 (A) Reflects our proportionate interest in and cntitlement to capacity fromm Keystone and Conemaugh, whirh include 2 megawatts of diesel capacity for Keystone and I megawatt of diesel capacity for Conemaugh.
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The following table describes our processing facilities:
Primary Plant Location Owned Fuel A/C Fuels Hazelton, PA 50.0 Coal Processing Gary PCI Gary, IN 24.5 Coal Processing Low Country Cross, SC 99.0 Synfuel 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 Mount Storm, WV 16.7 Synfuel Processing PC Synfuel WV III Mayberry, WV 16.7 Synfuel Processing Item 3. Legal Proceedings We discuss our legal proceedings in Note 12 to Comoelidated FinancialStatements.
Item 4. Submission of Matters to Vote of Security Holders Not applicable.
Executive Officers of the Registrant Other Offices or Positions Held Name Age Present Office During Past Five Years Mayo A. Shattuck III 50 Chairman of the Board of Constellation Global Head of Investment Banking and Energy (since July 2002), President Global Head of Private Banking-and Chief Executive Officer of Deutsche Banc Alex. Brown; and Vice Constellation Energy (since November Chairman-Bankers Trust 2001); and Chairman of the Board of Corporation.
BGE (since July 2002)
E. Follin Smith 45 Executive Vice President (since January Senior Vice President-Constellation 2004) and Chief Financial Officer Energy; Senior Vice President and (since June 2001) and Chief Chief Financial Officer-Armstrong Administrative Officer (since Holdings, Inc.; Vice President and December 2003) of Constellation Treasurer-Armstrong Holdings, Inc.
Energy and Senior Vice President and (filed for bankruptcy under Chief Financial Officer of Baltimore Chapter II on December 6, 2000);
Gas and Electric Company (since and Chief Financial Officer-General January 2002) Motors-Delphi Chassis Systems.
Thomas V. Brooks 42 President of Constellation Energy Vice President of Business Development Commodities Group, Inc. (formerly and Strategy-Constellation Energy; Constellation Power Source, Inc.) and Vice President-Goldman Sachs.
(since October 2001); Executive Vice President of Constellation Energy (since January 2004)
Michael J. Wallace 57 President of Constellation Generation Managing Director and Member-Group, LLC (since January 2002); Barrington Energy Partners; and Executive Vice President of Senior Vice President-Constellation Energy (since January Commonwealth Edison.
2004)
Thomas F. Brady 55 Executive Vice President, Corporate Senior Vice President, Corporate Strategy and Retail Competitive Strategy and Development-Supply of Constellation Energy (since Constellation Energy-, Vice President, January 2004) Corporate Strategy and Development-Constellation Energy, and Vice President, Corporate Strategy and Development-BGE.
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Other Offices or Positions Held Name Age Present Office During Past Five Years Kenneth W. DeFontes, Jr. 54 President and Chief Executive Officer of Vice President, Electric Transmission Baltimore Gas and Electric Company and Distribution-BGE; and and Senior Vice President of Manager, Corporate Strategy and Constellation Energy (since October Development-Constellation Energy.
2004)
Paul J. Allen 53 Senior Vice President, Corporate Affairs Vice President, Corporate Affairs-of Constellation Energy (since January Constellation Energy; and Senior Vice 2004) President and Group Head-Ogilvy Public Relations.
John R. Collins 47 Senior Vice President (since January Vice President-Constellation Energy; 2004) and Chief Risk Officer of Managing Director-Finance-Constellation Energy (since December Constellation Power Source 2001) Holdings, Inc.; and Senior Financial Officer-Constellation Power Source, Inc.
Beth S. Perlman 44 Senior Vice President (since January Vice President, Technology-Enron 2004) and Chief Information Officer Corporation.
of Constellation Energy (since April 2002)
Marc L Ugol 46 Senior Vice President, Human Resources Vice President, Human Resources-of Constellation Energy (since January Constellation Energy; Senior Vice 2004) President, Human Resources and Administration-Tellabs, Inc.; 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 2005, we announced an increase in our Constellation Energy's common stock is traded under quarterly dividend from $0.285 to $0.335 per share on the ticker symbol CEG. It is listed on the New York, our common stock payable April 1, 2005 to holders of Chicago, and Pacific stock exchanges. It has unlisted record on March 10, 2005. This is equivalent to an trading privileges on the Boston, Cincinnati, and annual rate of $1.34 per share.
Philadelphia exchanges. Quarterly dividends were declared on our common As of February 28, 2005, there were 45,843 stock during 2004 and 2003 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. 6.20% Deferrable Interest Subordinated Dividends have been paid continuously since 1910 Debentures due 2043, and any deferred interest on the common stock of Constellation Energy, BGE, remains unpaid; or and their predecessors. Future dividends depend upon
- any dividends (and any redemption payments) future earnings, our financial condition, and other due on BGEs preference stock have not been factors. paid.
Common Stock Dividends and Price Ranges 2004 2003 Dividend Price Dividend Price Declared High Low Declared High LoW First Quarter .$0.285 $41.47 $38.52 $0.260 $30.23 $25.17 Second Quarter .0.285 41.35 35.89 0.260 34.92 27.50 Third Quarter .0.285 41.18 36.76 0.260 37.65 31.75 Fourth Quarter.0.285 44.90 39.90 0.260 39.61 35.03 Total. $1.140 $1.040
- Based on New York Stock Exchange Composite Transactions.
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Item 6. Selected Financial Data Constellation Energy Group, Inc. and Subsidiaries 2004 2003 2002 2001 2000 (In milons, except per share amounts)
Summary of Operations Total Revenues $12,549.7 $ 9,687.8 $ 4,718.6 $ 3,877.3 $ 3,772.5 Total Expenses 11,471.3 8,647.7 3,893.7 3,525.7 3,008.0 Net (Loss) Gain on Sales of Investments and Other Assets (1.2) 26.2 261.3 6.2 78.1 Income From Operations 1,077.2 1,066.3 1,086.2 357.8 842.6 Other Income - 14.1 19.1 30.5 1.3 4.2 Fixed Charges 330.3 340.2 281.5 -238.8 271.4 Income Before Income Taxes 761.0 745.2 835.2 120.3 575.4 Income Taxes 172.2 269.5 309.6 37.9 230.1 Income from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles 588.8 475.7 525.6 82.4 345.3 Loss from Discontinued Operations, Net of Income Taxes (49.1) - - -
Cumulative Effects of Changes in Accounting Principles, Net of Income Taxes - (198.4) - 8.5 Net Income $ 539.7 $ 277.3 $ 525.6 $ 90.9 5 345.3 Earnings Per Common Share from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles Assuming Dilution $ 3.40 $ 2.85 $ 3.20 S 0.52 $ 2.30 Loss from Discontinued Operations (0.28) - - -
Cumulative Effects of Changes in Accounting Principles (1.19) - 0.05 Earnings Per Common Share Assuming Dilution $ 3.12 $ 1.66 $ 3.20 $ 0.57 $ 2.30 Dividends Declared Per Common Share $ 1.14 $ 1.04 I$ 0.96 $ 0.48 $ 1.68 Summary of Financial Condition Total Assets $17,347.1 $15,593.0 $14,943.3 $14,697.5 $13,248.1 Short-Term Borrowings $ - $ 9.6 $ 10.5 $ 975.0 $ 243.6 Current Portion of Long-Term Debt $ 480.4 $ 343.2 $ 426.2 $ 1,406.7 $ 906.6 Capitalization Long-Term Debt $ 4,813.2 $ 5,039.2 $ 4,613.9 $ 2,712.5 $ 3,159.3 Minority Interests 90.9 113.4 105.3 101.7 97.7 Preference Stock Not Subject to Mandatory Redemption 190.0 190.0 190.0 190.0 - 190.0 Common Shareholders' Equity 4,726.9 4,140.5 3,862.3 3,843.6 3,174.0 Total Capitalization $-9,821.0 $ 9,483.1 $ 8,771.5 $ 6,847.8 $ 6,621.0 Financial Statistics at Year End Ratio of Earnings to Fixed Charges 3.11 2.98 3.33 1.18 2.78 Book Value Per Share of Common Stock $ 26.81 $ 24.68 $ 23.44 $ 23.48 $ 21.09 Certainprior-yearamounts have been reclassified to conform with the currentyearspresentation.
We discuss items that affect comparability between years, including acquisitions, accounting changes, including the impact of adopting Emerging Issues Task Force Issue (EITF) 02-3, Issues Involved in Accounting for Derivative Contracts Heldfor Trading Purposes and Contracts Involved in Energy Tradingand Risk Management Activities, and special items, in Item 7. Managements Discussion and Analysis.
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Baltimore Gas and Electric Company and Subsidiaries 2004 2003 2002 2001 2000 (In millions)
Summary of Operations Total Revenues $2,724.7 $2,647.6 $2,547.3 $2,720.7 $2,746.8 Total Expenses 2,353.3 2,262.6 2,181.0 2,408.9 2,334.4 Income From Operations 371.4 385.0 366.3 311.8 412.4 Other (Expense) Income (6.4) (5.4) 10.7 0.4 7.5 Fixed Charges 96.2 111.2 140.6 154.6 184.0 Income Before Income Taxes 268.8 268.4 236.4 157.6 235.9 Income Taxes 102.5 105.2 93.3 60.3 92.4 Net Income 166.3 163.2 143.1 97.3 143.5
-Preference Stock Dividends 13.2 13.2 13.2 13.2 13.2 Earnings Applicable to Common Stock $ 153.1 $ 150.0 $ 129.9 $ 84.1 $ 130.3 Summary of Financial Condition Total Assets $4,662.9 $4,706.6 $4,779.9 $4,954.5 $4,657.4 Short-Term Borrowings $ - $ - $ - $ - $ 32.1 Current Portion of Long-Term Debt $ 165.9 $ 330.6 $ 420.7 $ 666.3 $ 567.6 Capitalization Long-Term Debt $1,359.5 $1,343.7 $1,499.1 $1,821.7 $1,864.4 Minority Interest 18.7 18.9 19.4 5.0 4.6 Preference Stock Not Subject to Mandatory Redemption - 190.0. 190.0 190.0 190.0 190.0 Common Shareholder's Equity 1,566.0 1,487.7 1,461.7 1,131.4 802.3 Total Capitalization $3,134.2 $3,040.3 $3,170.2 $3,148.1 $2,861.3 Financial Statistics at Year End Ratio of Earnings to Fixed Charges 3.75 3.36 2.66 1.99 2.27 Ratio of Earnings to Fixed Charges and Preferred and Preference Stock Dividends 3.08 2.82 2.31 1.75 2.03 23
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations Introduction and Overview Strategy Constellation Energy Group, Inc. (Constellation Energy) is a We are pursuing a strategy of distributing energy and energy North American energy company that conducts its business related services through our competitive supply activities and through various subsidiaries including a merchant energy BGE, our regulated utility located in Maryland. Our merchant business and Baltimore Gas and Electric Company (BGE). We energy business focuses on short-term and long-term, high-value describe our operating segments in Note 3. sales of energy, capacity, and related products to various This report is a combined report of Constellation Energy customers, including distribution utilities, municipalities, and BGE. References in this report to "we" and "our" are to cooperatives, industrial customers, and commercial customers Constellation Energy and its subsidiaries, collectively. References. primarily in the regional markets in which end-use customer in this report to the 'regulated business(es)" are to BGE. We electricity and gas rates have been deregulated and thereby discuss our business in more detail in Item 1. Business section. separated from the cost of generation and gas supply. These In this discussion and analysis, we will explain the general markets include.
financial condition and the results of operations for
- the Northeast (New England and New York),
Constellation Energy and BGE including:
- the Mid-Atlantic and Midwest regions,
- factors which affect our businesses,
- the West region (Texas and California), and
- our earnings and costs in the periods presented,
- certain areas in Canada.
- changes in earnings and costs between periods, We obtain this energy through both owned and contracted
- sources of earnings, supply resources. Our generation fleet is strategically located in
- impact of these factors on our overall financial deregulated markets across the country and is diversified by fuel type, including nuclear, coal, gas, oil, and renewable sources.
condition, Where we do not own generation, we contract for power from
- expected future expenditures for capital projects, and other merchant providers, typically through power purchase
- expected sources of cash for future capital expenditures.
agreements. We intend to remain diversified between regulated As you read this discussion and analysis, refer to our transmission and distribution and competitive supply. We will Consolidated Statements of Income, which present the results of use both our owned generation and our contracted generation to our operations for 2004, 2003, and 2002. Our results reflect a support our competitive supply operations.
significant increase in revenues and in purchased fuel and energy We are a leading national competitive supplier of energy in expenses mainly due to the implementation of Emerging Issues the deregulated markets previously discussed. In our wholesale Task Force Issue (EITF) 02-3, Issues Involved in Accountingfor and commercial and industrial retail marketing activities we are Derivative Contracts Heldfor Trading Purposes and Contracts leveraging our recognized expertise in providing full requirements Involved in Energy Trading and Risk ManagementActivities in energy and energy related services to enter markets, capture January 2003, as well as the full year impact of our 2002 market share, and organically grow these businesses. Through the acquisitions. We discuss our acquisitions in more detail in Note 15. application of technology, intellectual capital, process We analyze and explain the differences between periods in the improvement, and increased scale, we are seeking to reduce the specific line items of our Consolidated Statements of Income. cost of delivering full requirements energy and energy related We have organized our discussion and analysis as follows: services and managing risk.
- First, we discuss our strategy. We are also responding proactively to customer needs by
- We then describe the business environment in which we expanding the variety of products we offer. Our wholesale operate including how regulation, weather, and other competitive supply activities include a growing customer factors affect our business. products operation that markets physical energy products and
- Next, we discuss our critical accounting policies. These risk management and logistics services to generators, distributors, are the accounting policies that are most important to producers of coal, natural gas and fuel oil, and other, consumers.
both the portrayal of our financial condition and results Within our retail competitive supply activities, we are of operations and require management's most difficult, marketing a broader array of products and expanding our subjective or complex judgment. markets. Over time, we may consider integrating the sale of
- We highlight significant events that are important to electricity and natural gas to provide one energy procurement understanding our results of operations and financial solution for our customers.
condition. - Collectively, the integration of owned and contracted
- We then review our results of operations beginning with electric generation assets with origination, fuel procurement, and an overview of our total company results, followed by a risk management expertise, allows our merchant energy business more detailed review of those results by operating to earn incremental margin and more effectively manage energy segment. and commodity price risk over geographic regions and over time.
- We review our financial condition addressing our: Our focus is on providing solutions to customers' energy needs, sources and uses of cash, security ratings, capital and our wholesale marketing and risk management operation resources, capital requirements, commitments, and adds value to our owned and contracted generation assets by off-balance sheet arrangements. providing national market access, market infrastructure, real-time
- We conclude with a discussion of our exposure to market intelligence, risk management and arbitrage various market risks. opportunities, and transmission and transportation expertise.
Generation capacity supports our wholesale marketing and risk management operation by providing a source of reliable power supply that provides a physical hedge for some of our load-serving activities.
24
To achieve our strategic objectives, we expect to continue to Electric Competition pursue opportunities that expand our access to customers and to We face competition in the sale of electricity in wholesale power support our wholesale marketing and risk management operation markets and to retail customers.
with generation assets that have diversified geographic, fuel, and Various states have moved to restructure their electricity dispatch characteristics. We also expect to grow organically markets. The pace of deregulation in these states varies based on through selling a greater number of physical energy products and historical moves to competition and responses to recent market services to large energy customers. We expect to achieve events. While many states continue their support for retail operating efficiencies within our competitive supply operation competition and industry restructuring, other states that were and our generation fleer by selling more products through our considering deregulation have slowed their plans or postponed existing sales force, benefiting from efficiencies of scale, adding consideration. In addition, other states are reconsidering to the capacity of existing plants, and making our business deregulation. We discuss merchant competition in more detail in processes more efficient. Item 1. Buriness-Competition section.
.We expect BGE and our other retail energy service
- The impacts of electric deregulation on BGE in Maryland businesses to grow through focused and disciplined expansion are discussed in Item 1. Business-Electric Regulatory Matters and primarily from new customers. At BGE, we are also focused on Competition section.
enhancing reliability and customer satisfaction.
Customer choice, regulatory change, and energy market Gas Competition conditions significantly impact our business. In response, we The wholesale price of natural gas is not subject to regulation.
regularly evaluate our strategies with these goals in mind: to All BGE gas customers have the option to purchase gas from improve our competitive position, to anticipate and adapt to the alternate suppliers.
business environment and regulatory changes, and to maintain a strong balance sheet and investment-grade credit quality. Regulation by the Maryland PSC We are constantly reevaluating our strategies and might In addition to electric restructuring which was discussed in Item consider: 1. Business--Electric Regulatory Matters and Competition section,
- acquiring or developing additional generating facilities to regulation by the Maryland Public Service Commission support our merchant energy business, (Maryland PSC) significantly influences BGEs businesses. The
- mergers or acquisitions of utility or non-utility Maryland PSC determines the rates that BGE can charge businesses or assets, and customers for the electric distribution and gas businesses. The
- sale of assets or one or more businesses. Maryland PSC incorporates into BGE's electric rates the transmission rates determined by the Federal Energy Regulatory Business Environment Commission (FERC). BGE's electric rates are unbundled in General Industry customer billings to show separate components for delivery Over the past several years, the utility industry and energy service (i.e. base rates), competitive transition charges, electric markets experienced significant changes as a result of less liquid supply (commodity charge), transmission, a universal service and more volatile wholesale markets, credit quality deterioration surcharge, and certain taxes. The rates for BGE's regulated gas of various industry participants, and the slowing of the U.S. business continue to consist of a delivery charge (base rate) and economy. a commodity charge.
The energy markets also were affected by other significant events, induding expanded investigations by state and federal Base Rates authorities into business practices of energy companies in the *Thebase rate is the rate the Maryland PSC allows BGE to deregulated power and gas markets relating to "wash trading" to charge its customers for the cost of providing them delivery inflate revenues and volumes, and other trading practices service, plus a profit. BGE has both an electric base rate and a designed to manipulate market prices. In addition, several gas base rate. Higher electric base rates apply during the summer merchant energy businesses significantly reduced their energy when the demand for electricity is higher. Gas base rates are not trading activities due to deteriorating credit quality. affected by seasonal changes.
Over the last few years, the energy markets have been BGE may ask the Maryland PSC to increase base rates highly volatile with significant changes in natural gas and power. from time to time. The Maryland PSC historically has allowed prices, as well as the continuation of reduced liquidity in the BGE to increase base rates to recover its utility plant investment marketplace. We continue to actively manage our credit portfolio and operating costs, plus a profit, beginning at the time of to attempt to reduce the impact of a potential counterparty replacement. Generally, rate increases improve the earnings of default. We discuss our customer (counterparty) credit and other. our regulated business because they allow us to collect more risks in more detail in the Market Risk section. revenue. However, rate increases are normally granted based on We also continue to examine plans to achieve our strategies historical data, and those increases may not always keep pace and to further strengthen our balance sheet and enhance our with increasing costs. Other parties may petition the Maryland liquidity. We discuss our liquidity in the FinancialCondition PSC to decrease base rates.
section.
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As a result of the deregulation of electric generation in implement measures to mitigate the market power in order to Maryland, BGE's residential electric base rates are frozen until maintain market-based rate authority. In addition, FERC is July 2006. Electric base rates were frozen until July 2004 for reviewing other aspects of its granting of market-based rate commercial and industrial customers. We discuss electric authority, including transmission market power, affiliate abuse, deregulation in Item -1.Business-Electric Regulatory Matters and and barriers to entry. We cannot determine the eventual Competition section. outcome of FERC's efforts in this regard and their impact on our financial re'sults at this time.
Electric Commodity and Transmission Charges In January 2005, BGE and other transmission owners filed a BGE electric commodity and transmission charges (standard joint application at FERC to have network transmission rates offer service) are discussed in Item 1. Business-ElectricRegulatory established through a formula that tracks costs instead of through Matters and Competition section. fixed rates in accordance with FERC guidelines. If accepted by FERC, the formula approach would take effect in June 2005, and Gas Commodity Charge transmission rates would be adjusted in June of each year based BGE charges its gas customers separately for the natural gas they on the formula without the need for another transmission rate purchase. The price BGE charges for the natural gas is based on filing. We cannot predict the outcome of this proceeding a market-based rates incentive mechanism approved by the including whether the FERC will accept the formula approach.
Maryland PSC. We discuss market-based rates and a proceeding Other market changes are also being considered, including with the Maryland PSC in more detail in the Regulated Gas potential revisions to PJM's capacity market and rate design.
Business-Gas Cost Adjustments section and in Note 6 Such changes will be subject to FERC's review and approval. We cannot predict the outcome of these proceedings or the possible Federal Regulation effect on our, or BGE's, financial results at this time.
FERC The FERC has jurisdiction over various aspects of our business, FederalEnergy Legislation including transmission and wholesale electricity sales. Although a While energy legislation was not passed by Congress in 2004, FERC proposed rulemaking regarding implementation of a we expect that some form of energy legislation will be brought standard market design for wholesale electric markets appears to before Congress during the upcoming legislative session. We have halted, FERC has indicated that it continues to have a cannot predict the impact of potential legislation on our strong commitment to customer-focused, competitive wholesale financial results at this time.
power markets, with appropriate flexibility to accommodate regional differences. We believe that FERC's commitment should Weather result in improved competitive markets across various regions. Merchant Energy Business Since 1997, operation of BGE's transmission system has Weather conditions in the different regions of North America been under the authority of PJM, the Regional Transmission influence the financial results of our merchant energy business.
Organization (RTO) for the Mid-Atlantic region, pursuant to Weather conditions can affect the supply of and demand for FERC oversight. As the transmission operator, PJM operates the electricity and fuels. Changes in energy supply and demand may energy markets and conducts day-to-day operations of the bulk impact the price of these energy commodities in both the spot power system. market and the forward marker, which may affect our results in In addition to PJM, RTOs exist in other regions of the any given period. Typically, demand for electricity and its price country, such as the Midwest, New York, and New England. In are higher in the summer and the winter, when weather is more addition to operation of the transmission system and responsibility extreme. The demand for and price of natural gas and oil are for transmission system reliability, these RTOs also operate, or higher in the winter. However, all regions of North America plan to operate, energy markets for their region pursuant to typically do not experience extreme weather conditions at the FERC's oversight. Our merchant energy business participates in same time, thus we are not typically exposed to the effects of these regional energy markets. These markets are continuing to extreme weather in all parts of our business at once.
develop, and revisions to market structure are subject to review and approval in proceedings before FERC and other regulatory BGE bodies. We cannot predict the outcome of these proceedings at. Weather affects the demand for electricity and gas for our this time. However, changes 'to the structure of these markets regulated businesses. Very hot summers and very cold winters could have a material effect on our financial results. increase demand. Mild weather reduces demand. Weather affects Recent initiatives at FERC have included a review of its residential sales more than commercial and industrial sales, methodology for the granting of market-based rate authority to which are mostly affected by business needs for electricity and sellers of electricity. FERC has announced new interim tests that gas. The Maryland PSC allows BGE to record a monthly will be used to determine the extent to which companies may adjustment to our regulated gas business revenues to eliminate have marker power in certain regions. Where market power is the effect of abnormal weather patterns. We discuss this further found to exist, companies may be required by FERC to in the Regulated Gas Business-Weather Normalization section.
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Other Factors consume more electricity and gas. Conversely, during an A number of other factors significantly influence the level and economic downturn, our customers tend to consume less volatility of prices for energy commodities and related derivative electricity and gas.
products for our merchant energy business. These factors include: Environmental Matters and Legal Proceedings
- seasonal daily and hourly changes in demand, We discuss details of our environmental matters in Note 12 and
- number of market participants, Item 1. Business-EnvironmentalMatters section. We discuss details
- extreme peak demands, of our legal proceedings in Note 12. Some of this information is
- available supply resources, about costs that may be material to our financial results.
- transportation and transmission availability and reliability within and between regions, Accounting Standards Adopted and Issued
- location of our generating facilities relative to the We discuss recently adopted and issued accounting standards in location of our load-serving obligations, Note 1.
- implementation of new market rules governing operations of regional power pools, Critical Accounting Policies
- procedures used to maintain the integrity of the physical Our discussion and analysis of financial condition and results of electricity system during extreme conditions, - operations is based on our consolidated financial statements that
. changes in the nature and extent of federal and state were prepared in accordance with accounting principles generally regulations, and accepted in the United States of America. Management makes
- international demand. estimates and assumptions when preparing financial statements.
These factors can affect energy commodity and derivative These estimates and assumptions affect various matters, prices in different ways and to different degrees. These effects including:
may vary throughout the country as a result of regional
- our reported amounts of revenues and expenses in our differences in: Consolidated Statements of Income,
- weather conditions,
- our reported amounts of assets and liabilities in our
- market liquidity, Consolidated Balance Sheets, and
- capability and reliability of the physical electricity and
- our disclosure of contingent assets and liabilities.
gas systems, These estimates involve judgments with respect to
- local transportation systems, and numerous factors that are difficult to predict and are beyond
- the nature and extent of electricity deregulation. management's control. As a result, actual amounts could Our merchant energy business contracts with rail companies materially differ from these estimates.
to ensure the delivery of coal to our coal-fired generation Management believes the following accounting policies facilities. The timely delivery of coal together with the represent critical accounting policies as defined by the Securities maintenance of appropriate levels of inventory is necessary to and Exchange Commission (SEC). The'SEC defines critical allow for continued, reliable generation from these facilities. In accounting policies as those that are both most important to the the second, third, and fourth quarters of 2004, we experienced portrayal of a companys financial condition and results of delays in deliveries from one of the rail companies that supplies operations and require management's most difficult, subjective, coal to our generating facilities. In response, we procured coal or complex judgment, often as a result of the need to make using an alternative delivery method to meet our contractual estimates about the effect of matters that are inherently load obligations. We discuss the impact of these delays on our uncertain and may change in subsequent periods. We discuss our financial results in the Mid-Atlantic Reion section. We expect significant accounting policies, including those that do not the majority of the coal that was not delivered during 2004 will require management to make difficult, subjective, or complex be delivered during 2005. judgments or estimates, in Note 1.
Other factors also impact the demand for electricity and gas in our regulated businesses. These factors include the number of Revenue RecognitionlMark-to-Market Method of customers and usage per customer during a given period. We use Accounting these terms later in our discussions of regulated electric and gas Our merchant energy business enters into contracts for energy, operations. In those sections, we discuss how these and other other energy-related commodities, and related derivatives. We factors affected electric and gas sales during the periods record merchant energy business revenues using two methods of presented. accounting: accrual accounting and mark-to-market accounting.
The number of customers in a given period is affected by We describe our use of accrual accounting (including hedge new home and apartment construction and by the number of accounting) in more detail in Note 1.
businesses in our service territory. We record revenues using the mark-to-market method of Usage per customer refers to all other items impacting accounting for derivative contracts for which we are not permitted customer sales that cannot be measured separately. These factors to use accrual accounting or hedge accounting. These include the strength of the economy in our service territory. R mark-to-market activities include derivative contracts for energy When the economy is healthy and expanding, customers tend to and other energy-related commodities. Under the mark-to-market 27
method of accounting, we record the fair value of these derivatives as we realize cash flows under the contract or when as mark-to-market energy assets and liabilities at the time of observable market data becomes available.
contract execution. We record the changes in mark-to-market
- Credit-spread adjustment-for risk management energy assets and liabilities on a net basis in "Nonregulated purposes, we compute the value of our mark-to-market revenues" in our Consolidated Statements of Income. energy assets and liabilities using a risk-free discount Mark-to-market energy assets and liabilities consist of a - rate. In order to compute fair value for financial combination of energy and energy-related derivative contracts. reporting purposes, we adjust the value of our While some of these contracts represent commodities or mark-to-market energy assets to reflect the credit-instruments for which prices are available from external sources, worthiness of each counterparty based upon either other commodities and certain contracts are not actively traded published credit ratings, or equivalent internal credit and are valued using modeling techniques to determine expected ratings and associated default probability percentages.
future market prices, contract quantities, or both. The market We compute this adjustment by applying a default prices and quantities used to determine fair value reflect - probability percentage to our outstanding credit management's best estimate considering various factors. However, exposure, net of collateral, for each counterparty. The future market prices and actual quantities will vary from those level of this adjustment increases as our credit exposure used in recording mark-to-market energy assets and liabilities, to counterparties increases, the maturity terms of our and it is possible that such variations could be material. transactions increase, or the credit ratings of our We record valuation adjustments to reflect uncertainties counterparties deteriorate, and it decreases when our associated withcertain estimates inherent in the determination credit exposure to counterparties decreases, the maturity of the fair value of mark-to-market energy assets and liabilities. terms of our transactions decrease, or dhe credit ratings The effect of these uncertainties is not incorporated in marker of our counterparties improve.
price information or other market-based estimates used to Market prices for energy and energy-related commodities determine fair value of our mark-to-market energy contracts. To vary based upon a number of factors, and changes in market the extent possible, we utilize market-based data together with prices affect both the recorded fair value of our mark-to-market quantitative methods for both measuring the uncertainties for energy contracts and the level of future revenues and costs which we record valuation adjustments and determining the level associated with accrual-basis activities. Changes in the value of of such adjustments and changes in those levels. our mark-to-market energy contracts will affect our earnings in We describe below the main types of valuation adjustments the period of the change, while changes in forward market prices we record and the process for establishing each. Generally, related to accrual-basis revenues and costs will affect our earnings increases in valuation adjustments reduce our earnings, and in future periods to the extent those prices are realized. We decreases in valuation adjustments increase our earnings. cannot predict whether, or to what extent, the factors affecting However, all or a portion of the effect on earnings of changes in market prices may change, but those changes could be material valuation adjustments may be offset by changes in the value of and could affect us either favorably or unfavorably. We discuss the underlying positions. our market risk in more detail in the Market Risk section.
- Close-out adjustment-represents the estimated cost to In October 2002, the EITF reached a consensus on close out or sell to a third-party open mark-to-market Issue 02-3. This consensus prohibits mark-to-market accounting positions. This valuation adjustment has the effect of for energy-related contracts that do not meet the definition of a valuing "long", positions (the purchase of a commodity) derivative under Statement of Financial Accounting Standards at the bid price and "short" positions (the sale of a (SFAS) No. 133, Accounting for Derivative Instruments and commodity) at the offer price. We compute this Hedging Activities, a; amended.As a result, we began to account adjustment using a market-based estimate of the bid/ for all non-derivative contracts on the accrual basis of offer spread for each commodity and option price and accounting effective January 1, 2003 as described in Note 1. The the absolute quantity of our net open positions for each consensus also prohibits recording unrealized gains or losses at year. The level of total close-out valuation adjustments the inception of derivative contracts unless the fair value of each increases as we have larger unhedged positions,- bid-offer contract in its entirety is evidenced by quoted market prices or spreads increase, or market information is not available, other current marker transactions for contracts with similar and it decreases as we reduce our unhedged positions, terms and counterparties, and it requires gains and losses on bid-offer spreads decrease, or market information derivative energy trading contracts (whether realized or becomes available. To the extent that we are not able to unrealized) to be reported as revenue on a net basis in the obtain observable market information for similar income statement.
contracts, the close-out adjustment is equivalent to the EITF 02-3 affects the timing of recognizing earnings on initial contract margin, thereby resulting in no gain or non-derivative transactions. In general, beginning in 2003 loss at inception. In the absence of observable market earnings on non-derivative transactions subject to EITF 02-3 are information, there is a presumption that the transaction no longer recognized at the inception of the transactions as they
..price is equal to the market value of the contract, and were under mark-to-marker accounting because they are subject therefore we do not recognize a gain or loss at to accrual accounting and are recognized over the term of the inception. We recognize such gains or losses in earnings transaction. As a result, while total earnings over the term of a 28
transaction are the same as they would have been under not recoverable under SFAS No. 144 if the carrying amount mark-to-market accounting, our reported earnings for contracts exceeds the sum of the undiscounted future cash flows expected subject to EITF 02-3 generally match the cash flows from those to result from the use and eventual disposition of the asset.
contracts more closely. Additionally, because we record revenues Therefore, when we believe an impairment condition may have and costs on a gross basis under accrual accounting, our occurred, we are required to estimate the undiscounted future revenues and costs increased, but our earnings have not been cash flows associated with a long-lived asset or group of affected by gross versus net reporting. long-lived assets. This necessarily requires us to estimate The impact of derivative contracts on our revenues and uncertain future cash flows.
costs is affected by many factors, including: In order to estimate an asset's future cash flows, we
- our ability to designate and qualify derivative contracts consider historical cash flows and changes in the market for normal purchase and sale accounting or hedge environment and other factors that may affect future cash flows.
accounting under SFAS No. 133, To the extent applicable, the assumptions we use are consistent
- potential volatility in earnings from derivative contracts with forecasts that wc are otherwise required to make (for that serve as economic hedges but do not meet the example, in preparing our other earnings forecasts). If we are accounting requirements to qualify for normal purchase considering alternative courses of action to recover the carrying and sale accounting or hedge accounting, amount of a long-lived asset (such as the potential sale of an
- our ability to enter into new mark-to-market derivative asset), we probability-weight the alternative courses of action to origination transactions, and estimate the cash flows.
- sufficient liquidity and transparency in the energy We use our best estimates in making these evaluations and markets to permit us to record gains at inception of new consider various factors, including forward price curves for derivative contracts because fair value is evidenced by energy, fuel costs, and operating costs. However, actual future quoted market prices, current market transactions, or market prices and project costs could vary from the assumptions other observable market information. used in our estimates, and the impact of such variations could We discuss the impact of mark-to-market accounting on be material.
our financial results in the Results of Operations-Merchant For long-lived assets that can be classified as assets held for Energy Business section. sale under SFAS No. 144, an impairment loss is recognized to the extent their carrying amount exceeds their fair value less Evaluation of Assets for Impairment and Other Than costs to sell.
Temporary Decline In Value If we determine that the undiscounted cash flows from an Long-Lived Assets asset to be held and used are less than the carrying amount of We are required to evaluate certain assets that have long lives the asset, or if we have classified an asset as held for sale, we (for example, generating property and equipment and real estate) must estimate fair value to determine the amount of any to determine if they are impaired when certain conditions exist.
impairment loss. The estimation of fair value under SFAS SFAS No. 144, Accountingfor the Impairment or Disposalof No. 144, whether in conjunction with an asset to be held and Long-Lived Assets, provides the accounting requirements for used or with an asset held for sale, also involves judgment. We impairments of long-lived assets. We are required to test our consider quoted market prices in active markets to the extent long-lived assets for recoverability whenever events or changes in they are available. In the absence of such information, we may circumstances indicate that their carrying amount may not be consider prices of similar assets, consult with brokers, or employ recoverable. Examples of such events or changes are: other valuation techniques. Often, we will discount the
- -a significant decrease in the market price of a long-lived estimated future cash flows associated with the asset using a asset, single interest rate that is commensurate with the risk involved
- a significant adverse change in the manner an asset is with such an investment or employ an expected present value being used or its physical condition, method that probability-weights a range of possible outcomes.
- an adverse action by a regulator or in the business The use of these methods involves the same inherent uncertainty climate, of future cash flows as discussed above with respect to
- an accumulation of costs significantly in excess of the undiscounted cash flows. Actual future market prices and project amount originally expected for the construction or costs could vary from those used in our estimates, and the acquisition of an asset, impact of such variations could be material.
- a current-period loss combined with a history of losses We are also 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 ofAccounting for Investments in Common Stock, provides estimated useful life. the accounting requirements for these investments. The standard For long-lived assets that are expected to be held and used, for determining whether an impairment must be recorded under SFAS No. 144 provides 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 and exceeds its fair value. The carrying amount of an asset is 29
value that is considered an "other than a temporary" decline in SPAS No. 143 requires the use of an expected present value value. methodology in measuring asset retirement obligations that The evaluation and measurement of impairments under the involves judgment surrounding the inherent uncertainty of the APB No. 18 standard involves the same uncertainties as probability, amount and timing of payments to settle these described on the previous page for long-lived assets that we own obligations, and the appropriate interest rates to discount future directly and account for in accordance with SFAS No. 144. cash flows. We use our best estimates in identifying and Similarly, the estimates that we make with respect to our equity measuring our asset retirement obligations in accordance with and cost-method investments are subject to variation, and the SPAS No. 143.
impact of such variations could be material. Additionally, if the Our nuclear decommissioning costs represent our largest projects in which we hold these investments recognize an asset retirement obligation. This obligation primarily results from impairment under the provisions of SPAS No. 144, we would the requirement to decommission and decontaminate our record our proportionate share of that impairment loss and nudear generating facilities in connection with their future would evaluate our investment for an other than temporary retirement. We utilize site-specific decommissioning cost decline in value under APB No. 18. estimates to determine our nuclear asset retirement obligations.
However, given the magnitude of the amounts involved, Debt and Equity Securities complicated and ever-changing technical and regulatory Our investments in debt and equity securities are subject to requirements, and the very long time horizons involved, the impairment evaluations under SFAS No. 115, Accounting for actual obligation could vary from the assumptions used in our Certain Investments in Debt and Equity Securities. SFAS No. 115 estimates, and the impact of such variations could be material.
requires us to determine whether a decline in fair value of an investment below the amortized cost basis is other than Significant Events temporary. If we determine that the decline in fair value is In 2004, we recorded the following special items in earnings:
judged to be other than temporary, the cost basis of the Pre- After-Tax Tax investment must be written down to fair value as a new cost basis. We discuss EITF 03-1, The Meaning of Other Than (In millions)
Temporary Impairment and Its Application to Certain Investments, Loss from discontinued operations $(75.6) $(49.1) in the Accounting Standards Issued section of Note 1.
Recognition of 2003 synthetic fuel tax credits - 35.9 Workforce reduction costs (9.7) (5.9)
Goodwill Impairment losses and other costs (3.7) (2.2)
Goodwill is the excess of the purchase price of an acquired Net loss on sales of investments and other business over the fair value of the net assets acquired. We assets (1.2) (0.6) account for goodwill and other intangibles under the provisions Total special items $(90.2) $(21.9) of SPAS No. 142, Goodwill and Other Intangible Assets. We do not amortize goodwill and certain other intangible assets. SPAS Loss from Discontinued Operations No. 142 requires us to evaluate goodwill for impairment at least During 2004, we completed the sale of a geothermal facility in annually or more frequently if events and circumstances indicate Hawaii. We recorded a loss of $77.7 million pre-tax, or the business might be impaired. Goodwill is impaired if the $50.4 million after-tax, during the year ended December 31, carrying value of the business exceeds fair value. Annually, we 2004. We reported the after-tax loss as a component of "Loss estimate the fair value of the businesses we have acquired using from discontinued operations" in our Consolidated Statements techniques similar to those used to estimate future cash flows for of Income. Additionally, prior to sale we recognized earnings long-lived assets as discussed on the previous page, which from the facility of $2.1 million pre-tax, or $1.3 million involves judgment. If the estimated fair value of the business is after-tax as a component of "Loss from discontinued less than its carrying value, an impairment loss is required to be operations." We discuss the loss from discontinued operations in recognized to the extent that the carrying value of goodwill is more detail in Note 2.
greater than its fair value.
Synthetic Fuel Tax Credits Asset Retirement Obligations We have investments in facilities that manufacture solid We incur legal obligations associated with the retirement of synthetic fuel produced from coal as defined under Section 29 certain long-lived assets. SPAS No. 143, Accountingfor Asset of the Internal Revenue Code for which we can claim tax credits Retirement Obligations,provides the accounting for legal on our Federal income tax return until 2007. We recognize the obligations associated with the retirement of long-lived assets; tax benefit of these credits in our Consolidated Statements of We incur such legal obligations as a result of environmental and Income when we believe it is highly probable that the credits other government regulations, contractual agreements, and other will be sustained.
factors. The application of this standard requires significant As of December 31, 2004, we have recognized cumulative tax benefits associated with Section 29 credits of $201.2 million.
judgment due to the large number and diverse nature of the assets in our various businesses and the estimation of future cash In 2004, we recognized $123.2 million in tax benefits for flows required to measure legal obligations associated with the Section 29 credits, including $35.9 million for credits relating to retirement of specific assets. 2003 production. We discuss the synthetic fuel tax credits in more detail in Note J0.
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Workforce Reduction Costs Results of Operations In the fourth quarter of 2004, we approved a restructuring of In this section, we discuss our earnings and the factors affecting the work forces of the Nine Mile Point and Calvert Cliffs them. Wc begin with a general overview, then separately discuss nuclear generating facilities that was effective in January 2005. earnings for our operating segments. Significant changes in other In connection with this restructuring, approximately 108 income and expense, fixed charges, and income taxes are employees will receive severance and other benefits under our discussed in the aggregate for all segments in the Consolidated existing benefit programs. We accrued the estimated total cost of NonoperatingIncome and Expenses section.
this reduction in workforce of $9.7 million pre-tax, or
$5.9 million after-tax, in accordance with applicable accounting Overview requirements. We expect to realize annual savings in the future Results from reduced labor and benefit costs approximately equal to the 2004 2003 2002 charge recorded in 2004.
(In millions, after-ax)
Merchant energy $439.0 $313.0 $247.2 Impairment of Financial Investment Regulated electric 131.1 107.5 99.3 Our other nonregulated businesses recognized a pre-tax Regulated gas 22.2 43.0 31.1 impairment loss of $3.7 million, or $2.2 million after-tax, Other nonregulared (3.5) 12.2 148.0 during the year ended December 31, 2004 related to an other Net Income Before Cumulative Effects of than temporary decline in fair value of certain financial Changes in Accounting Principles 588.8 475.7 525.6 investments. Loss from discontinued operations (49.1) - -
Cumulative effects of changes in Net Loss on Sales of Investments and Other Assets accounting principles - (198.4) -
Our other nonregulated businesses recognized a net pre-tax loss Net Income $539.7 $277.3 5525.6 of $1.2 million, or $0.6 million after-tax, during the year ended Special Items Included in Operations:
December 31, 2004 on the sales of non-core assets. We discuss Recognition of 2003 synthetic fuel tax our net loss on sales of investments and other assets in more credits $ 35.9 $ - $ -
detail in Note 2. Workforce reduction costs (5.9) (1.3) (38.0)
Impairments of real estate, senior-living, Acquisition and other investments (2.2) (0.4) (1.2)
In June 2004, we completed our purchase of the R. E. Ginna Net (loss) gain on sales of investments nuclear facility (Ginna), which is located in Ontario, New York and other assets (0.6) 16.4 166.7 from Rochester Gas & Electric Corporation (RG&E). Ginna Impairments of investment in qualifying facilities and domestic power projects - - (9.9) consists of a 495 megawatt reactor that entered service in 1970 Costs associated with exit of BGE Home and is licensed to operate until 2029. We discuss the acquisition merchandise stores - - (6.1) further in Note 15.
Total Special Items $ 27.2 $ 14.7 $111.5 Dividend Increase In January 2005, we announced an increase in our quarterly 2004 dividend to $0.335 per share on our common stock. This is Our total net income for 2004 increased $262.4 million, or equivalent to an annual rate of $1.34 per share. Previously, our $1.46 per share, compared to the same period of 2003 mostly.
quarterly dividend on our common stock was $0.285 per share, because of the following-equivalent to an annual rate of $1.14 per share.
- In 2003, we recorded a $266.1 million after-tax, or
$1.60 per share, loss for the cumulative effect of adopting EITF 02-3. This was partially offset by a
$67.7 million after-tax, or $0.41 per share, gain for the cumulative effect of adopting Statement of Financial Accounting Standards (SFAS) No. 143, Accountingfor Asset Retirement Obligations. These items had a combined negative impact during 2003.
- Our merchant energy business had higher earnings of
$78.4 million at our South Carolina synfuel facility primarily due'to the recognition of $35.9 million in tax credits associated with 2003 production and tax credits associated with 2004 production.
- We had higher earnings from our regulated electric business mostly because of the absence of $19.4 million
- of after-tax incremental operations and maintenance expenses due to distribution service restoration efforts associated with Hurricane Isabel in 2003.
31
- We had higher earnings from our nuclear generating
- We had higher fixed charges of $58.7 million due to assets due to the June 2004 acquisition of Ginna, which lower capitalized interest of $30.2 million and contributed $28.1 million after-tax, and higher $28.5 million primarily related to a higher level of debt generation at our Calvert Cliffs nuclear power plant, outstanding as a result of refinancing our High Desert partially offset by lower generation by and lower power facility.
prices for the output of our Nine Mile Point facility in
- Our results reflect the impact of the shift to accrual 2004 compared to 2003.. accounting under EITF 02-3. Specifically, the absence of
- We had higher earnings from our merchant energy 2002 mark-to-market gains for contracts accounted for business mostly due to the realization of wholesale on an accrual basis in 2003 and the timing difference in contracts originated in prior periods, portfolio the recognition of earnings for certain economic hedges, management, and favorable settlements at our retail - which we discuss further in the Conipetive Supply-electric operation of $16.9 million pre-tax. Mark-to-Market Revenues section, were only partially
- We had higher earnings due to lowver pre-tax losses of ' offset by the 2003 recognition of accrual earnings on
$47.7 million associated with economic hedges that do transactions entered into in prior periods.
not qualify for cash-flow hedge accounting treatment.
- Our regulated electric business incurred incremental
- We had higher earnings of $20.9 million after-tax in distribution service restoration expenses of $19.4 million 2004 due to a full year of operations at the High Desert after-tax associated with Hurricane Isabel.
facility. These decreases were partially offset by the following:
These increases were partially offset by the following:
- We had higher earnings from wholesale competitive
- We recorded a $49.1 million after-tax, or $0.28 per supply activities including effective portfolio share, loss from discontinued operations. management, partially offset by lower mark-to-market
- We had higher Sarbanes-Oxley 404 implementation origination in 2003.
costs of approximately $15 million pre-tax, higher
- We had $39.5 million of higher earnings from our enterprise information systems expenditures of regulated business, excluding the impacts of Hurricane approximately $8 million pre-tax, and higher Isabel.
compensation, benefit, and other inflationary cost
- We had higher earnings from favorable generating plant increases. operational performance. Specifically, our High Desert
- We had lower earnings from our regulated gas business facility commenced operations in April 2003 mostly because of $13.6 million after-tax of higher contributing $39.1 million after-tax, and Calvert Cliffs operations and maintenance expenses in 2004 and the completed a steam generator replacement in April 2003, absence of a $4.7 million after-tax market-based rate gas 58 fewer days than a similar outage that was completed recovery, which had a favorable effect in 2003. in June 2002.
- We recognized a gain of $16.4 million after-tax related
- We had $36.7 million after-tax of higher workforce to non-core asset sales in 2003 that had a favorable reduction costs in 2002 that had a negative impact in impact in that period. the period.
Earnings per share was impacted by additional dilution
- We realized cost reductions due to productivity resulting from the issuance of 6.0 million shares of common initiatives.
stock on July 1, 2004.
- We had higher earnings from a full year at our retail electric operation, which contributed $20.3 million, and 2003 from the acquisition of our retail gas operation, which Our total net income for 2003 decreased $248.3 million, or contributed $4.1 million.
$1.54 per share, compared to 2002 mostly because of the Our other nonregulated business recognized a gain of following: $16.4 million after-tax, or $0.10 per share, in 2003
- We recorded a $266.1 million after-tax, or $1.60 per. related to non-core asset sales.
share, charge for the cumulative effect of adopting
- We had higher earnings from our other nonregulated EITF 02-3. This was partially offset by a $67.7 million businesses primarily related to improved operations of after-tax, or $0.41 per share, gain for the cumulative our international portfolio of $7.0 million after-tax.
effect of adopting SFAS No. 143.
- We had $6.1 million after-tax of costs associated with
- We recognized a $163.3 million after-tax, or $1.00 per our exit of BGE Home merchandise stores in 2002 that share, gain on the sale of our investment in Orion had a negative impact in that period.
Power Holdings, Inc. (Orion) in 2002 that had a
- We recognized impairments of certain investments in positive impact in that period. We discuss the sale of qualifying facilities, real estate, and other investments in Orion in more detail in Note 2. 2002 that had a negative impact in that period.
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Merchant Energy Business EITF 02-3 affects the timing of recognizing earnings on Background non-derivative transactions. Earnings on new non-derivative Our merchant energy business is a competitive provider of transactions subject to EITF 02-3 are no longer recognized at energy solutions for various customers. We discuss the impact of the inception of the transactions as they were under deregulation on our merchant energy business in Item 1. mark-to-market accounting because they are subject to accrual Business-Competition section. accounting and are recognized over the term of the transaction.
We record merchant energy revenues and expenses in our Additionally, we expect lower earnings volatility for this financial results in different periods depending upon which portion of our business because unrealized changes in the fair portion of our business they affect. We discuss our revenue value of non-derivative load-serving contracts will no longer be recognition policies in the CriticalAccounting Policies section and recorded as revenue at the time of the change as they were in Note 1. We summarize our policies as follows: under mark-to-market accounting.
- We record revenues as they are earned and fuel and purchased energy expenses as they are incurred for .Results contracts and activities subject to accrual accounting, 2004 2003 2002 induding certain load-serving activities. (In millions)
- Prior to the settlement of the forecasted transaction Revenues $10,389.9 $ 7,632.9 $ 2,781.3 being hedged, we record changes in the fair value of Fuel and purchased energy contracts designated as cash-flow hedges in other expenses - (8,129.3) (5,706.1) (1,208.3) comprehensive income to the extent that the hedges are Operating expenses (1,178.4) (935.9) (759.8) effective. We record the effective portion of the changes Workforce reduction costs (9.7) (1.2) (26.5)
Impairment losses and other costs - - (14.4) in fair value of hedges in earnings in the period the Depreciation and amortization (248.0) (229.5) (242.8) settlement of the hedged transaction occurs. We record Accretion of asset retirement the ineffective portion of the changes in fair value of obligations (53.2) (42.7) -
hedges, if any, in earnings in the period in which the Taxes other than income taxes (91.5) (89.2) (69.7) change occurs. Net loss on sales of assets - - (3.7)
- We record changes in the fair value of contracts that are Income from Operations $ 679.8 $ 628.3 $ 456.1 subject to mark-to-market accounting in revenues on a Income from continuing net basis in the period in which the change occurs.
operations before cumulative -
Mark-to-market accounting requires us to make estimates effects of changes in and assumptions using judgment in determining the fair value of accounting principles (after-tax) $ -439.0 $ 313.0 $ 247.2 certain contracts and in recording revenues from those contracts. Loss from discontinued We discuss the effects of mark-to-market accounting on our operations (after-tax) (49.1) - -
revenues in the Competitive Supply-Mark-to-Market Revenues Cumulative effects of changes in section. We discuss mark-to-market accounting and the accounting principles (after-tax) - (198.4) -
accounting policies for the merchant energy business further in Net Income $ 389.9 $ 114.6 $ 247.2 the CriticalAccounting Policies section and in Note 1.
Special hiems Included in OperaSions In the first quarter of 2003, we adopted EITF 02-3, which (a1fier-tax) required non-derivative contracts to be accounted for on the Recognition of 2003 synthetic accrual basis and recorded in our Consolidated Statements of fuel tax credits $ 35.9 $ - $
Income gross rather than net. The primary contracts affected Workforce reduction costs (5.9) (0.7) (16.0) were our full requirements load-serving contracts and Impairment of investments in unit-contingent power purchase contracts. The majority of these qualif'ing facilities and contracts were in Texas and New England and were entered into domestic power projects - - (9.9)
Net loss on sales of assets - - .(2.4) prior to our shift to accrual accounting earlier in 2002. We discuss our shift to accrual accounting during 2002 in more Total Special Items $ 30.0 $ (0.7) $ (28.3) detail in the -Wholesale Accrual Activities section. After the Above amounts include intercompany transarcionseliminated in our re-designation of existing contracts to non-trading, we record ConsolidatedFinancialStatements. Note 3 provides a reconciliation revenues and expenses on a gross basis, but this does not have a Of operating results by segment to our ConsolidatedFinancial material impact on earnings because the resulting increase in Statements. Certainprior-yearamounts have been reclassified to revenues is accompanied by a similar increase in fuel and conform with the current year's presentation.
purchased energy expenses.
33
Revenues and Fuel and PurchasedEnergy Expenses We provide a summary of our revenues, fuel and purchased Our merchant energy business manages the revenues we realize energy expenses, and gross margin as follows:
from the sale of energy to our customers and our costs of 2004 2003 2002 procuring fuel and energy. The difference between revenues and fuel and purchased energy expenses is the gross margin of our (Dollar amounts in millions) merchant energy business, and this measure is management's Revenues:
primary tool for assessing the profitability of our merchant Mid-Adantic Region $ 1,925.6 - 1,696.2 $ 1,415.1 energy business. Accordingly, we believe it is appropriate to Plants with discuss the operating results of our merchant energy business by Power analyzing the changes in gross margin between periods. In Purchase managing our portfolio, we occasionally terminate, restructure, Agreements 756.9 620.0 456.4 or acquire contracts. Such transactions are within the normal Competitive course of managing our portfolio and may materially impact the Supply timing of our recognition of revenues, fuel and purchased energy Retail 4,280.0 2,567.7 312.7 Wholesale 3,353.8 2,703.9 540.7 expenses, and cash flows.
Other 73.6 45.1 56.4 We analyze our merchant energy gross margin in the following categories because of the risk profile of each category, Total $10,389.9 $ 7,632.9 $ 2,781.3 differences in the revenue sources, and the nature of fuel and Fuel and purchased energy expenses. With the exception of a portion of purchased our competitive supply activities that we are required to account energy expenses:
for using the mark-to-market method of accounting, all of these Mid-Atlantic activities are accounted for on an accrual basis. Region $ (946.9) $ (711.6) $ (551.2)
Plants with
- Mid-Atlantic Region-our fossil, nuclear, and Power hydroelectric generating facilities and load-serving Purchase activities in the PJM Interconnection (PJM) region for Agreements (57.6) (51.9) (40.0) which the output is primarily used to serve BGE. This Competitive also includes active portfolio management of the Supply generating assets and other physical and financial Retail (4,011.4) (2,389.5) (273.2) contractual arrangements, as well as other PJM Wholesale (3,113.4) (2,553.1) (343.9) competitive supply activities. Other - - -
- Plants with Power Purchase Agreements-our generating Total $ (8,129.3) $(5,706.1) $(1,208.3) facilities outside the Mid-Atlantic Region with long-term % of % of 96of power purchase agreements, induding the Nine Mile Gross margin: Total Total Total Point, Ginna, Oleander, University Park, and High Mid-Adantic Desert facilities. Region $ 978.7 43% $ 984.6 51% S 863.9 55%
- Wholesale Competitive Supply-our marketing and risk Plants with management operation that provides energy products Power and services outside the Mid-Atlantic Region primarily Purchase to distribution utilities, power generators, and other Agreements 699.3 31 568.1 29 416.4 26 wholesale customers. Competitive
- Retail Competitive Supply-our operation that provides Supply electric and gas energy products and services to Retail 268.6 12 178.2 9 39.5 3 Wholesale 240.4 11 150.8 8 196.8 13 commercial and industrial customers.
Other 73.6 3 45.1 3 56.4 3
- Other-our investments in qualifying facilities and Total $ 2,260.6 100% $ 1,926.8 100% $ 1,573.0 100%
domestic power projects and our operations and maintenance consulting services. Certainprior-yearamounts have been reclassified to conforrn withy the currentyearspresentation.
Mid-Atlantic Region 2004 2003 2002 (In millions)
Revenues $1,925.6 $1,696.2 $1,415.1 Fuel and purchased energy expenses - (946.9) (711.6) (551.2)
Gross margin $ 978.7 S 984.6 $ 863.9 34
The decrease in Mid-Atlantic Region gross margin in 2004
- higher gross margin of $18.7 million from the Oleander compared to 2003 is primarily due to lower fossil plant generating facility that contributed a full year of gross availability resulting in lower margin of $17.0 million and margin during 2003 compared to six months of higher coal costs primarily due to purchasing coal from operations during 2002.
alternative suppliers in 2004 at higher prices than in 2003 as a result of delays in deliveries as discussed in the Business Competitive Suppl.
Environment-OtherFactors section. These decreases were Retail partially offset by an increase in margin of $7.1 million related to new load-serving obligations, offset in part by lower volumes 2004 2003 2002 served to BGE resulting from small commercial customers (In millions) leaving BGE's standard offer service due to the end of fixed- Accrual revenues $ 4,281.0 S 2,567.7 $ 312.7 price service in June 2004. Mark-to-markec revenues (1.0) - -
The increase in Mid-Atlantic Region gross margin in 2003 Fuel and purchased energy expenses (4,011.4) (2.389.5) (273.2) compared to 2002 is primarily due to: Gross margin $ 268.6 $ 178.2 $ 39.5
- higher margins of approximately $85 million from our The increase in gross margin from our retail competitive supply owned generation in excess of that used to serve BGE's activities in 2004 compared to 2003 is primarily due to higher standard offer service, including our active portfolio electric gross margin of $66.1 million mostly due to:
management of these generating assets and associated
- serving approximately 16 million more megawatt hours physical and financial arrangements, and partially offset by lower realized margins'due to
- a gain on the assumption of the Allegheny Energy increased wholesale power costs in 2004 compared to Supply Company, L.L.C. load-serving contract for the 2003, remaining 10% of the BGE standard offer service load.
- a bankruptcy settlement from PG&E of $10.3 million, and a favorable settlement of a pre-acquisition liability Plants with Power PurchaseAgreements of $6.6 million also related to a bankruptcy proceeding, 2004 2003 2002 - and
- lower contract amortization, which reduces margin, of (In millions)
$9.2 million relating to the fair value of contracts at Revenues $756.9 $620.0 $456.4 acquisition.
Fuel and purchased energy expenses (57.6) (51.9) (40.0)
In addition, we had higher gas gross margin contribution of Gross margin $699.3 $568.1 $416.4 $17.1 million from Blackhawk Energy Services and Kaztex The increase in gross margin from our Plants with Power Energy Management, which were acquired in October 2003. We Purchase Agreements in 2004 compared to 2003 is primarily discuss our acquisitions in more detail in Note 15.
due to: The increase in gross margin from our retail competitive
- gross margin of $112.4 million from Ginna, which was supply activities in 2003 compared to 2002 is due to:
acquired in June 2004. The increase in gross margin
- a'full year of electric gross margin contribution of includes higher revenues of $119.1 million. We discuss $115.9 million. The increase in electric gross margin this acquisition in more detail in Note 14, and includes higher revenues of $1,170.2 million. Our retail
- higher gross margin of $45.9 million from the High electric operation was acquired in September 2002, and Desert facility that contributed a full year of gross
- a full year of gas gross margin contribution of margin in 2004 compared to eight months in 2003. $22.8 million. The increase in gas gross margin includes These increases in gross margin were partially offset by higher revenues of $1,084.8 million. Our retail gas lower gross margin of $21.0 million at our Nine Mile Point operation was acquired in December 2002.
facility primarily due to lower revenues from reduced contract prices for the output in 2004 compared to 2003 and lower holesale 2004 2003 2002 generation.
- The increase in gross margin from our Plants with Power (In millions)
Purchase Agreements in 2003 compared to 2002 is primarily Accrual revenues $ 3,253.7 $ 2,667.7 $ 310.7 due to: Fuel and purchased energy expenses (3,113.4) (2.553.1) (343.9)
- gross margin of $105.5 million from the High Desert Wholesale accrual activities 140.3 - 114.6 (33.2) facility, which commenced operations in the second Mark-to-markct revenues 100.1 36.2 230.0 quarter of 2003. The increase in gross margin includes Gross margin . . $ 240.4 S 150.8 $ 196.8 higher revenues of $111.3 million,
. higher gross margin of $22.6 million from Nine Mile Point primarily due to fewer forced outage days in 2003 compared to 2002, and 35
In January 2003, we adopted EITF 02-3 that changed the The increase in revenues, fuel and purchased energy accounting for certain energy contracts. EITF 02-3 prohibits the expenses, and gross margin from our wholesale accrual activities use of mark-to-market accounting for any energy-related in 2003 compared to 2002 is primarily due to the impact of the contracts that are not derivatives. Any non-derivative contracts adoption of EITF 02-3 as discussed above. While it is not must be accounted for on the accrual basis and recorded in the practicable to determine precisely the impact of EITF 02-3 on income statement gross rather than net upon application of. revenues and gross margin, accrual revenues for 2003 include EITF 02-3. This change applied immediately to new contracts approximately $1.4 billion from load-serving contracts that executed after October 25, 2002 and applied to existing existed at January 1, 2003 (the date EITF 02-3 was adopted) non-derivative energy-related contracts beginning January 1, which had been accounted for on a mark-to-market basis in 2003. During 2002, the majority of our wholesale results were 2002.
on the mark-to-markec method of accounting. In addition, our wholesale accrual revenues and fuel and The portion of competitive supply revenues, fuel and purchased energy expenses were impacted in 2002 by the purchased energy expenses, and gross margin derived from re-designation of our Texas and New England load-serving accrual and mark-to-market contracts changed significantly due activities to accrual.
to the adoption of EITF 02-3. Effective January 1, 2003, we In February 2002, we began to manage our Texas began to account for all non-derivative contracts on the accrual* load-serving activities as a physical delivery business separate basis, whereas we had accounted for these contracts on the from our trading activities and re-designated these activities as mark-to-market basis in 2002. We also began to recognize non-trading. After the change in designation, the results of our origination gains only for derivative contracts for which we have Texas load-serving activities are included in "Nonregulated observable market prices. These changes increased accrual revenues" on a gross basis as power is delivered to our customers competitive supply revenues, fuel and purchased energy expenses, and "Fuel and purchased energy expenses" as costs are incurred.
and gross margin and decreased mark-to-market competitive Prior to dte re-designation, the results of these activities were supply revenues and gross margin in 2003 as compared to 2002. reported on a net basis as part of mark-to-market revenues EITF 02-3 affected a large number of competitive supply included in "Nonregulated revenues." Mark-to-market revenues contracts, and we cannot quantify its total impact precisely for the Texas trading activities were a net loss of $1.2 million for because we cannot recast our 2002 results to reflect accrual the portion of 2002 prior to designation as non-trading.
accounting, nor did we maintain separate mark-to-market Since future power sales revenues and costs from these accounting records for accrual contracts beginning in 2003. activities are reflected in our Consolidated Statements of Income However, the larger portion of our competitive supply activities as part of "Nonregulated revenues" when power is delivered and that became subject to accrual accounting under EITF 02-3 "Fuel and purchased energy expenses" when the costs are resulted in an increase in total competitive supply revenues and incurred, this re-designation generally delays the recognition of fuel and purchased energy expenses, but a decrease in total earnings from these activities compared to what we would have competitive supply gross margin in 2003 compared to 2002. recognized under mark-to-market accounting. The change in We analyze our wholesale accrual and mark-to-market designation of our Texas load-serving activities did not impact competitive supply activities separately below. our cash flows.
In addition, our New England load-serving activities consist Wholesale Accnral Activities primarily of contracts to serve the full energy and capacity The increase in gross margin from our wholesale accrual requirements of retail customers and electric distribution utilities activities in 2004 compared to 2003 is primarily due to and associated power purchase agreements to supply our -
approximately $50 million in the New England region due to customers' requirements. We manage these activities primarily to higher realized contract margins in 2004 compared to 2003 and assure profitable delivery of customers' energy requirements higher volumes served. This increase was partially offset by rather than as a traditional proprietary trading activity where higher transportation costs for our gas trading portfolio of profits or losses result from taking directional positions on approximately $16 million. The transportation costs associated market price changes. Therefore, we use accrual accounting for with this portfolio are accounted for on an accrual basis, while New England load-serving transactions and associated power our gas trading portfolio is recorded as mark-to-market. In purchase agreements entered into since the second quarter of addition, we incurred higher operating costs of $5.0 million 2002.
related to our South Carolina synthetic fuel facility.
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Because applicable accounting rules significantly limited the Origination gains arise primarily from contracts that our circumstances under which contracts previously designated as a wholesale marketing and risk management operation structures trading activity could be re-designated as non-trading, prior to to meet the risk management needs of our customers.
EITF 02-3, we were requited to continue to include contracts Transactions that result in origination gains may be unique and entered into before the second quarter of 2002 in our provide the potential for individually significant revenues and mark-to-market accounting portfolio. However, under gains from a single transaction.
EITF 02-3, on January 1, 2003, we removed these contracts - Origination gains represent the initial fair value recognized from our "Mark-to-market energy assets and liabilities" and on these structured transactions. The recognition of origination began to account for these contracts under the accrual method gains is dependent on the existence of observable market data of accounting. that validates the initial fair value of the contract. Origination gains arose from 13 transactions completed in 2004 and 14 Mark-to-Market Revenues transactions completed in 2003, of which no transaction Mark-to-market revenues indude net gains and losses from individually contributed in excess of $10 million pre-tax.
origination and risk management activities for which we use the As noted on the previous page, the recognition of mark-to-market method of accounting. We discuss these origination gains is dependent on sufficient observable market activities and the mark-to-market method of accounting in more data. Liquidity and market conditions impact our ability to derail in the CriticalAccountingPolicies section and in Note 1. identify sufficient, objective market-price information to permit We also discuss the implications of EITF 02-3 on the recognition of origination gains. As a result, while our strategy mark-to-market method of accounting in the CriticalAccounting and competitive position provide the opportunity to continue to Policies section. originate such transactions, the level of origination revenue we As a result of the nature of our operations and the use of are able to recognize may vary from year to year as a result of mark-to-marker accounting for certain activities, mark-to-market the number, size, and market-price transparency of the revenues and earnings will fluctuate. We cannot predict these individual transactions executed in any period.
fluctuations, but the impact on our revenues and earnings could Risk management revenues represent both realized and be material. We discuss our 'market risk in more detail in the unrealized gains and losses from changes in the value of our Market Risk section. The primary factors that cause fluctuations entire portfolio, including the recognition of gains associated in our mark-to-market revenues and earnings are: with decreases in the close-out adjustment when we are able to
- the number, size, and profitability of new transactions obtain sufficient market price information. We discuss the including terminations or restructuring of existing changes in mark-to-market revenues below. We show the contracts, relationship between our revenues and the change in our net
- the number and size of our open derivative positions, mark-to-market energy asset later in this section.
and Our mark-to-market revenues were and continue to be
- changes in the level and volatility of forward commodity affected by a decrease in the portion of our activities that is prices and interest rates. - subject to mark-ro-market accounting. As previously discussed in Mark-to-market revenues were as follows: the Whoksale Accrual Activities section, we re-designated our Texas load-serving activities as accrual during 2002, and we 2004 2003 2002 began to account for new non-derivative origination transactions (in millions) on the accrual basis rather than under mark-to-market Unrealized revenues accounting. Beginning January 1, 2003, under EITh 02-3, we Origination gains $ 19.7 $ 62.3 $160.4 Risk management no longer record existing non-derivative contracts at fair value.
Unrealized changes in fair value 79.4 (26.1) 58.8 Further, effective July 1, 2002, to the extent that we are not able Changes in valuation techniques - - 10.8 to observe quoted market prices or other current market Reclassification of settled contracts transactions for contract values determined using models, we to realized (85.4) (123.5) (45.4) record a valuation adjustment to result in zero gain or loss at Total risk management (6.0) (149.6) 24.2 inception. We remove the valuation adjustment in determining Total unrealized revenues' 13.7 (87.3) .184.6 fair value when we obtain current market information for Realized revenues . 85.4 123.5 45.4 contracts with similar terms and counterparties.
Total mark-to-market revenues $ 99.1. $ 36.2 $230.0 Mark-to-market revenues increased $62.9 million in 2004
- Total unrealized revenues is the sum oforigination transactions compared to 2003 'mostly because of the impact of lower and total risk management. mark-to-market losses on economic hedges that do not qualify for hedge accounting treatment as discussed in more detail on the next page and lower losses from risk management activities primarily due to favorable changes in regional power prices, and price volatility. These increases were partially offset by a lower level 'of origination gains in 2004 compared to 2003. The lower level of origination gains is primarily due to higher individually significant gains on contracts in 2003 that had a positive impact in that period.
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Mark-to-market revenues decreased $193.8 million in 2003 The following are the primary sources of the change in net compared to 2002 mostly because of lower revenues from mark-to-market energy asset during 2004 and 2003:
origination transactions, net losses from risk management activities compared to net gains in the prior year, and the 2004 2003 reclassification of revenues from settled contracts to realized (in millions) revenues. The lower level of origination transactions primarily Fair value beginning of year $ 18.8 $516.6 Changes in fair value recorded as reflects the continuing reduction of the portion of our activities revenues subject to mark-to-market accounting. The decrease in risk Origination gains $ 62.3
$ 19.7 management revenues is primarily due to mark-to-market Unrealized changes in fair value 79.4 (26.1) revenue associated with the restructuring of our High Desert Changes in valuation techniques contract with the CDWR that had a positive impact in 2002,. Redassification of settled unfavorable changes in regional power prices, price volatility, and contracts to realized (85.4) (123.5) the impact of mark-to-marker losses on economic hedges that Total changes in fair value recorded did not qualify for hedge accounting treatment as discussed in as revenues 13.7 (87.3) more detail below. Cumulative effect impact of EITF With the implementation of EITF 02-3 in the first quarter 02-3 (379.4) of 2003, all of our load-serving contracts were converted to Contracts designated as normal accrual accounting. However, several economically effective purchases/sales and hedges upon implementation of EITF 02-3 (58.2) hedges on these positions did not qualify for accrual accounting Contract exchange (68.9) treatment under SFAS No. 133 and remained in the Changes in value of exchange-listed mark-to-market portfolio. In 2003, increasing forward prices futures and options (15.8) (8.4) shifted value between accrual load-serving positions and Net change in premiums on associated mark-to-market hedges producing a timing difference options 29.4 99.3 in the recognition of earnings on related transactions. As a Other changes in fair value 6.3 5.1 result, we recorded $0.3 million of pre-tax gains in 2004 and Fair value at end of year $ 52.4 $ 18.8
$47.4 million of pre-tax losses on the mark-to-market hedges during 2003. This mark-to-market loss will be offset as we Changes in the net mark-to-market energy asset that realize the related accrual load-serving positions in cash. affected revenues were as follows:
- Origination gains represent the initial unrealized fair value at the time these contracts are executed to the Mark-to-Market Energy Assets and Liabilities extent permitted by applicable accounting rules.
Our mark-to-market energy assets and liabilities are comprised of
- Unrealized changes in fair value represent unrealized derivative contracts. While some of our mark-co-market contracts changes in commodity prices, the volatility of options represent commodities or instruments for which prices are available from external sources, other commodities and certain on commodities, the time value of options, and other valuation adjustments.
contracts are not actively traded and are valued using other
- Changes in valuation techniques represent improvements pricing sources and modeling techniques to determine expected in estimation techniques, including modeling and other future market prices, contract quantities, or both. We discuss our statistical enhancements used to value our portfolio to.
modeling techniques later in this section.
Mark-to-market energy assets and liabilities consisted of the reflect more accurately the economic value of our contracts.
following:
- Reclassification of settled contracts to realized represents Al Decnmber 31, 2004 2003 the portion of previously unrealized amounts settled an millionm) during the period and recorded as realized revenues.
Current Assets $5673 $504.8 The net mark-to-market energy asset also changed due to Noncurrent Assets 359.8 265.8 the following items recorded in accounts other than revenue:
Total Assets 927.1 770.6
- The cumulative effect impact of EITF 02-3 represents the non-derivative portion of the net asset that was Current Liabilities 559.7 490.4 removed from our Consolidated Balance Sheets as a Noncurrent liabilities 315.0 26.4 cumulative effect of change in accounting principle Total Liabilities 874.7 751.8 effective January 1, 2003 as required by EITF 02-3.
Net mark-to-market energy asset $ 52.4 $ 18.8 Certainprior-year amounts have been rechassifiedto conform with the currentyear! presentation.
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- Contracts designated as normal purchases/sales and
- Changes in value of exchange-listed futures and options hedges upon implementation of EITF 02-3 represents are adjustments to remove unrealized revenue from the portion of the net asset reclassified to "Other assets exchange-traded contracts that are included in risk or liabilities" under the normal purchases/normal sales management revenues. The fair value of these contracts provisions of SFAS No. 133 or "Risk management assets is recorded in 'Accounts receivable" rather than or liabilities" under the cash-flow hedge provisions of "Mark-to-market energy assets" in our Consolidated SFAS No. 133 in connection with the implementation Balance Sheets because these amounts are settled of EITF 02-3 effective January 1, 2003. through our margin account with a third-party broker.
- Contract exchange represents the fair value of a contract
- Net changes in premiums on options reflects the previously included in "Mark-to-market energy assets" accounting for premiums on options purchased as an that we terminated in a nonmonetary exchange with a increase in the net mark-to-market energy asset and counterparty. At that time, we also terminated a hedge premiums on options sold as a decrease in the net contract with the same counterparty that was recorded mark-to-market energy asset.
in "Risk management liabilities." In exchange, we entered into a new cash-flow hedge transaction with the counterparty that we recorded at an amount equal to the fair value of the terminated contracts.
The settlement terms of our net mark-to-market energy asset and sources of fair value as of December 31, 2004 are as follows:
Settlement Term 2005 2006 2007 2008 2009 2010 Thereafter Fair Value (In nzillions)
Prices provided by external sources (1) $17.2 $29.5 $ 123.0 $ 61.6 $ $ $- $ 231.3 Prices based on models (9.6) (8.3) (101.7) (54.6) (I.5) (1.8) (1.4) (178.9)
Total net mark-to-market energy asset $ 7.6 $21.2 $ 21.3 $ 7.0 $(1.5) $(1.8) $(1.4) $ 52.4 (1) Includes contracts actively quoted and contracts valued from other external sources.
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). and off-peak hours for delivery terms primarily through Consistent with our risk management practices, we have 2006, but up to 2008, depending upon the region, presented the information in the table above based upon the
- options for the purchase and sale of electricity during ability to obtain reliable prices for components of the risks in peak hours for delivery terms through 2005, depending our contracts from external sources rather than on a upon the region, contract-by-contract basis. Thus, the portion of long-term
- forward purchases and sales of electric capacity for contracts that is valued using external price sources is presented delivery terms through 2006, under the caption "prices provided by external sources." This is
- forward purchases and sales of natural gas, coal and oil consistent with how we manage our risk, and we believe it for delivery terms through 2008, and provides the best indication of the basis for the valuation of our
- options for the purchase and sale of natural gas, coal portfolio. Since we manage our risk on a portfolio basis rather and oil for delivery terms through 2006.
than contract-by-contract, it is not practicable to determine The remainder of the net mark-to-market energy asset is separately the portion of long-term contracts that is included in valued using models. The portion of contracts for which such each valuation category. We describe the commodities, products, techniques are used includes standard products for which and delivery periods included in each valuation category in detail external prices are not available and customized products that are below. valued using modeling techniques to determine expected future market prices, contract quantities, or both.
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Modeling techniques include estimating the present value of Management uses its best estimates to determine the fair cash flows based upon underlying contractual terms and value of commodity and derivative contracts it holds and sells.
incorporate, where appropriate, option pricing models and These estimates consider various factors including closing statistical and simulation procedures. Inputs to the models exchange and over-the-counter price quotations, time value, include: volatility factors, and credit exposure. However, future market
- observable market prices, prices and actual quantities will vary from those used in
- estimated market prices in the absence of quoted market recording mark-to-market energy assets and liabilities, and it is prices, possible that such variations could be material.
- the risk-free market discount rate,
- volatility factors, Other
- estimated correlation of energy commodity prices, and 2004 2003 2002
- expected generation profiles of specific regions. (In millions)
Additionally, we incorporate counterparty-specific credit Revenues $73.6 $45.1 $56.4 quality and factors for market price and volatility uncertainty and other risks in our valuation. The inputs and factors used to Our merchant energy business holds up to a 50% voting interest determine fair value reflect management's best estimates. in 24 operating domestic energy projects that consist of electric The electricity, fuel, and other energy contracts we hold generation, fuel processing, or fuel handling facilities. Of these have varying terms to maturity, ranging from contracts for 24 projects, 17 are "qualifying facilities" that receive certain delivery the next hour to contracts with terms of ten years or exemptions and pricing under the Public Utility Regulatory more. Because an active, liquid electricity futures market Policy Act of 1978 based on the facilities' energy source or the comparable to that for other commodities has not developed, the use of a cogeneration process. Earnings from our investments majority of contracts used in the wholesale marketing and risk were $18.0 million in 2004, $2.1 million in 2003, and management operation are direct contracts between market $9.1 million in 2002.
participants and are not exchange-traded or financially settling The increase in revenues in 2004 compared to 2003 is contracts that can be readily liquidated in tleir entirety through primarily due to higher equity in earnings related to our an exchange or other market mechanism. Consequently, we and minority investment in a facility that produces synthetic fuel other market participants generally realize the value of these from coal. This increase included $13.1 million of revenues contracts as cash flows become due or payable under the terms related to an increased incentive fee and a deferred contingent of the contracts rather than through selling or liquidating the transaction fee.
contracts themselves.
- The decrease in revenues in 2003 compared to 2002 was Consistent with our risk management practices, the due to lower revenues from our California projects because we amounts shown in the table on the previous page as being reversed certain credit reserves that totaled $9.1 million during valued using prices from external sources include the portion of the first quarter of 2002, as we began receiving payments from long-term contracts for which we can obtain reliable prices from the California utilities, which had a positive impact in 2002, external sources. The remaining portions of these long-term partially offset by a geothermal project generating at a higher contracts are shown in the table as being valued using models. capacity in 2003.
In order to realize the entire value of a long-term contract in a At December 31, 2004, our investment in qualifying single transaction, we would need to sell or assign the entire facilities and domestic power projects consisted of the following:
contract. If we were to sell or assign any of our long-term contracts in their entirety, we may not realize the entire value Book Value at December 31, 2004 2003 reflected in the table. However, based upon the nature of the (In millions) wholesale marketing and risk management operation, we expect Project Type to realize the value of these contracts, as well as any contracts we Coal $128.7 $130.5 may enter into in the future to manage our risk, over time as Hydroelectric 55.8 57.3 the contracts and related hedges settle in accordance with their Geothermal 46.3 56.0 terms. We do not expect to realize the value of these contracts Biomass 50.2 51.4 and related hedges by selling or assigning the contracts Fuel Processing 22.5 22.5 themselves in total. Solar 10.4 10.5 The fair values in the table represent expected future cash Total $313.9 $328.2 flows based on the level of forward prices and volatility factors as of December 31, 2004 and could change significantly as a result of future changes in these factors. Additionally, because the depth and liquidity of the power markets vary substantially between regions and time periods, the prices used to determine fair value could be affected significantly by the volume of transactions executed.
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We believe the current market conditions for our equity- OperatingExpenser method investments that own geothermal, coal, hydroelectric, Our merchant energy business operating expenses increased and fuel processing projects provide sufficient positive cash flows $242.5 million in 2004 compared to 2003 mostly due to the to recover our investments. We continuously monitor issues that following potentially could impact future profitability of these investments,
- an increase of $94.3 million primarily related to higher including environmental and legislative initiatives. We discuss compensation, benefit, and other inflationary costs, certain risks and uncertainties in more detail in our Forward higher. Sarbanes-Oxley 404 implementation costs of Looking Statements section. However, should future events cause approximately $10 million, and higher spending on these investments to become uneconomic, our investments in enterprise-wide information technology infrastructure these projects could become impaired under the provisions of costs of approximately $5 million, APB No. 18.
- an increase at our competitive supply operations totaling The ability to recover our costs in our equity-method $90.1 million mostly because of higher compensation investments that own biomass and solar projects is partially and benefit expense, induding an increased number of dependent upon subsidies from the State of California. Under employees to support the growth of these operations, the California Public Utility Act, subsidies currently exist in that
- an increase in expenses due to the June 2004 acquisition the California Public Utilities Commission (CPUC) requires of Ginna totaling $43.1 million, and electric corporations to identify a separate rate component to
- an increase of $10.1 million at our Nine Mile Point fund the development of renewable resources technologies, nuclear facility primarily due to refueling outage and including solar, biomass, and wind facilities. In addition, reliability spending.
legislation in California requires that each electric corporation Our merchant energy business operating expenses increased increase its total procurement of eligible renewable energy $176.1 million in 2003 compared to 2002 mostly due to the resources by at least one percent per year so that 20% of its following:
retail sales are procured from eligible renewable energy resources
- an increase of $81.5 million due to the acquisitions of by 2017. The legislation also requires the California Energy our retail electric operation in September 2002 and Commission to award supplemental energy payments to electric retail gas operation in December 2002, corporations to cover above-market costs of renewable energy.
- an increase of $22.7 million at Nine Mile Point, Given the need for electric power and the desire for induding higher costs associated with the refueling renewable resource technologies, we believe California will outage of Unit I in 2003 compared to the 2002 continue to subsidize the use of renewable energy to make these refueling outage of Unit 2. Since we own 100% of projects economical to operate. However, should the California Unit 1, we incurred all outage costs compared to 82%
legislation fail to adequately support the renewable energy of costs for Unit 2, initiatives, our equity-method investments in these types of * -costs of $17.8 million related to our High Desert projects could become impaired under the provisions of APB facility that commenced operations in the second No. 18, and any losses recognized could be material. If our quarter of 2003, strategy were to change from an intent to hold to an intent to
- an increase in costs of $10.3 million related to our sell for any of our equity-method investments in qualifying wholesale marketing and risk management operation as facilities or power projects, we would need to adjust their book a result of growth of this operation, and value to fair value, and that adjustment could be material. If we
- higher compensation, benefit, and other inflationary were to sell these investments in the current market, we may costs.
have losses that could be material. These increases were partially offset by cost reductions due to productivity initiatives induding our corporate-wide workforce reduction programs.
-Worforre Reduction Costs, Impairment Losses and Other Costs, and Net Loss on Saks ofAssets Our merchant energy business recognized expenses associated with our loss on discontinued operations, workforce reduction efforts, impairment losses and other costs, and a net loss on sales of assets as discussed in more detail in Note 2.
41
Depreciation andAmortization Expense Regulated Electric Business Merchant energy depreciation and amortization expense Our regulated electric business is discussed in detail in Item 1.
increased $18.5 million in 2004 compared to 2003 mostly Business-ElectricBusiness section.
because of $10.3 million of depreciation and amortization at Ginna which was acquired in June 2004 and $5.1 million Results related to our South Carolina synthetic fuel facility which was 2004 2003 2002 acquired in May 2003. (In millions)
Merchant energy depreciation and amortization expense Revenues $ 1,967.7 $ 1,921.6 $ 1,966.0 decreased $13.3 million in 2003 compared to 2002 mostly Electricity purchased for resale expenses (1,034.0) (1,023.5) (1,080.7) because of the adoption of SFAS No. 143. Under SFAS Operations and No. 143, a portion of the decommissioning amortization is maintenance expenses (304.2) (305.1) (260.4) included as 'Accretion of asset retirement obligations" expense 'Workforce reduction costs - (0.6) (34.0) beginning in 2003. In addition, beginning in 2003 we no longer Depreciation and amortization (194.2) (181.7) (174.2) include the expected net future costs of removal as a component Taxes other than income of depreciation expense. These decreases were partially offset by taxes - (132.8) (130.2) (129.0) higher depreciation expense related to new generating facilities Income from Operations $ 302.5 $ 280.5 $ 287.7 that commenced operations in mid-2002 and High Desert that Net Income $ 131.1 $ 107.5 $ 99.3 commenced operations in 2003.
Special Items Included in Operations (afrer-tax)
Workforce reduction Accretion of Asset Retirement Obligations costs $ - $ (0.4) $ (20.5)
On January 1, 2003, we adopted SFAS No. 143 that requires the accretion of the asset retirement obligation liability due to Abotve amounts include intercompany transactions eliminated in our the passage of time until the liability is settled. The increase in ConsolidatedFinancialStatements. Note 3 provides a reconciliation accretion expense of $10.5 million in 2004 compared to 2003 is of operatingresults by segment to our Consolidated Financial primarily due to $6.9 million related to Ginna which was Statements. Certain prior-yearamounts haie been reclassifiedto acquired in June 2004. conform wit/i the currentyearspresentation.
Net income from the regulated electric business increased in Taxes Other Than Income Taxes 2004 compared to 2003 mostly because of:
Merchant energy taxes other than income taxes increased
- increased revenues less electricity purchased for resale
$2.3 million in 2004 compared to 2003 mostly because of expenses of $21.5 million after-tax in 2004 compared to
$4.2 million of property taxes at Ginna which was acquired in 2003, which includes $6.0 million after-tax related to June 2004, partially offset by lower property taxes at Nine Mile the shareholder return portion of the administrative fee Point. collected under Provider of last Resort rates, Merchant energy taxes other than income taxes increased
- the absence of $19.4 million after-tax of incremental
$19.5 million in 2003 compared to 2002 mostly because of distribution service restoration expenses associated with gross receipt taxes associated with our retail electric operation of Hurricane Isabel in 2003, and
$17.5 million and property taxes on new generating facilities.
- lower interest expense of $10.0 million after-tax.
These favorable results were partially offset by the following:
- excluding the costs associated with Hurricane Isabel, we had increased operations and maintenance expenses'of
$18.9 million after-tax in 2004 compared to 2003 mostly due to higher compensation, benefit, and other inflationary costs, higher uncollectible expenses, Sarbanes-Oxley 404 implementation costs, and increased spending on electric system reliability, and
- increased depreciation and amortization expense of
$7.6 million after-tax.
Net income from the regulated electric business increased in 2003 compared to 2002 mostly because of:
- lower workforce reduction costs of $20.1 million after-tax, lower interest expense of $19.1 million after-tax, and
- cost reductions resulting from our corporate-wide workforce reduction programs and other productivity initiatives.
42
- These favorable results were partially offset by distribution 2002 and elected other electric generation suppliers. In 2003, service restoration expenses related to Hurricane Isabel and other these decreased revenues were partially offset by an increase in major storms in 2003. Total distribution service restoration the standard offer service rate that BGE charges its customers.
expenses related to Hurricane Isabel were $22.2 million after-tax, which included $19.4 million of incremental expenses. Ekctricicy Purchusedfor Resak E:penses BGE's actual costs of electricity purchased for resale expenses Electric Revenues increased in 2004 compared to 2003 mostly due to increased The changes in electric revenues in 2004 and 2003 compared to sales to residential customers, partially offset by lower electricity the respective prior year were caused by: purchased for resale expenses associated with commercial and industrial customers that elected an alternative supplier 2004 2003 beginning July 1, 2004. Electricity purclased for resale expenses (In millions) decreased in 2003 compared to 2002 mostly because large Distribution volumes $15.8 $ 3.0 commercial and industrial customers left BGE's standard offer Standard offer service 26.6 (54.2) service in the second quarter of 2002 and elected other electric Total change in electric revenues from electric generation suppliers.
system sales 42.4 (51.2)
Other 3.7 6.8 Electric Operations and MaintenanceExpenses Total change in electric revenues $46.1 $(44.4) Regulated electric operations and maintenance expenses were about the same in 2004 compared to 2003. Hurricane Isabel Distribution Volumes caused $32.1 million of incremental distribution service Distribution volumes are sales to customers in BGE's service restoration expenses in 2003. Other operations and maintenance territory for the delivery service BGE provides at rates set by the expenses increased $31.2 million in 2004 compared to 2003.
Maryland PSC. This increase was mostly due to:
The percentage changes in our electric system distribution
- an increase in compensation, benefit, and other volumes, by type of customer, in 2004 and 2003 compared to inflationary costs, the respective prior year were:
- a $9.0 million increase in uncollectible expenses,
- approximately $4 million related to Sarbanes-Oxiry 404 2004 2003 implementation costs, and Residential
- approximately $4 million in spending on electric systems 4.4% 0.8%
reliability.
Commercial 0.9 2.1 Industrial (8.0) Regulated electric operations and maintenance expenses (3.0) increased $44.7 million in 2003 compared to 2002 mostly In 2004, we distributed more electricity to residential because of distribution service restoration expenses related to customers compared to 2003 mostly due to increased usage per Hurricane Isabel of $36.8 million, which includes $4.7 million customer, an increased number of customers, and warmer of non-incremental labor expenses, and distribution service summer weather. We distributed about the same amount of restoration expenses related to other major storms. This increase electricity to commercial customers. We distributed less also refleas higher compensation, benefit, and other inflationary electricity to industrial customers mostly due to lower usage by costs, partially offset by lower uncollectible expenses and cost industrial customers. reductions resulting from our corporate-wide workforce In 2003, we distributed about the same amount of reduction programs and other productivity initiatives.
electricity to residential customers compared to 2002. We distributed more electricity to commercial customers mostly due Workforce Reduction Costs to increased usage per customer. We distributed less electricity to BGE's electric business recognized expenses associated with our industrial customers mostly due to lower usage by industrial workforce reduction efforts as discussed in Note 2.
customers.
Electric Depreciation andAmortization Evpense StandardOffer Service Regulated electric depreciation and amortization expense BGE provides standard offer service for customers that do not increased $12.5 million in 2004 compared to 2003 mostly select an alternative generation supplier as discussed in Item 1. because of $7.6 million related to accelerated amortization Business-Electric Regulatory Matters and Competition section. expense associated with the replacement of information Standard offer service revenues increased in 2004 compared technology assets and $4.9 million related to additional property to 2003 mostly because of increased distribution volumes to placed in service.
residential customers, partially offset by lower revenues associated Regulated electric depredation and amortization expense with commercial and industrial customers that elected an increased $7.5 million in 2003 compared to 2002 mostly alternative supplier beginning July 1, 2004. Standard offer because of accelerated amortization associated with the service revenues decreased in 2003 compared to 2002 mostly replacement of information technology assets.
because a majority of BGEs large commercial and industrial customers left standard offer service in the second quarter of 43
Regulated Gas Business Gas Revenues All BGE customers have the option to purchase gas from other The changes in gas revenues in 2004 and 2003 compared to the suppliers. To date, customer choice has not had a material effect respective prior year were caused by.
on our, or BGE's, financial results.
2004 2003 Results (In millions) 2004 2003 2002 Distribution volumes $ (7.2) $ 21.6 (In millions) Base rates (0.1) (1.3)
Revenues $ 757.0 $ 726.0 $ 581.3 Weather normalization 5.4 (18.9)
Gas purchased for resale Gas cost adjustments 40.5 132.4 expenses (484.3) (445.8) (316.7)
Total change in gas revenues from gas system Operations and maintenance
- sales 38.6 133.8 expenses (123.6) (101.1) (106.2)
Off-system sales (7.6) 10.0 Workforce reduction costs - (0.1) (1.3)
Other - 0.9 Depreciation and amortization (48.1) (46.6) (47.4)
Taxes other than income taxes (32.1) (27.9) (31.1) Total change in gas revenues $31.0 S144.7 Income from Operations $ 68.9 $ 104.5 S 78.6 Distribution Volumes Net Income $ 22.2 $ 43.0 $ 31.1 The percentage changes in our distribution volumes, by type of Special Items Included in Operations (after-ttax) customer, in 2004 and 2003 compared to the respective prior Workforce reduction costs $ - $ (0.1) $ (0.8) year were:
Above amounts include intercompany transactions eliminated in our Consolidated FinancialStatements. Note 3 provides a reconciliation 2004 2003 of operating results by segment to our ConsolidatedFinancial Residential (5.1)% 13.8%
Statements. Certainprior-year amounts have been reclassified to Commercial 10.1 7.6 conform with the currentyeart presentation. Industrial (22.3) (21.5)
Net income from our regulated gas business decreased during We distributed less gas to residential customers during 2004 2004 compared to 2003 mostly because of: compared to 2003 mostly due to milder winter weather and
- increased operations and maintenance expenses of lower usage per customer. We distributed more gas to
$13.6 million after-tax mostly due to increased commercial customers mostly due to increased usage and an compensation, benefit, and other inflationary costs, increased number of customers. We distributed less gas to higher uncollectible expenses, and Sarbanes-Oxley 404 industrial customers mostly due to lower usage per customer.
implementation costs, We distributed more gas to residential and commercial
- the absence of a $4.7 million after-tax recovery of a customers during 2003 compared to 2002 mostly due to colder previously disallowed regulatory asset following an order winter weather, an increased number of customers, and increased issued by the Maryland PSC that had a positive impact usage per customer. We distributed less gas to industrial in 2003, and customers mostly due to decreased usage per customer.
- the absence of $2.2 million after-tax of property tax refund claims by the State of Maryland resulting from a Weather Normalization reclassification of gas distribution pipeline from real The Maryland PSC allows us to record a monthly adjustment to property to personal property that had a positive impact our gas distribution revenues to eliminate the effect of abnormal in 2003. weather patterns on our gas distribution volumes. This means Net income from our regulated gas business increased our monthly gas distribution revenues are based on weather that during 2003 compared to 2002 mostly because of. is considered "normal" for the month and, therefore, are not
-* a $4.7 million after-tax recovery of a previously affected by actual weather conditions.
disallowed regulatory asset following an order issued by the Maryland PSC, and Gas Cost Adjustments
- the approval of $2.2 million after-tax of property tax We charge our gas customers for the natural gas they purchase refund claims by the State of Maryland resulting from a from us using gas cost adjustment dauses set by the Maryland reclassification of gas distribution pipeline from real PSC as described in Note 1. However, under the market-based property to personal property- rates mechanism approved by the Maryland PSC, our actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between our actual cost and the market index is shared equally between shareholders and customers.
44
Customers who do not purchase gas from BGE are not Gas PurchasedFor Resale Expenses subject to the gas cost adjustment clauses because we are not Gas purchased for resale expenses include the cost of gas selling gas to them. However, these customers are charged base purchased for resale to our customers and for off-system sales.
rates to recover the costs BGE incurs to deliver their gas through These costs do not include the cost of gas purchased by delivery our distribution system, and are included in the gas distribution service only customers.
volume revenues. Gas costs increased during 2004 as compared to 2003 Gas cost adjustment revenues increased during 2004 mostly because of higher average gas prices and the $7.7 million compared to 2003 because we sold gas at a higher price partially recovery of disallowed fuel-related costs recognized in 2003 that offset by less gas sold. Gas cost adjustment revenues increased had a positive impact in that period as previously discussed in during 2003 compared to 2002 because we sold more gas at a the Gas Cost Adjustments section.
higher price. Gas costs increased during 2003 as compared to 2002 In December 2002, a Hearing Examiner from the mostly because we purchased more gas at a higher price.
Maryland PSC issued a proposed order disallowing $7.7 million of a previously established regulatory asset for certain credits that Gas Operations andMaintenance Expenses were over-refunded to customers through our market-based rates. Regulated gas operations and maintenance expenses increased BGE reserved the $7.7 million of disallowed fuel costs in the $22.5 million during 2004 compared to 2003 mostly because of-fourth quarter of 2002. In August 2003, the Maryland PSC
- an increase in compensation, benefit, and other issued an order authorizing us to recover the $7.7 million and - inflationary expenses, we reinstated the regulatory asset.
- a $5.4 million increase in uncollectible expenses, and
- approximately $1 million related to Sarbanes-Oxley 404 Off-System Sales implementation costs.
Off-system gas sales are low-margin direct sales of gas to -Regulated gas operations and maintenance expenses wholesale suppliers of natural gas outside our service territory. decreased $5.1 million during 2003 compared to 2002 mostly Off-system gas sales, which occur after BGE satisfied its because of lower uncollectible expenses and cost reductions customers' demand, are not subject to gas cost adjustments. The resulting from our corporate-wide workforce reduction programs Maryland PSC approved an arrangement for part of the margin and other productivity initiatives.
from off-system sales to benefit customers (through reduced costs) and the remainder to be retained by BGE (which benefits Workforce Reduction Costs shareholders). Changes in off-system sales do not significantly BGE's gas business recognized expenses associated with our impact earnings. workforce reduction efforts as discussed in Note 2.
Revenues from off-system gas sales decreased during 2004 compared to 2003 mostly because of less gas sold.
Revenues from off-system gas sales increased during 2003 compared to 2002 because we sold gas at a higher price, partially offset by less gas sold.
45
Other Nonregulated Businesses
- a $9.5 million pre-tax charge associated with the exit of Results BGE Home merchandise stores in 2002 which had a 2004 2003 2002 negative impact in that period,
- a $7.2 million pre-tax gain on the sale of an oil tanker (In millions)
Revenues $ 422.0 $ 587.9 $ 537.4 to the U.S. Navy, Operating expenses (353.4) (535.8) (505.9) * *a $5.3 million pre-tax gain on the favorable settlement Workforce reduction costs - (0.2) (1.0) of a contingent obligation we had previously reserved Impairment losses and other costs (3.7) (0.6) (10.8) relating to the sale of our Guatemalan power plant Depreciation and amortization (35.2) (21.2) (16.6) operation in the fourth quarter of 2001, Taxes other than income taxes (2.5) (3.3) (4.3)
- a $0.6 million pre-tax gain on the sale of financial Net (loss) gain on sales of investrents investments, and and odier assets (1.2) 26.2 265.0
- improved results from our international portfolio.
Income from Operations $ 26.0 $ 53.0 $ 263.8 In 2001, we decided to sell certain non-core assets and Net (Loss) Income - $ (3.5) $ 12.2 $ 148.0 accelerate the exit strategies on other assets that we continued to hold and own. These assets included approximately 1,300 acres Special Items Included In Operations (after-tax) of land holdings in various stages of development located in Impairment of real estate, senior-living, and other investments $ (2.2) $ (0.4) $ (1.2) seven sites in the central Maryland region, an operating waste Net (loss) gain on sales of water treatment plant located in Anne Arundel County, investments and other assets (0.6) 16.4 169.1 Maryland, all of our 18 senior-living facilities and certain Workforce reduction costs - (0.1) - (0.7) international power projects. At December 31, 2004, our Costs associated with exit of BGE remaining land holdings totaled approximately 190 acres with a Home merchandise stores - - (6.1) carrying value of approximately $29 million recorded in our Total Special Items S (2.8) $ 15.9 $ 161.1 Consolidated Balance Sheets. We also initiated a liquidation program for our financial investments operation in 2001. As of Above amounts include intercompany transactionseliminated in our December 31, 2004, we have substantially liquidated our Consolidated FinancialStatements. Note 3 provides a reconciliation investment portfolio and have approximately $6 million in of operatingresults by segment to our ConsolidatedFinancial non-core financial investments recorded in our Consolidated Statements.
Balance Sheets.
Net income from our other nonregulated businesses decreased In .2005, we began to market our Panamanian distribution
$15.7 million during 2004 compared to 2003 mostly because of facility and our investment in a fund that owns interests in two a $16.4 million net gain on sales of investments and other assets South American energy projects, with an expectation of in 2003 that had a positive impact in that period. completing a sale by the end of the year. We do not expect that Net income from our other nonregulated businesses the sale of these assets will have a material impact on our decreased $135.8 million during 2003 compared to 2002 mostly financial results.
because we recognized a $163.3 million after-tax gain on the sale 'While our intent is to dispose of these remaining non-core of our investment in Orion in 2002 that had a positive impaca assets, market conditions and other events beyond our control in that period. This decrease was partially offset by the following may affect the actual sale of these assets. In addition, a future 2003 transactions: dedine in the fair value of these assets could result in losses that
- a $13.1 million pre-tax gain on the sale of several could have a material impact on our financial results.
parcels of real estate, 46
Consolidated Nonoperating Income and Expenses Income Taxes Other Income The differences in income taxes result from a combination of Other income decreased $5.0 million during 2004 as compared the changes in income and the impact of the recognition of tax to 2003 mostly because of higher earnings from consolidated credits on the effective tax rate. We include an analysis of the investments where our ownership is less than 100%, which changes in the effective tax rate and discuss in more detail the resulted in increased minority interest expense. Other income tax-credits related to our South Carolina synthetic fuel facility in decreased $11.4 million during 2003 as compared to 2002 Note 10.
mostly because of lower interest income on temporary cash investments of $6.1 million and higher earnings from Pension Expense consolidated investments where our ownership is less than Our actual return on our qualified pension plan assets was 100%, which resulted in increased minority interest expense of 11.6% for the year ended December 31, 2004. We assume an
$4.0 million. expected return on pension plan assets of 9% for the purpose of Other income for BGE decreased $16.1 million in 2003 as computing annual net periodic pension expense in accordance compared to 2002 mostly because of an increase in charitable with SFAS No. 87, Employers'Accountingfinr Pensions. Differences contributions of $7.5 million and because of lower interest between actual and expected returns are deferred along with income of $5.0 million on temporary cash investments in the other actuarial gains and losses and reflected in future net Constellation Energy cash pool. periodic pension expense in accordance with SFAS No. 87.
Expected and actual returns on pension assets also are affected Fixed Charges by plan contributions.
Total fixed charges decreased $9.9 million during 2004 as We contributed an additional $50 million to our pension compared to 2003 mostly because of.a lower level of debt plans in March 2005, even though there is no IRS minimum outstanding and the benefit of lower interest rates due to interest contribution for 2005. At December 31, 2004, we recorded an rate swaps entered into during the third quarter of 2004. We after-tax charge to equity of $42.6 million as a result of discuss these interest rate swaps in more detail in Note 13. increasing our additional minimum pension liability. We discuss Total fixed charges increased $58.7 million during 2003 our pension plans in more detail in Note 7.
compared to 2002 mostly because we had lower capitalized interest of $30.2 million due to our new generating facilities commencing operations and $28.5 million related to a higher level of debt outstanding, including the issuance of $550 million of debt in June 2003 that was used to refinance the High Desert facility lease.
Total fixed charges for BGE decreased $15.0 million during 2004 compared to 2003 mostly because of a lower level of debt outstanding. Total fixed charges for BGE decreased
$29.4 million during 2003 compared to 2002 mostly because of a lower level of debt outstanding and lower interest rates.
47
Financial Condition Cash Flows The following table summarizes our 2004 cash flows by business segment, as well as our consolidated cash flows for 2004, 2003, and 2002.
2004 Segment Cash Flows Consolidated Cash Flows Merchant Regulated Other 2004 2003 2002 (in millions)
Operating Activities Net Income $ 389.9 $ 153.3 $ (3.5) $ 539.7 $ 277.3 $ 525.6 Non-cash adjustments to net income 592.9 293.1 44.3 930.3 959.5 616.0 Changes in working capital . (318.8) (43.1) 32.3 (329.6) (65.3) 49.0 Pension and postemployment benefits* (3.0)- (69.4) (116.2)
Other (41.2) (28.0) 18.6 (50.6) (44.3) (68.6)
Net cash provided by operating aaivities 622.8 375.3 91.7 1,086.8 1,057.8 1,005.8 Investing activities Investments in property, plant and equipment (428.3) (242.1) (33.2) (703.6) (635.7) (817.7)
Acquisitions, net of cash acquired (457.3) - _ (457.3) (546.6) (221.4)
Contributions to nuclear decommissioning trust funds (22.0) _ - (22.0) (13.2) (17.6)
Net proceeds from sale of discontinued operations 72.7 72.7 - -
Sale of investments and other assets 0.1 4.9 31.1 36.1 148.8 838.0 Other investments - . (86.1) - 7.5 (78.6) (113.6) (86.9)
Net cash (used in) provided by investing activities :(920.9) (237.2) 5.4 (1,152.7) (1,160.3) (305.6)
Cash flows from operating activities less cash flows from investing activities $(298.1) $ 138.1 $ 97.1 (65.9) (102.5) 700.2 Financing Activities Net (repayment) issuance of debt* * (152.8) 274.9 (62.9)
Proceeds from issuance of common stock' 293.9 95.4 28.5 Common stock dividends paid' (189.7) (169.2) (137.8)
Other" 99.5 7.7 14.6 Net cash provided by (used in) financing activities 50.9 208.8 (157.6)
Net (Decrease) Increase in Cash and Cash Equivalents $ (15.0) $ 106.3 $ 542.6 Items are not allocated to the business segments because they are managed for the company as a whol Cash Flowrsfrom Operating Actirities
- a decrease in the net gain on sales of investments and Cash provided by operating activities was $1,086.8 million in other assets of $27 million primarily due to the sale of 2004 compared to $1,057.8 million in 2003 and financial and real estate investments in 2003. We adjust
$1,005.8 million in 2002. Net income was higher by net income to exclude these gains and reflect the
$262.4 million in 2004 compared to 2003. Non-cash proceeds from these sales in the investing activities adjustments to net income were $29.2 million lower in 2004 section.
compared to 2003. The decrease in non-cash adjustments to net Changes in working capital had a negative impact of income was primarily due to the cumulative effects of changes in $329.6 million on cash flow from operations in 2004 compared accounting principles of $198.4 million as a result of the to a negative impact of $65.3 million in 2003. The adoption of SPAS No. 143 and EITF 02-3 in 2003, which had $264.3 million decrease was primarily due to the following uses the effect of reducing net income in 2003 but were non-cash of cash in 2004 compared to 2003:
transactions. This decrease in non-cash adjustments to net
- a decline in working capital related to accrued taxes of income was offset in part by the following increases in non-cash approximately $254 million in 2004 compared to 2003 adjustments in 2004: due to higher income tax payments in 2004 compared
- higher depreciation and amortization and accretion of to refunds of taxes in 2003 and due to the timing of.
asset retirement obligations of $60 million, income tax accruals in 2004 compared to 2003,
- the loss from discontinued operations of $49 million,
- a $77 million unfavorable change in working capital
- an increase in deferred income taxes of $14 million, and relating to our accounts receivable and accounts payable primarily due to increased volumes associated with our merchant energy business and the termination of an accounts receivable securitization program in 2004, and 48
- an unfavorable change of approximately $49 million property, plant and equipment and a decrease in cash proceeds relating to fuel stocks during 2004 primarily due to from the sale of investments and other assets in 2004 compared higher gas and coal prices, which affected inventory to 2003.
levels at BGE and our merchant energy business. The $854.7 million increase in cash used in investing These items were partially offset by a $111 million source activities in 2003 compared to 2002 was primarily due to a of cash in 2004 compared to 2003 primarily due to other decrease in cash proceeds from the sales of investments and favorable working capital changes as a result of higher accrued other assets in 2003 because of the sale of Orion and Corporate expenses in 2004 compared to 2003. Office Properry Trust that generated $555.4 million in 2002.
Cash provided by operating activities was $1,057.8 million W'e discuss our sale of Orion in Note 2. In addition, acquisitions in 2003 compared to $1,005.8 million in 2002. Non-cash were $325.2 million higher in 2003 due to the refinancing of adjustments to net income were $343.5 million higher in 2003 the High Desert lease, partially offset by a decline in other compared to 2002. The increase in non-cash adjustments to net acquisitions from 2002.
income was primarily due to the following:
- cumulative effects of changes in accounting principles of Cash Flowsfrom FinancingActivities
$198.4 million as a result of the adoption of SFAS Cash provided by financing activities was $50.9 million in 2004 No. 143 and EITF 02-3 in 2003, which had the effect compared to $208.8 million in 2003. The decrease in 2004 of reducing net income but were non-cash transactions, compared to 2003 was mostly due to a lower issuance of net and debt in 2004 (gross proceeds less debt repayments), partially
- a decrease in the net gain on sales of investments and offset by higher proceeds from common stock issuances and other assets of $235.1 million primarily due to the sale acquired contracts in 2004. We discuss cash flows from customer of our investment in Orion in 2002. contract restructurings in more detail below.
These increases in non-cash adjustments to net income Cash provided by financing activities increased were offset in part by lower accruals for workforce reduction $366.4 million in 2003 compared to 2002 mostly due to higher costs of $60.7 million in 2003 compared to 2002. net issuances of debt in 2003 compared to 2002.
Changes in working capital had a negative impact of
$65.3 million on cash flow from operations in 2003 compared Cash Flows from Customer Contract Restructurings to a positive impact of $49.0 million in 2002. The During 2004, our merchant energy business entered into several
$114.3 million decrease was primarily due to the following uses power agreements to help customers restructure their businesses, of cash in 2003 compared to 2002: which generate significant cash flows at the inception of the
- an increase in cash in 2002 due to the collection of contracts. These agreements have a contract price that differs approximately $85 million related to prepaid expenses from current market prices, which results in cash payments from and collateral at our retail electric operation subsequent the counterparry at the inception of the contract. We received to our acquisition, $117.5 million in 2004 for one contract reflected in cash flows
- a decline in accrued interest of approximately from financing activities in our Consolidated Statements of Cash
$50 million in 2003 compared to 2002 due to a shift in Flows. We received an additional $157.2 million for a second the timing of interest payments as a result of financings contract in March 2005. WXVe expect to receive approximately in 2002, $70 million in the first half of 2005 for another contract that
- an increase of approximately $40 million in fuel stocks was entered into during 2004, contingent upon the receipt of all and materials and supplies during 2003 primarily due to regulatory and other approvals and the dosing of the higher gas prices, which affected BGE's inventory levels, transaction.
and
- an increase of approximately $54 million in our Security Ratings accounts receivable balance primarily related to our Independent credit-rating agencies rate Constellation Energys merchant energy business as a result of increased and BGE's fixed-income securities. The ratings indicate the business and High Desert commencing operations in agencies' assessment of each company's ability to pay interest, 2003. distributions, dividends, and principal on these securities. These These items were partially offset by a source of cash in ratings affea how much it will cost each company to sell these 2003 compared to 2002 due to an increase in accrued income securities. The better the rating, the lower the cost of the taxes. securities to each company when they sell them.
The factors that credit rating agencies consider in CWb Flows fiom Investing Activities establishing Constellation Energy's and BGE's credit ratings Cash used in investing activities was $1,152.7 million in 2004 include, but are not limited to, cash flows, liquidity, business compared to $1,160.3 million in 2003 and $305.6 million in risk profile, and the amount of debt as a component of total 2002. Cash used in investing activities in 2004 was about the capitalization. In March 2004, Standard & Poors rating group same as in 2003 primarily due to the decrease in cash used for reduced Constellation Energy's and BGE's corporate credit rating acquisitions and proceeds from the sale of discontinued from A- to BBB+ and reduced certain other ratings to the levels operations in 2004, substantially offsetting increased spending on noted in the table on the next page. In October 2004, Fitch-49
Ratings affirmed Constellation Energy's and BGE's credit ratings. We expect to fund future acquisitions with an overall goal All Constellation Energy and BGE credit ratings have stable ' of maintaining a strong investment grade credit profile. We outlooks. At the date of this report, our credit ratings were as funded our June 2004 acquisition of Ginna with a mix of cash follows: -_and equity. On July 1, 2004, we issued 6.0 million shares of Standard common stock for net proceeds of $226.9 million to fund a
& Poors Moody's portion of the acquisition of Ginna. We discuss our acquisition Rating Investors Fitch- of Ginna in more detail in Note 15.
Group Service Ratings Constellation Energy BGE Commercial Paper A-2 P-2 F-2 During 2004, certain credit facilities expired and BGE renewed Senior Unsecured Debt* BBB Baal A- those facilities. BGE continues to maintain $200.0 million in BGE annual committed credit facilities, expiring May through Commercial Paper A-2 P-i F-I November 2005, to ensure adequate liquidity to support its Mortgage Bonds A Al A+' operations. We can borrow directly from the banks or use the Senior Unsecured Debt BBB+ A2 A facilities to allow commercial paper to be issued; As of Trust Preferred Securities* BBB- A3 A- December 31, 2004, BGE had no outstanding commercial Preference Stock* BBB- BaaI A- paper, which results in $200.0 million in unused credit facilities.
In March 2004f, Standard & Poors rating group reduced the rating one level to this current rating. Other NonreguLated Businesses BGE Home Products & Services' program to sell up to Available Sources of Funding $50 million of receivables was not extended beyond the We continuously monitor our liquidity requirements and believe March 2004 expiration date. During 2004, this receivables that our credit facilities and access to the capital markets provide program was fully liquidated.
sufficient liquidity to meet our business requirements. We If we can get a reasonable value for our remaining real discuss our available sources of funding in more detail below. estate projects and other investments, additional cash may be obtained by selling them. Our ability to sell or liquidate assets Constellation EneryW will depend on market conditions, and we cannot give In addition to our cash balance, we have a commercial paper assurances that these sales or liquidations could be made.
program under which we can issue short-term notes to fund our subsidiaries. At December 31, 2004, we had approximately Capital Resources
$2.2 billion of credit under several facilities. Our actual consolidated capital requirements for the years 2002 In June 2004, Constellation Energy arranged an through 2004, along with the estimated annual amount for
$800.0 million three-year revolving credit facility and a 2005, are shown in the table on the next page.
$300.0 million five-year revolving credit facility replacing a We will continue to have cash requirements for:
$447.5 million 364-day revolving credit facility, which expired in
- working capital needs, the second quarter of 2004. We also have an existing
- payments of interest, distributions, and dividends,
$640 million revolving credit facility expiring in June 2005 and
- capital expenditures, and a $447.5 million facility expiring in June 2006.
- the retirement of debt and redemption of preference We use these facilities to ensure adequate liquidity to stock.
support our operations. We can borrow directly from the banks Capital requirements for 2005 and 2006 include estimates or use the facilities to allow the issuance of commercial paper. of spending for existing and anticipated projects. We Additionally, we use the multi-year facilities to support letters of continuously review and modify those estimates. Actual credit primarily for our merchant energy business. requirements may vary from the estimates included in the table These revolving credit facilities allow the issuance of letters': on the next page because of a number of factors including:
of credit up to approximately $2.2 billion. In addition, BGE ' regulation, legislation, and competition, maintains $200.0 million in credit facilities as discussed below.
- BGE load requirements, At December 31, 2004, letters of credit that totaled
- environmental protection standards,
$809.9 million were issued under all of our facilities. - the type and number of projects selected for In October 2004, we terminated certain loans under-other construction or acquisition, revolving credit agreements of $41.4 million related to our
- the effect of market conditions on those projects, Panamanian distribution facility. We replaced these revolving
- the cost and availability of capital, credit agreements with loans under new revolving credit
- the availability of cash from operations, and agreements totaling $100.0 million.
- business decisions to invest in capital projects.
50
Our estimates are also subject to additional factors. Please
- upstream gas investments, see the ForwardLooking Statements section. - portfolio acquisitions and other investments,
- costs of complying with the Environmental Protection 2002 2003 2004 2005 Agency (EPA), Maryland, and Pennsylvania nitrogen' oxides (NOx) and sulfur dioxide (SO 2) emissions (In millions) regulations, and Nonregulated Capital Requirements:
- enhancements to our information technology Merchant energy (excludes infrastructure.
acquisitions)
Construction program $122 $- $ $
Generation plants 236 175(A)182 180 Regulated Electric and Gas Nuclear fuel 122 59 133 125 Regulated electric and gas construction expenditures primarily Environmental controls 66 12 - -5 include new business construction needs and improvements to Portfolio acquisitions/investments 51 51 11 140 existing facilities, including projects to improve reliability.
Technology/other 44 122 129 125 Capital requirements for 2003 in the table above include
$32.0 million in costs incurred as a result of Hurricane Isabel to Total merchant energy capital restore the electric distribution system.
requirements 641 419 455 575 Other nonregulated capital Funding for Capital Requirements requirements 65 53 42 35 Merchant Energy Business Total nonregulated capital Funding for the expansion of our merchant energy business is requirements 706 472 497 610 expected from internally generated funds. We also have available Regulated Capital Requirements: sources from commercial paper issuances, issuances of long-term Regulated electric 167 236 209 250 debt and equity, leases, and other financing activities.
Regulated gas 50 53 *56 55 The projects that our merchant energy business develops typically require substantial capital investment. Many of the Total regulated capital requirements 217 289 265 305 qutalifying facilities and independent power projects that-we have Total capital requirements $923 $761 $762 $915 an interest in are financed primarily with non-recourse debt that is repaid from the project's cash flows. This debt is collateralized (A) The table above does not include the capital requirements by interests in the physical assets, major project contracts and and financing costs of approximately $40 million for the agreements, cash accounts and, in some cases, the ownership High Desert Power Project for the six months ended interest in that project-June 30, 2003. We discuss the acquisition of the High We expect to fund acquisitions with a mixture of debt and Desert Power Project in Note 15.
equity with an overall goal of maintaining a strong investment The above amounts do not include the acquisition of Ginna but do grade credit profile.
include post-acquisition capitalrequirementsfor Ginna. We discuss the acquisition of Ginna in more detail in Note 15.
Regulated Elctric and Gas As of the date of this report, we have not completed our Funding for regulated electric and gas capital expenditures is 2006 capital budgeting process, but expect our 2006 capital expected from internally generated funds. During 2005, we requirements to be approximately $950 million. expect our regulated business to generate sufficient cash flows Our environmental controls capital requirements are - from operations to meet BGE's operating requirements. If affected by new rules or regulations that require modifications to necessary, additional funding may be obtained from commercial our facilities. As a result of regulatory or legislative proposals, we -paper-issuances, available capacity under credit facilities, the expect more stringent air emission standards to be adopted and issuance of long-term debt, trust preferred securities, or if promulgated as expected we will install additional air emission preference stock, and/or from time to time equity contributions control equipment at our coal-fired generating facilities in from' Constellation Energy. BGE also participates in a cash pool' Maryland and at co-owned coal-fired generating facilities in administered by Constellation Energy as discussed in Note 16.
Pennsylvania. If these rules are promulgated as we have assumed in our projections, there would be another $400-$500 million of Other NonregulatedBusinesses capital spending from 2008-2010. We discuss environmental Funding for our other nonregulated businesses is expected from matters in more detail in Item I.Business-Environmental internally generated funds, commercial paper issuances, issuances Matters. of long-term debt of Constellation Energy, sales of securities and assets, and/or from'time to time equity contributions from Capital Requirements Constellation Energy.
Merchant Energ Business Our ability to sell or liquidate securities and non-core assets Our merchant energy business' capital requirements consist of its will depend on market conditions,'and we cannot give continuing requirements, including expenditures for: assurances that these sales or liquidations could be made. We
- improvements to generating plants, discuss our remaining non-core assets and market conditions in
- nuclear fuel costs, the Results of Operations-OtherNonregulatedBusinesses section.
51
Contractual Payment Obligations and Committed The table below presents our contingent obligations. Our Amounts contingent obligations increased S2.6 billion during 2004, We enter into various agreements that result in contractual primarily due to the issuance of additional letters of credit and payment obligations in connection with our business activities. guarantees by the parent company for subsidiary obligations to These obligations primarily relate to our financing arrangements third parties in support of the growth of our merchant energy (such as long-term debt, preference stock, and operating leases), business. These amounts do not represent incremental purchases of capacity and energy to support the growth in our consolidated Constellation Energy obligations; rather, they merchant energy business activities, and purchases of fuel and primarily represent parental guarantees of certain subsidiary transportation to satisfy the fuel requirements of our power obligations to third parties. Our calculation of the fair value of generating facilities. subsidiary obligations covered by the $5,504.2 million of parent Our total contractual payment obligations as of company guarantees was $1,395.6 million at December 31, December 31, 2004 are shown in the following table 2004. Accordingly, if the parent company was required to fund payments subsidiary obligations, the total amount at current market prices 2006- 2008- is $1,395.6 million.
2005 2007 2009 Thereafser Total (In millions) Expiration ContratnualPayment 2006- 2008-Obligations 2005 2007 2009 Thereafter Total Long-term debt:' (In millions)
Nonregulatcd Contingent Obligationt Principal $ 314.5 S 639.6 S 518.3 S2,328.1 S 3,800.5 Letters of credit $ 787.5 S 22.4S - $ - $ 809.9 Interest 215.7 398.9 335.0 1,584.2 2,533.8 Guarantees - competitive Total 530.2 1,038.5 853.3 3,912.3 6,334.3 supply' 3,693.4 918.5 314.5 577.8 5,504.2 Other guarantees, net2 6.7 3.6 15.7 1,236.0 1,262.0 BGE Principal 41.6 565.3 307.5 589.2 1,503.6 Totalcontingentobligations $4,487.6$944.5$330.2 $1,813.8 $7,576.1 Interest 87.4 138.6 79.2 809.0 1,114.2 I While theeface amount f these guarantees is .55504.2 million, ue wvuld not Total 129.0 703.9 386.7 1,398.2 2,617.8 expect tofund thefull amount. In the event the parent uere requirrdtofu6'fiO BGE preference stock - - - 190.0 190.0 subsidiary obligations our calculation of the fair value of eobigations cotved by Operating Ileas&s 113.2 219.2 74.6 127.9 534.9 these guarantees us 51395.6 million at December 31, 2004.
Purchasc obligations:- 2 Other guarantees in the above sable are shown net of liabilities of $25.0 million recordedat December 31, 2004 in our Consolidated Balance Sheers.
Purchased capacity 4
and cnergy 794.2 743.3 184.9 157.0 1,879.4 Fuel and Liquidity Provisions transportation" 1,292.0 816.3 142.8 37.3 .2,288.4 In many cases, customers of our merchant energy business rely Other 97.2 63.0 74.9 211.0 446.1 on the creditworthiness of Constellation Energy. A decline below Other noncurrent investment grade by Constellation Energy would negatively liabilities: impact the business prospects of that operation.
Postretirement and We regularly review our liquidity needs to ensure that we postemploynment have adequate facilities available to meet collateral requirements.
benefits' 36.1 74.3 79.8 185.1 375.3 Other 1.6 - - - 1.6 This includes having liquidity available to meet margin requirements for our wholesale marketing and risk management Total contractual operation and our retail competitive supply activities.
payment obligations $2,993.5 S3,658.5 $1,797.0 $6,218.8 $14,667.8 We have certain agreements that contain provisions that 1 Anmountt in long.teuw debt rejLft the original maturity date. Investors may would require additional collateral upon credit rating decreases require us to repay $381.6 million early through put options and remarketing in the senior unsecured debt of Constellation Energy. Decreases features. Interest on variable rate debt is included based on the December 31.
2004jforuvardeurvefor interest rntet. in Constellation Energy's credit ratings would not trigger an 2 Our operating kase commitments include fture payment obligations under early payment on any of our credit facilities.
certain power purchate agreements atdiscussedfurther in Note 11. Under counterparty contracts related to our wholesale 3 Contractsto purtatehs goodt or services that iprci all significant terms. Amounn reltted to certain purchase obligations are based on future purchase epectations marketing and risk management operation, we are obligated to wiich may differfrom actual purchaes. post collateral if Constellation Energy's senior unsecured credit 4 Our contractualobligations forpurchasedcapacity and energy are shourn on a ratings declined below established contractual levels. As a result gros basis for certain transactions, including both thefixed payment portions of tolling contracu and estimated uaritblepaymenutunder unit-contingent power of the ratings action taken by Standard & Poors rating agency in purchase agreements We have recorded $17.4 million of liabilities related to March 2004, we posted approximately $40 million in additional purchased capacity and energy obligations at December 31. 20041 in our collateral during the first quarter of 2004 to support our Consolidated Balance Sheets.
wholesale marketing and risk management operational 5 Ue hatr recorded liabilities of $165 million related to fuel and transportation obligations at December 31, 2004 in our Consolidated Balance Shees. requirements. We discuss the Standard & Poors rating action in 6 Amounts reltted to postretiremett and postemplayment benefits arefor unfunded more detail in the Financial Condition-Securiuie;Ratings plans and reflect present tvlue amounts consistent wvith tse determination of the related liabilities recorded on the Consolidated Balance Sheers as discussed in section.
Note 7 52
Based on contractual provisions at December 31, 2004, we cross-default provisions that apply to defaults on debt by estimate that if Constellation Energy's senior unsecured debt Constellation Energy and certain subsidiaries over a specified were downgraded we would have the following additional threshold. Certain BGE credit facilities also contain usual and collateral obligations: customary cross-default provisions that apply to defaults on debt by BGE over a specified threshold. The indentures pursuant to Credit Ratings Incremental Cumulative which BGE has issued and outstanding mortgage bonds and Downgraded to Obligations Obligations subordinated debentures provide that a default under any debt (In millions) instrument issued under the relevant indenture may cause a BBB-1Baa3 $13 S13 default of all debt outstanding under such indenture.
Below investment grade 662 675 Constellation Energy also provides credit support to Calvert Cliffs, Nine Mile Point, and Ginna to ensure these plants have Based on market conditions and contractual obligations at the time of a downgrade, we could be required to post collateral funds to meet expenses and obligations to safely operate and in an amount that could exceed the amounts specified above, maintain the plants.
which could be material. At December 31, 2004, we had XN~e discuss our short-term credit facilities in Note 8, long-term debt in Note 9, lease requirements in Note 11, and approximately $1.6 billion of unused credit facilities and
$706.3 million of cash available to meet potential collateral commitments and guarantees in Note 12.
requirements.
Off-Balance Sheet Arrangements The credit facilities of Constellation Energy and BGE have For financing and other business purposes, we utilize certain limited material adverse change clauses that only consider a off-balance sheer arrangements that are not reflected in our material change in financial condition and are not directly Consolidated Balance Sheets. Such arrangements do not affected by decreases in credit ratings. If these clauses are represent a significant part of our activities or a significant invoked, the lending institutions can decline to make new ongoing source of financing. We use these arrangements when advances or issue new letters of credit, but cannot accelerate the they enable us to obtain financing or execute commercial payment of existing amounts outstanding. The long-term debt transactions on favorable terms. As of December 31, 2004, we indentures of Constellation Energy and BGE do not contain material adverse change clauses or financial covenants. have no material off-balance sheet arrangements including:
- guarantees with third-parties that are subject to the Certain credit facilities of Constellation Energy contain a initial recognition and measurement requirements of provision requiring Constellation Energy to maintain a ratio of FASB Interpretation No. 45, Guarantor! Accounting and debt to capitalization equal to or less than 65%. At Disclosure Requirrmentsfor Guarantees. Including Indirect December 31, 2004, the debt to capitalization ratios as defined Guarantees of Indebtedness to Others, in the credit agreements were no greater than 51%. Certain
- retained interests in assets transferred to unconsolidated credit agreements of BGE contain provisions requiring BGE to entities, maintain a ratio of debt to capitalization equal to or less than
- derivative instruments indexed to our common stock, 65%. At December 31, 2004, the debt to capitalization ratio for and classified as equity, or BGE as defined in these credit agreements was 46%. At
- variable interests in unconsolidated entities that provide December 31, 2004, no amount was outstanding under these financing, liquidity, market risk or credit risk support, agreements.
or engage in leasing, hedging or research and Failure by Constellation Energy, or BGE, to comply with development services.
these provisions could result in the maturity of the debt outstanding under these facilities being accelerated. The credit WYe discuss our guarantees in Note 12.
facilities of Constellation Energy contain usual and customary Market Risk limits. Ve have a Risk Management Department that is We are exposed to various risks, including, but not limited to, responsible for monitoring the key business risks, enforcing energy commodity price and volatility risk, credit risk, interest compliance with risk management policies and risk limits, as rate risk, equity price risk, foreign exchange risk, and operations well as managing credit risk. The Risk Management Department risk. Our risk management program is based on established reports to the Chief Risk Officer (CRO) who provides regular policies and procedures to manage these key business risks with risk management updates to the Audit Committee and the a strong focus on the physical nature of our business. This Board of Directors.
program is predicated on a strong risk management culture We have a Risk Management Committee (RMC) that is combined with an effective system of internal controls. responsible for establishing risk management policies, reviewing Our Board of Directors and the Audit Committee of the procedures for the identification, assessment, measurement and Board oversee the risk management program, including the management of risks, and the monitoring and reporting of risk approval of risk management policies and establishment of risk exposures. The RMC meets on a regular basis and is chaired by 53
the CRO and consists of our Chief Executive Officer, our Chief Interest Rate Risk Financial Officer and Chief Administrative Officer, our Executive We are exposed to changes in interest rates as a result of Vice President of Corporate Strategy & Development, the financing through our issuance of variable-rate and fixed-rate President of Constellation Energy Commodities Group, and the debt and certain related interest rate swaps. W~(e may use President of Constellation Generation Group. In addition, the derivative instruments to manage our interest rate risks.
CRO coordinates with the risk management committees at the In July 2004, to optimize the mix of fixed and floating-rate major operating subsidiaries that meet regularly to identify, debt, we entered into interest rate swaps relating to $450 million assess, and quantify material risk issues and to develop strategies of our long-term debt. These fair value hedges effectively convert to manage these risks. our current fixed-rate debt to a floating-rate instrument tied to the three month London Inter-Bank Offered Rate. Including the S450 million in interest rate swaps, approximately 15% of our long-term debt is floating-rate.
The following table provides information about our debt obligations that are sensitive to interest rate changes:
PrincipalPayments and Interest Rate Detail by ContractualMaturity Date Fair value at 2005 2006 2007 2008 2009 Thereafter Total Dec. 31, 2004 (Dollar amounts in millions)
Long-term debt Variable-rate debt $ 8.6 $100.9 $ 5.0 $ 5.0 $ 10.0 S 706.1 $ 835.6 $ 835.6 Average interest rate 4.26% 2.57% 5.53% 5.53% 5.53% 3.00% 3.07%
Fixed-rate debt $347.5(A) $362.1 $736.9 $299.3 $511.5 $2,211.2 $4,468.5 $4,979.7 Average interest rate 7.61% 5.43% 6.49% 6.28% 6.12%16 6.46% 6.43%
(A) Amount excludes $381.6 million of long-term debt that contains certainput options under whichlinders could potentially require us to repay the debt prior to maturity of which $124.3 million is clasif ied as current portion oflong-term drbt in our ConsolidatedBalance Sheets and in our ConsolidatedStatements of Capitalization.
Commodity Risk the associated financial exposure, this commodity price volatility We are exposed to the impact of market fluctuations in the price could affect our eamings. These factors include and transportation costs of electricity, natural gas, coal, and
- seasonal daily and hourly changes in demand, other commodities. These risks arise from our ownership and
- extreme peak demands due to weather conditions, operation of power plants, the load-serving activities of BGE
- available supply resources, standard offer service and our competitive supply activities, and
- transportation availability and reliability within and our origination and risk management activities. We discuss these between regions, risks separately for our merchant energy and our regulated
- location of our generating facilities relative to the businesses bdow. location of our load-serving obligations,
- procedures used to maintain the integrity of the physical Aferchant Energy Business electricity system during extreme conditions, and Our merchant energy business is exposed to various risks in the
- changes in the nature and extent of federal and state competitive marketplace that may materially impact its financial regulations.
results and affect our earnings. These risks include changes in These factors can affect energy commodity and derivative commodity prices, imbalances in supply and demand, and prices in different ivays and to different degrees. These effcas operations risk. may vary throughout the country as a result of regional differences in:
Commodity Prices
- weather conditions, Commodity price risk arises from:
- market liquidity,
- the potential for changes in the price of, and
- capability and reliability of the physical electricity and transportation costs for, electricity, natural gas, coal, and gas systems, and other commodities,
- the nature and extent of electricity deregulation.
- the volatility of commodity prices, and Additionally, we have fuel requirements that are subject to
- changes in interest rates and foreign exchange rates. future changes in coal, natural gas, and oil prices. Our power A number of factors associated with the structure and generation facilities purchase fuel under contracts or in the spot operation of the energy markets significantly influence the level market. Fuel prices may be volatile and the price that can be and volatility of prices for energy commodities and related obtained from power sales may not change at the same rate or derivative products. We use such commodities and contracts in in the same direction as changes in fuel costs. This could have a our merchant energy business, and if we do not properly hedge material adverse impact on our financial results.
54
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The value at risk calculation does not include market risks Due to the inherent limitations of statistical measures such associated with activities chat are subject to accrual accounting, as value at risk and the seasonality of changes in market prices, primarily our generating facilities and our competit ive supply the value at risk calculation may not reflect the full extent of load-serving activities. We manage these risks by mionitoring our our commodity price risk exposure. Additionally, actual changes fuel and energy purchase requirements and our estiimated in the value of options may differ from the value at risk contract sales volumes compared to associated supplly calculated using a linear approximation inherent in our arrangements. We also engage in hedging activities to manage calculation method. As a result, actual changes in the fair value these risks. We describe those risks and our hedgin1 activities of mark-to-market energy assets and liabilities could differ from earlier in this section. the calculated value at risk, and such changes could have a The value at risk amounts below represent the potential material impact on our financial results.
pre-tax loss in the fair value of our wholesale markt nsing and risk management mark-to-market energy assets and liabi ilities over Regulated Electric Business one and ten-day holding periods. BGE's residential base rates are frozen for a six-year period ending June 30, 2006, and its commercial and industrial base Total Wbolesale Value at Risk rates were frozen for a four-year period that ended June 30, For rhe year ended December 31, 2004 2003 2004. The commodity and transmission components of rates are (In milliom) frozen for different time periods depending on the customer 99% Confidence Level, One-Day Holding Period Year end
$4 $ 37 type and service options selected by custnmers.
Avenrge 3.7 66 Our wholesale marketing and risk management operation High 7.8 13.3 provided BGE with 100% of the energy and capacity required Low 2.5 2.7 to meet its commercial and industrial standard offer service obligations through June 30, 2004, and provides i00% of the 95% Confidcnce Level, Onc-Day Holding Period
$ 3.4 S 2.8 energy and capacity to meet its residential standard offer service Year end Average 2.8 S50 obligations through June 30, 2006. Effective July 1, 2004, BGE High 5.9 10.1 executed one and two-year contracts for commercial and Low 1.9 2.1 industrial electric power supply totaling approximately 2,300 megavatts. Our wholesale marketing and risk management 95% Confidenec Level, Ten-Day Holding Period
$10.7 $ 88 operation will provide a significant portion of this electric power Year end Average 9.0 15.9 supply.
High 18.7 32.0 Bidding to supply BGE's standard offer service to Low 6.1 6.5 commercial and industrial customers for one, two, or four-year periods beyond June 30, 2004, and to residential customers Based on a 99% confidence interval, we woul d expect a beyond June 30, 2006, will occur from time to time through a one-day change in the fair value of the portfolio gr eater than or competitive bidding process approved by the Maryland PSC. We equal to the daily value at risk approximately once in every discuss standard offer service and the impact on base rates in 100 days. In 2004, we experienced four instances Mwhere the more detail in Item 1. Business-Electric Business section.
actual daily mark-to-market change in portfolio val uc exceeded BGE may receive performance assurance collateral from the predicted value at risk. On average, we expcc to experience suppliers to mitigate suppliers' credit risks in certain a change in value to our portfolio greater than our value at risk circumstances. Performance assurance collateral is designed to approximately three times in a calendar year. Howe ver, published protect BGE's potential exposure over the term of the supply market studies conclude that exceeding daily value, at risk less contracts and will fluctuate to reflect changes in market prices.
than seven times in a one-year period is considered consistent In addition to the collateral provisions, there are supplier with a 99% confidence interval. "step-up" provisions, where other suppliers can step in if the The table above is the value at risk associated with our early termination of a Full-Requirements Service Agreement with wholesale marketing and risk management operatio ens a supplier should occur, as well as specific mechanisms for BGE mark-to-market energy assets and liabilities, includi ng both to otherwise replace defaulted supplier contracts. All costs trading and non-trading activities. The following ta ble details incurred by BGE to replace the supply contract are to be our value at risk for the trading portion of our whi olesale recovered from the defaulting supplier or from customers marketing and risk management mark-to-market cn fergy assets through rates. Finally, BGE's exposure to uncollectible expense and liabilities over a one-day holding period at a 9'9% or credit risk from customers for the commodity portion of the confidence level for 2004 and 2003: bill is covered by the administrative fee included in Provider of Last Resort rates.
'vWolesale Trading Value at Risk At December 31, 2004 2003 Regulated Gas Business (In millions) Our regulated gas business may enter into gas futures, options, Average $2.6 S 4.6 and swaps to hedge its price risk under our market-based rate High 6.9 10-9 incentive mechanism and our off-system gas sales program. We 56
discuss this further in Note 13. At December 31, 2004 and The reduction in the percentage of counterparries with 2003, our exposure to commodity price risk for our regulated investment grade ratings to 62% in 2004 is primarily due to gas business was not material. continued increased exposure to lower credit quality fuel and power supply counterparties that supply fuel to our power plants Credit Risk and provide power to meet certain customer load-serving We are exposed to credit risk, primarily through our merchant requirements.
energy business. Credit risk is the loss that may result from In addition to the credit ratings provided by the major counterparties' nonperformance. We evaluate the credit risk of credit rating agencies, we utilize internal credit ratings to our wholesale marketing and risk management operation and evaluate the creditworthiness of our wholesale customers, our retail competitive supply activities separately as discussed including those companies that do not have public credit belowv. ratings. The following table provides the breakdown of the credit quality of our wholesale credit portfolio based on our internal WSoletak Credit Risk credit ratings.
We measure wholesale credit risk as the replacement cost for open energy commodity and derivative transactions (both At December31, 2004 2003 mark-to-market and accrual) adjusted for amounts owed to or Investment Grade Equivalent 74% 910%b due from counterparties for settled transactions. The replacement Non-Investment Grade 26 9 cost of open positions represents unrealized gains, net of any A portion of our wholesale credit risk is related to unrealized losses, where we have a legally enforceable right of transactions that are recorded in our Consolidated Balance setoff. We monitor and manage the credit risk of our wholesale marketing and risk management operation through credit Sheets. These transactions primarily consist of open positions from our wholesale marketing and risk management operation policies and procedures which indude an established credit that are accounted for using mark-to-market accounting, as well approval process, daily monitoring of counterparty credit limits, as amounts owed by wholesale counterparties for transactions the use of credit mitigation measures such as margin, collateral, that scttled but have not yet been paid. The following table or prepayment arrangements, and the use of master netting highlights the credit quality and exposures related to these agreements.
activities:
During 2004, we continued to observe declines in the creditworthiness of several major participants in the wholesale Net energy markets. We continue to actively manage the credit Total Number of Exposure of portfolio of our wholesale marketing and risk management Exposure Counterparties Counterparties Before Greater than Greater than operation to attempt to reduce the impact of the general decline Credit Credit Net 10% of Net 10% of Net in the overall credit quality of the energy industry and the Rating Collateral Collateral Exposure Exposure Exposure impact of a potential counterpartsy default. As of December 31, (Dollars in millions) 2004 and 2003, the credit portfolio of our wholesale marketing Investment grade S 789 $ 53 $ 736 1 $158 and risk management operation had the following public credit Split rating 6 - 6 - -
ratings: Non-investment At December 31, 2004 2003 grade 215 151 64 -
Internally Rating rated-Investment Grade' 62% 75% investment Non-Investment Grade 15 4 gradr 225 58 167 - -
Not Rated 23 21 Internally rated-I Includes counterparrieswith an investment grade rating by at non-least one of the major credit rating agencies. If split rating exists, investment the lower ratingis used. grade 77 33 44 - -
Tout 51,312 5295 $1,017 I $158 Due to the possibility of extreme volatility in the prices of energy commodities and derivatives, the market value of contractual positions with individual counterparties could exceed established credit limits or collateral provided by those counterparties. If such a counterparty were then to fail to perform its obligations under its contract (for example, fail to deliver the elcaricity our wholesale marketing and risk management operation had contracted for), we could incur a loss that could have a material impact on our financial results.
57
Additionally, if a counterparty were to default and we were Foreign Currency Risk to liquidate all contracts with that entity, our credit loss would Our merchant energy business is exposed to the impact of include the loss in value of mark-to-market contracts, the foreign exchange rate fluctuations. This foreign currency risk amount owed for settled transactions, and additional payments, arises from our activities in countries where we transact in if any, that we would have to make to settle unrealized losses on currencies other than the U.S. dollar. In 2004, our exposure to accrual contracts. foreign currency risk was not material. However, we expect our foreign currency exposure to grow due to our Canadian presence Retail CreditRisk and international coal operations. We manage our exposure to We are exposed to retail credit risk through our competitive foreign currency exchange rate risk using a comprehensive electricity and natural gas supply activities which serve foreign currency hedging program. While we cannot predict commercial and industrial companies. Retail credit risk results currency fluctuations, the impact of foreign currency exchange when customers default on their contractual obligations. This rate risk could be material.
risk represents the loss that may be incurred due to the nonpayment of a customer's accounts receivable balance, as well Equity Price Risk as the loss from the resale of energy previously committed to We are exposed to price fluctuations in equity markets primarily serve the customer. through our pension plan assets, our nuclear decommissioning Retail credit risk is managed through established credit trust funds and trust assets securing certain executive benefits.
policies, monitoring customer exposures, and the use of credit We are required by the NRC to maintain externally funded mitigation measures such as letters of credit or prepayment trusts for the costs of decommissioning our nuclear power arrangements. plants. We discuss our nuclear decommissioning trust funds in Our retail credit portfolio is well diversified with no more detail in Note 1.
significant company or industry concentrations. During 2004, A hypothetical 10% decrease in equity prices would result we did not experience a material change in the credit quality of in an approximate S110 million reduction in the fair value of our retail credit portfolio compared to 2003. Retail credit quality our financial investments that are classified as trading or is dependent on the economy and the ability of our customers available-for-sale securities. In 2004, the value of our defined to manage through unfavorable economic cycles and other benefit pension plan assets increased by $114 million due to market changes. If the business environment were to be advances in the markets in which plan assets are invested. We negatively affected by changes in economic or other market describe our financial investments in more detail in Note 4, and conditions, our retail credit risk may be adversely impacted. our pension plans in Note 7.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk The information required by this item with respect to market risk is set forth in Item 7 of Part II of this Form 10-K under the heading Market Risk.
58
Item 8. Financial Statements and Supplementary Data
. . .I FinancialStatements accordance with generally accepted accounting principles in the The management of Constellation Energy Group, Inc. and United States of America.
Baltimore Gas and Electric Company (the "Companies") is The management of Constellation Energy conducted an responsible for the information and representations in the evaluation of the effectiveness of Constellation Energy's internal Companies' financial statements. The Companies prepare the control over financial reporting using the framework in Internal financial statements in accordance with accounting principles Control-Integrated Framework issued by the Committee of generally accepted in the United States of America based upon Sponsoring Organizations of the Treadway Commission available facts and circumstances and management's best (COSO). As noted in the COSO framework, an internal control estimates and judgments of known conditions. system, no matter how well conceived and operated, can provide PricewaterhouseCoopers LLP, an independent registered only reasonable-not absolute-assurance to management and the public accounting firm, has audited the financial statements and Board of Directors regarding achievement of an entitys financial expressed their opinion on them. They performed their audit in reporting objectives. Based upon the evaluation under this accordance with the standards of the Public Company framework, management concluded that Constellation Energy's Accounting Oversight Board (United States). internal control over financial reporting was effective as of The Audit Committee of the Board of Directors, which December 31, 2004.
consists of four independent Directors, meets periodically with PricewaterhouseCoopers LLP, an independent registered management, internal auditors, and PricewaterhouseCoopers UP public accounting firm, has audited management's assessment of to review the activities of each in discharging their the effectiveness of Constellation Energys internal control over responsibilities. The internal audit staff and financial reporting at December 31, 2004, as stated in their PricewaterhouseCoopers UP have free access to the Audit report set forth below.
Committee. As discussed in Item 9A. Controls and Procedures, the management of Baltimore Gas & Electric Company ("BGE")
Management's Report on Internal Control Over has not assessed the effectiveness of BGE's internal control over FinancialReporting financial reporting on a standalone basis because it is not yet The management of Constellation Energy Group, Inc. required to do so by applicable federal securities laws and
("Constellation Energy"), under the direction of its principal regulations.
executive officer and principal financial officer, is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Exchange Act Rule 13a-15(f).
- =o~
Mayo A. Shatck III E. Follin Smith Constellation Energy's system of internal control over Chairman ofthe Board, Executive Vice-President, financial reporting is designed to provide reasonable assurance to President and ChiefExecutive ChiefFinancialOfficer, and Constellation Energy's management and Board of Directors Officer ChiefAdministrative Officer regarding the reliability of financial reporting and the preparation of financial statements for external purposes in
- ., , . . . 11H VN, To the Board of Directorsand Shareholders of Constellation Energy and the results of their operations and their cash flows for each Group, Inc. of the three years in the period ended December 31, 2004 in We have completed an integrated audit of Constellation Energy conformity with accounting principles generally accepted in the Group, Inc. and Subsidiaries' 2004 consolidated financial United States of America. In addition, in our opinion, the statements and of its internal control over financial reporting as financial statement schedule listed in the index appearing under of December 31, 2004 and audits of its 2003 and 2002 Item 15(a) 2 presents fairly, in all material respects, the consolidated financial statements in accordance with the information set forth therein when read in conjunction with the standards of the Public Company Accounting Oversight Board related consolidated financial statements. These financial (United States). Our opinions, based on our audits, are statements and financial statement schedule are the responsibility presented below. of the Company's management; our responsibility is to express an opinion on these financial statements and financial statement Consolidated financial statements and financial schedule based on our audits. We conducted our audits of these statement schedule statements in accordance with the standards of the Public In our opinion, the consolidated financial statements listed in Company Accounting Oversight Board (United States). Those the index appearing under Item 15(a) 1. present fairly, in all standards require that we plan and perform the audit to obtain material respects, the financial position of Constellation Energy reasonable assurance about whether the financial statements are Group, Inc. and Subsidiaries at December 31, 2004 and 2003, free of material misstatement. An audit of financial statements 59
includes examining, on a test basis, evidence supporting the statements for external purposes in accordance with generally amounts and disclosures in the financial statements, assessing the accepted accounting principles. A company's internal control accounting principles used and significant estimates made by over financial reporting includes those policies and procedures management, and evaluating the overall financial statement that (i) pertain to the maintenance of records that, in reasonable presentation. We believe that our audits provide a reasonable detail, accurately and fairly reflect the transactions and basis for our opinion. dispositions of the assets of the company; (ii) provide reasonable We have also previously audited, in accordance with the assurance that transactions are recorded as necessary to permit standards of the Public Company Accounting Oversight Board preparation of financial statements in accordance with generally (United States), the consolidated balance sheets and statements accepted accounting principles, and that receipts and of capitalization of Constellation Energy Group, Inc. and expenditures of the company are being made only in accordance Subsidiaries as of December 31, 2002, 2001 and 2000, and the with authorizations of management and directors of the related consolidated statements of income, cash flows, and company; and (iii) provide reasonable assurance regarding common shareholders' equity and comprehensive income for the prevention or timely detection of unauthorized acquisition, use, years ended December 31, 2001 and 2000 (none of which are or disposition of the company's assets that could have a material presented herein); and we expressed unqualified opinions on effect on the financial statements.
those consolidated financial statements. In our opinion, the Because of its inherent limitations, internal control over information set forth in the Summary of Operations and financial reporting may not prevent or detca misstatements.
Summary of Financial Condition of Constellation Energy Also, projections of any evaluation of effectiveness to future Group, Inc. and Subsidiaries included in the Selected Financial periods are subject to the risk that controls may become Data for each of the five years in the period ended inadequate because of changes in conditions, or that the degree December 31, 2004, is fairly stated, in all material respects, in of compliance with the policies or procedures may deteriorate.
relation to the consolidated financial statements from which it has been derived.
Internal control over financial reporting PricewaterhouseCoopers LLP Also, in our opinion, management's assessment, included in Atlanta, Georgia Management's Report on Internal Control Over Financial March 10, 2005 Reporting appearing under Item 8, that the Company maintained effective internal control over financial reporting as To Board of Directors and Shareholderof Baltimore Gas and of December 31, 2004, based on criteria established in Internal Flectric Coinpany Control-Integrated Framework issued by the Committee of In our opinion, die consolidated financial statements listed in Sponsoring Organizations of the Treadway Commission the index appearing under Item 15(a) 1. present fairly, in all (COSO), is fairly stated, in all material respects, based on those material respects, the financial position of Baltimore Gas and criteria. Furthermore, in our opinion, the Company maintained, Electric Company and Subsidiaries at December 31, 2004 and in all material respects, effective internal control over financial 2003, and the results of their operations and their cash flows for reporting as of December 31, 2004, based on criteria established each of the three years in the period ended December 31, 2004 in Internal Control-Integrated Framework issued by the in conformity with accounting principles generally accepted in COSO. The Company's management is responsible for the United States of America. In addition, in our opinion, the maintaining cffecaivc internal control over financial reporting financial statement schedule listed in the index appearing under and for its assessment of the effectiveness of internal control over Item 15(a) 2 presents fairly, in all material respects, the financial reporting. Our responsibility is to express opinions on information set forth therein when read in conjunction with the management's assessment and on the effectiveness of the related consolidated financial statements. These financial Company's internal control over financial reporting based on our statements are the responsibility of the Companys management; audit. We conducted our audit of internal control over financial our responsibility is to express an opinion on these financial reporting in accordance with the standards of the Public statements based on our audits. We conducted our audits of Company Accounting Oversight Board (United States). Those these statements in accordance with the standards of the Public standards require that we plan and perform the audit to obtain Company Accounting Oversight Board (United States). Those reasonable assurance about whether effective internal control over standards require that we plan and perform the audit to obtain financial reporting was maintained in all material respects. An reasonable assurance about whether the financial statements are audit of internal control over financial reporting includes free of material misstatement. An audit includes examining, on a obtaining an understanding of internal control over financial test basis, evidence supporting the amounts and disclosures in reporting, evaluating management's assessment, testing and the financial statements, assessing the accounting principles used evaluating the design and operating effectiveness of internal and significant estimates made by management, and evaluating control, and performing sudh other procedures as we consider the overall financial statement presentation. We believe that our necessary in the circumstances. We believe that our audit audits provide a reasonable basis for our opinion.
provides a reasonable basis for our opinions.
Wte have also previously audited, in accordance with the A company's internal control over financial reporting is a standards of the Public Company Accounting Oversight Board process designed to provide reasonable assurance regarding the (United States), the consolidated balance sheets of Baltimore Gas reliability of financial reporting and the preparation of financial 60
and Electric Company and Subsidiaries as of December 31, period ended December 31, 2004, is fairly stated, in all material 2002, 2001 and 2000, and the related consolidated statements respects, in relation to the consolidated financial statements from of income, cash flows, and common shareholders' equity and which it has been derived.
comprehensive income for the years ended December 31, 2001 and 2000 (none of which are presented herein); and we expressed unqualified opinions on those consolidated financial statements. In our opinion, the information set forth in the Pricew-aterhouseCoopers LLP Summary of Operations and Summary of Financial Condition of Atlanta, Georgia Baltimore Gas and Electric Company and Subsidiaries included March 10, 2005 in the Selected Financial Data for each of the five years in the 61
Constellation Energy Group, Inc. and Subsidiaries Year Ended December 31, 2004 2003 2002 (In millions, except per share amounts)
Revenues Nonregulated revenues S 9,827.0 $7,053.6 $2,182.5 Regulated electric revenues 1,967.6 1,921.5 1,965.6 Regulated gas revenues 755.1 712.7 570.5 Total revenues 12,549.7 9,687.8 4,718.6 Expenses Fuel and purchased energy expenses 8,849.6 6,297.1 1,709.8 Operating expenses 1,770.7 1,575.6 1,380.8 Workforce reduction costs 9.7 2.1 62.8 Impairment losses and other costs 3.7 0.6 25.2 Depreciation and amortization 525.5 479.0 481.0 Accretion of asset retirement obligations 53.2 42.7 Taxes other than income taxes 258.9 250.6 234.1 Total expenses 11,471.3 8,647.7 3,893.7 Net (Loss) Gain on Sales of Investments and Other Assets (1.2) 26.2 261.3 Income from Operations 1,077.2 1,066.3 1,086.2 Other Income 14.1 19.1 30.5 Fixed Charges Interest expense 328.0 340.8 312.3 Interest capitalized and allowance for borrowed funds used during construction (10.9) (13.8) (44.0)
BGE preference stock dividends 13.2 13.2 13.2 Total fixed charges 330.3 340.2 281.5 Income Before Income Taxes 761.0 745.2 835.2 Income Taxes 172.2 269.5 309.6 Income from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles 588.8 475.7 525.6 Loss from discontinued operations, net of income taxes of $26.5 (see Note
- 2) (49.1) - -
Cumulative effects of changes in accounting principles, net of income taxes of S119.5 _ (198.4) _
Net Income $ 539.7 S 277.3 $ 525.6 Earnings Applicable to Common Stock $ 539.7 $ 277.3 $ 525.6 Average Shares of Common Stock Outstanding-Basic 172.1 166.3 164.2 Average Shares of Common Stock Outstanding-Diluted 173.1 166.7 164.2 Earnings Per Common Share from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles-Basic $ 3.42 S 2.86 $ 3.20 Loss from discontinued operations (0.28)
Cumulative effects of changes in accounting principles - (1.19)
Earnings Per Common Share-Basic $ 3.14 S 1.67 $ 3.20 Earnings Per Common Share from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles-Diluted $ 3.40 $ 2.85 $ 3.20 Loss from discontinued operations (0.28)
Cumulative effects of changes in accounting principles _ (1.19)
Earnings Per Common Share-Diluted $ 3.12 $ 1.66 S 3.20 Dividends Declared Per Common Share $ 1.14 $ 1.04 $ 0.96 See Notes to ConsolidatedFinancialStatements.
Certain prior-year amounts lave been reclassified to conform with the currentyears presentation.
62
. I *. ==
Constellation Energy Group, Inc. and Subsidiaries At December 31, 2004 2003 (In millions)
Assets Current Assets Cash and cash equivalents $ 706.3 $ 721.3 Accounts receivable (net of allowance for uncollectibles of $43.1 and $51.7, respectively) 1,979.3 1,563.0 Mark-to-market energy assets 567.3 504.8 Risk management assets 471.5 233.0 Materials and supplies 203.8 203.2 Fuel stocks 298.3 196.8 Other 262.9 220.3 Total current assets 4,489.4 3,642.4 Investments and Other Assets Nudear decommissioning trust funds 1,033.7 736.1 Investments in qualifying facilities and power projects 318.4 332.6 Mark-to-market energy assets 359.8 265.8 Risk management assets 306.2 154.5 Regulatory assets (net) 195.4 229.5 Goodwill 144.8 146.3 Other 412.8 484.3 Total investments and other assets 2,771.1 2,349.1 Property, Plant and Equipment Regulated property, plant and equipment Plant in service 5,324.4 5,131.7 Construction work in progress 83.1 130.5 Plant held for future use 5.2 4.5 Total regulated property, plant and equipment 5,412.7 5,266.7 Nonregulated property, plant and equipment 8,638.4 8,110.0 Nudear fuel (net of amortization) 264.3 202.9 Accumulated depreciation (4,228.8) (3,978.1)
Net property, plant and equipment 10,086.6 9,601.5 Total Assets $17,347.1 $15,593.0 See Notes to Consolibted FinancialStatements.
Certainprior-year amounts have been reclasified to conform with the currentyearl presentation.
63
Constellation Energy Group, Inc. and Subsidiaries At December 31, 2004 2003 (In millions)
Liabilities and Equity Current Liabilities Short-term borrow ings $ - $ 9.6 Current portion of long-term debt 480.4 343.2 Accounts payable and accrued liabilities 1,424.9 1,142.0 Customer deposits and collateral 223.8 194.5 Mark-to-market energy liabilities 559.7 490.4 Risk management liabilities 304.3 118.8 Accrued expenses and other 669.3 628.9 Total current liabilities 3,662.4 2,927.4 Deferred Credits and Other Liabilities Deferred income taxes 1,303.3 1,311.8 Asset retirement obligations 825.0 595.9 Mark-to-market energy liabilities 315.0 261.4 Risk management liabilities 472.2 166.7 Postretirement and postemployment benefits 375.3 361.8 Net pension liability 269.7 225.7 Deferred investment tax credits 71.2 78.4 Other 232.0 180.8 Total deferred credits and other liabilities 3,863.7 3,182.5 Capitalization (See Consolidated Statements of Capitalization)
Long-term debt 4,813.2 5,039.2 Minority interests 90.9 113.4 BGE preference stock not subject to mandatory redemption 190.0 190.0 Common shareholders' equity 4,726.9 4,140.5 Total capitalization 9,821.0 9,483.1 Commitments, Guarantees, and Contingencies (see Note 12)
Total Liabilities and Equity $17,347.1 S1 5,593.0 See Notes to ConsolidatedFinancialStatements.
Certainprior-yearamounts hazve been reclasified to conform with the currntyears presentation.
64
Constellation Energy Group, Inc. and Subsidiaries Year Ended December 31. 2004 2003 2002 (In millions)
Cash Flows From Operating Activities Net income $ 539.7 $ 277.3 $ 525.6 Adjustments to reconcile to net cash provided by operating activities Loss from discontinued operations 49.1 - -
Cumulative effects of changes in accounting principles - 198.4 Depreciation and amortization 660.7 611.7 558.0 Accretion of asset retirement obligations 53.2 42.7 Deferred income taxes 123.4 109.2 148.3 Investment tax credit adjustments (7.2) (7.3) (7-9)
Deferred fuel costs 6.0 (10.1) 23.9 Pension and postemployment benefits (3.0) (69.4) (116.2)
Net loss (gain) on sales of investments and other assets 1.2 (26.2) (261.3)
Workforce reduction costs 9.7 2.1 62.8 Impairment losses and other costs 3.7 0.6 25.2 Equity in earnings of affiliates less than dividends received 30.5 38.4 67.0 Changes in Accounts receivable (437.4) (291.0) (236.8) hMark-to-market energy assets and liabilities (26.1) 29.9 (133-7)
Risk management assets and liabilities 5.3 (83.5) 58.6 Materials, supplies, and fuel stocks (112.1) (51.5) (11.7)
Other current assets 2.4 19.3 130.3 Accounts payable and accrued liabilities 273.9 204.1 188.4 Other current liabilities (35.6) 107.4 53.9 Other (50.6) (44.3) (68.6)
Net cash provided by operating activities 1,086.8 1,057.8 1,005.8 Cash Flows From Investing Activities Investments in property, plant and equipment (703.6) (635.7) (817.7)
Acquisitions, net of cash acquired (457.3) (546.6) (221.4)
Contributions to nuclear decommissioning trust funds (22.0) (13.2) (17.6)
Net proceeds from sale of discontinued operations 72.7 Sale of investments and other assets 36.1 148.8 838.0 Other investments (78.6) (113.6) (86.9)
Net cash used in investing activities (1,152.7) (1,160.3) (305.6)
Cash Flows From Financing Activities Net maturity of short-term borrowings (9.6) (0.9) (964.5)
Proceeds from issuance of Common stock 293.9 95.4 28.5 Long-term debt 100.0 983.3 2,529.3 Repayment of long-term debt (243.2) (707.5) (1,627.7)
Common stock dividends paid (189.7) (169.2) (137.8)
Proceeds from acquired contracts 117.5 - -
Other (18.0) 7.7 14.6 Net cash provided by (used in) financing activities 50.9 208.8 (157.6)
Net (Decrease) Increase in Cash and Cash Equivalents (15-0) 106.3 542.6 Cash and Cash Equivalents at Beginning of Year 721.3 615.0 72.4 Cash and Cash Equivalents at End of Year $ 706.3 $ 721.3 $ 615.0 Other Cash Flow Information:
Cash paid during the year for Interest (net of amounts capitalized) $ 331.4 $ 339.4 $ 230.5 Income taxes $ 207.9 $ 34.0 $ 157.8 See Notes to ConsolidatedFinancialStatements.
Certainprior-yearamounts have been reclassified to conform with the currentyear! presentation.
65
C.o 'M*] Ii . E S Grou, Inc. and Su d "s* e l 1 S Constellation Energy Group, Inc. and Subsidiaries Accumulated Other Common Stock Retained Comprehensive 'I otal Year Ended December 31. 2004, 2003, and 2002 Shares Amount Earnings Income (Loss) Ar nount (Dollar amounts in millions, number of shares in thousands)
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 (OCI)
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 gain 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 525.6 (384.1) 141.5 Common stock dividend declared ($0.96 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 Comprehensive Income Net income 277.3 277.3 Other comprehensive income Reclassification of net gain on sales of securities from OCI to net income, net of taxes of $0.2 (0.4) (0.4)
Reclassification of net gains on hedging instruments from OCI to net income, net of taxes of $10.7 (16.4) (16.4)
Net unrealized gain on securities, net of taxes of $24.4 37.3 37.3 Net unrealized gain on hedging instruments, net of taxes of $15.8 39.9 39.9 Minimum pension liability, net of taxes of $8.2 12.6 12.6 Total Comprehensive Income 277.3 73.0 350.3 Common stock dividend declared ($1.04 per share) (172.8) (172.8)
Common stock issued 2,976 100.9 100.9 Other (0.2) (0.2)
Balance at December 31, 2003 167,819 2,179.8 2,081.9 (121.2) 4,140.5 Comprehensive Income Net income 539.7 539.7 Other comprehensive income Reclassification of net loss on securities from OCI to net income, net of taxes of $1.4 2.2 2.2 Redassification of net gains on hedging instruments from OCI to net income, net of taxes of $169.0 (270.8) (270.8)
Net unrealized gain on securities, net of taxes of $22.2 33.7 33.7 Net unrealized gain on hedging instruments, net of taxes of $124.7 196.8 196.8 Net unrealized gain on foreign currency translation 0.4 0.4 Minimum pension liability, net of taxes of $27.9 (42.6) (42.6)
Total Comprehensive Income 539.7 (80.3) 459.4 Common stock dividend declared ($1.14 per share) (196.3) (196.3)
Common stock issued 8,514 322.7 322.7 Other 0.6 0.6 Balance at December 31, 2004 176,333 $2,502.5 $2,425.9 $(201.5) $4,726.9 See Notes to Consolidated FinancialStatements.
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Constellation Energy Group, Inc. and Subsidiaries At December 31, 2004 2003 (In millions)
Long-Term Debt Long-term debt of Constellation Energy 7-/sV Notes, due April 1, 2005 $ 300.0 $ 300.0 6.35% Fixed-Rate Notes, due April 1, 2007 600.0 600.0 6.125% Fixed-Rate Notes, due September 1, 2009 500.0 500.0 7.00% Fixed-Rate Notes, due April 1, 2012 700.0 700.0 4.55% Fixed-Rate Notes, due June 15, 2015 550.0 550.0 7.60% Fixed-Rate Notes, due April 1, 2032 700.0 700.0 Fair Value of Interest Rate Swaps 13.3 Total long-term debt of Constellation Energy 3,363.3 3,350.0 Long-term debt of nonregulated businesses Tax-exempt debt transferred from BGE cffective 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 District Cooling facilities loan, due December 1, 2031 25.0 25.0 Loans under revolving credit agreements 100.1 46.3 Geothermal facilities loan, due September 30, 2011 45.3 4.25% Mortgage note, due March 15, 2009 2.3 2.8 South Carolina synthetic fuel facility loan, due January 15, 2008 40.0 Total long-term debt of nonregulated businesses 437.2 389.2 First Refunding Mortgage Bonds of BGE 5'A% Series, due April 15, 2004 125.0 Remarketed floating-rate series, due September 1, 2006 99.3 104.1 7!6% Series, due January 15, 2007 122.5 122.5 6%% Series, due March 15, 2008 124.5 124.5 Total First Refunding Mortgage Bonds of BGE 346.3 476.1 Other long-term debt of BGE 5.25% Notes, due December 15, 2006 300.0 300.0 5.20% Notes, due June 15, 2033 200.0 200.0 Medium-term notes, Series B 12.1 12.1 Medium-term notes, Series D 48.0 68.0 Medium-term notes, Series E 199.5 199.5 Medium-term notes, Series G 140.0 140.0 Total other long-term debt of BGE 899.6 919.6 6.20% deferrable interest subordinated debentures due October 15, 2043 to BGE wholly owned BGE Capital Trust 1I relating to trust preferred securities 257.7 257.7 Unamortized discount and premium (10.5) (10.2)
Current portion of long-term debt (480.4) (343.2)
Total long-term debt $4,813.2 $5,039.2 See Notes to Consolidated FinancialStatements.
continued on next page 67
Constellation Energy Group, Inc. and Subsidiaries At Deconber 31, 2004 2003 (in millions)
Minority Interests $ 90.9 $ 113.4 BGE Preference Stock Cumulative preference stock not subject to mandatory redemption, 6,500,000 shares authorized 7.125%, 1993 Series, 400,000 shares outstanding, callable at $103.21 per share until June 30, 2005, and at lesser amounts thereafter 40.0 40.0 6.97%, 1993 Series, 500,000 shares outstanding, callable at $103.14 per share until September 30, 2005, and at lesser amounts thereafter 50.0 50.0 6.70%, 1993 Series, 400,000 shares outstanding, callable at $103.02 per share until December 31, 2005, and at lesser amounts thereafter 40.0 40.0 6.99%, 1995 Series, 600,000 shares outstanding, not callable prior to October 1, 2005, then callable at $103.50 per share until September 30, 2006 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; 176,333,121 and 167,819,338 shares issued and outstanding at December 31, 2004 and 2003, respectively.
(At December 31, 2004, 5,884,607 shares were reserved for the long-term incentive plans, 7,957,620 shares were reserved for the Shareholder Investment Plan, 520,000 shares were reserved for the continuous offering programs, and 422,651 shares were reserved for the employee savings plan.) 2,502.5 2,179.8 Retained earnings 2,425.9 2,081.9 Accumulated other comprehensive loss (201.5) (121.2)
Total common shareholders' equity 4,726.9 4,140.5 Total Capitalization $9,821.0 $9,483.1 Ste Notes to Consolidated FinancialStatements.
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el Ie.
Baltimore Gas and Electric Company and Subsidiaries Y'ar Ended December 31. 2004 2003 2002 (In millions)
Revenues Electric revenues $1,967.7 S1,921.6 S1,966.0 Gas revenues 757.0 726.0 581.3 Total revenues 2,724.7 2,647.6 2,547.3 Expenses Operating Expenses Electricity purchased for resale expenses 1,034.0 1,023.5 1,080.7 Gas purchased for resale 484.3 445.8 316.7 Operations and maintenance 427.8 406.2 366.6 Workforce reduction costs - 0.7 35.3 Depreciation and amortization 242.3 228.3 221.6 Taxes other than income taxes 164.9 158.1 160.1 Total expenses 2,353.3 2,262.6 2,181.0 Income from Operations 371.4 385.0 366.3 Other (Expense) Income (6.4) (5.4) 10.7 Fixed Charges Interest expense 97.3 112.8 142.1 Allowance for borrowed funds used during construction (1.1) (1.6) (1.5)
Total fixed charges 96.2 111.2 140.6 Income Before Income Taxes 268.8 268.4 236.4 Income Taxes Current 69.4 48.5 67.4 Deerred 34.9 58.5 28.0 Investment tax credit adjustments (1.8) (1.8) (2.1)
Total income taxes 102.5 105.2 93.3.
Net Income 166.3 163.2 143.1 Preference Stock Dividends 13.2 13.2 13.2 Earnings Applicable to Common Stock $ 153.1 $ 150.0 S 129.9 Baltimore Gas and Electric Company and Subsidiaries Year Ended December 31, 2004 2003 2002 (In millions)
Net Income S 153.1 $ 150.0 $ 129.9 Other comprehensive income Redassification of net gains on hedging instruments from OCI to net income, net of taxes of $0.0 (0.1) -
Unrealized gain on hedging instruments, net of taxes of $0.4 - 0.8 Comprehensive Income $ 153.0 S 150.8 $ 129.9 See Notes to ConsolidatedFinancialStatements Certainprior-year amounts have been reclassified to conform with the currentyear! presentation.
69
Baltimore Gas and Electric Company and Subsidiaries At December 31) 2004 2003 (In millions)
Assets Current Assets Cash and cash equivalents $ 8.2 $ 11.0 Accounts receivable (net of allowance for uncollectibles of $13.0 and $10.7, respectively) 381.8 354.8 Investment in cash pool, affiliated company 127.9 230.2 Accounts receivable, affiliated companies 1.0 4.5 Fuel stocks 86.5 62.8 Materials and supplies 34.6 29.9 Prepaid taxes other than income taxes 44.5 42.8 Other 7.2 9.9 Total current assets 691.7 745.9 Investments and Other Assets Regulatory assets (net) 195.4 229.5 Receivable, affiliated company 150.4 131.6 Other 134.2 140.6 Total investments and other assets 480.0 501.7 Utility Plant Plant in service Electric 3,7593 3,599.3 Gas 1,086.7 1,064.7 Common 478.4 467.7 Total plant in service 5,324.4 5,131.7 Accumulated depreciation (1,921.5) (1,807.7)
Net plant in service 3,402.9 3,324.0 Construction work in progress 83.1 130.5 Plant held for future use 5.2 4.5 Net utility plant 3,491.2 3,459.0 Total Assets S 4,662.9 S 4,706.6 See Notes to Consolidated Financil Statements.
Certain prior-year amounts have been classified to conform with the current year! presentation.
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Baltimore Gas and Electric Company and Subsidiaries At December 31, 2004 2003 (In millions)
Liabilities and Equity Current liabilities Current portion of long-term debt $ 165.9 $ 330.6 Accounts payable and accrued liabilities 125.4 101.2 Accounts payable and accrued liabilities, affiliated companies 146.1 151.7 Customer deposits 64.3 59.7 Accrued taxes 32.2 43.0 Accrued expenses and other 71.7 75.2 Total current liabilities 605.6 761.4 Deferred Credits and Other liabilities Deferred income taxes 608.0 576.2 Poirretirement and postemployment benefits 278.2 279.2 Deferred investment tax credits 16.9 18.7 Other 20.0 30.8 Total deferred credits and other liabilities 923.1 904.9 Long-termn Debt First refunding mortgage bonds of BGE 346.3 476.1 Other long-term debt of BGE 899.6 919.6 6.20% deferrable interest subordinated debentures due October 15, 2043 to wholly owned BGE Capital Trust 11 relating to trust preferred securities 257.7 257.7 Long-term debt of nonregulated businesses 25.0 25.0 Unamortized discount and premium (3.2) (4.1)
Current portion of long-term debt (165.9) (330.6)
Total long-tcrm debt 1,359.5 1,343.7 Minority Interest 18.7 18.9 Preference Stock Not Subject to Mandatory Redemption 190.0 190.0 Common Shareholder's Equity Common stock 912.2 912.2 Retained earnings 653.1 574.7 Accumulated other comprehensive income 0.7 0.8 Total common shareholder's equity 1,566.0 1,487.7 Commitments, Guarantees, and Contingencies (see Note 12)
Total Liabilities and Equity $ 4,662.9 $ 4,706.6 See Notes to ConsolidatedFinancialStatements.
Certainprior-year amounts have been reclkssified to conforn with the currentyears presentation.
71
RI. . .t -
Baltimore Gas and Electric Company and Subsidiaries Year Ended December 31, 2004 2003 2002 (In millions)
Cash Flows From Operating Activities Net income $ 166.3 $ 163.2 S 143.1 Adjustments to reconcile to net cash provided by operating activities Depreciation and amortization 257.4 242.7 234.4 Deferred income taxes 34.9 58.5 28.0 Investment tax credit adjustments (1.8) (1.8) (2.1)
Deferred fuel costs 6.0 (10.1) 23.9 Pension and postemployment benefits (16.6) (56.2) (40.7)
Allowance for equity funds used during construction (2.0) (3.0) (2.8)
Workforce reduction costs 0.7 35.3 Changes in Accounts receivable (27.0) 2.7 (62.3)
Receivables, affiliated companies 3.5 126.7 (67.8)
Materials, supplies, and fuel stocks (28.4) (20.3) 13.0 Other current assets 1.0 (0.4) 27.8 Accounts payable and accrued liabilities 24.2 8.0 39.6 Accounts payable and accrued liabilities, affiliated companies (5.6) 66.1 (7.0)
Other current liabilities (10.3) 14.0 (11.2)
Ocher (30.2) (22.9) 129.0 Net cash provided by operating activities 371.A 567.9 480.2 Cash Flows From Investing Activities Utility construction expenditures (excluding equity portion of allowance for funds used during construction) (246.4) (269.0) (202.5)
Change in cash pool at parent 1023 107.9 101.0 Sales of investments and other assets 4.9 - _
Other 2.7 1.8 (17.0)
Net cash used in investing acivities (136.5) (159.3) (118.5)
Cash Flows From Financing Activities Proceeds from issuance of long-term debt - 439.4 Repayment of long-term debt (149.8) (710.4) (575.5)
Preference stock dividends paid (13.2) (13.2) (13.2)
Distribution (to) from parent (74.7) (124.8) 200.0 Other - 1.2 (0.2)
Net cash used in financing activities (237.7) (407.8) (388.9)
Net (Decrease) Increase in Cash and Cash Equivalents (2.8) 0.8 (27.2)
Cash and Cash Equivalents at Beginning of YCar 11.0 10.2 37.4 Cash and Cash Equivalents at End of Year $ 8.2 $ 11.0 $ 10.2 Other Cash Flow Information:
Cash paid during the year for Interest (net of amounts capitalized) S 95.5 $ 120.6 S 147.5 Income taxes $ 80.7 S 24.7 S 36.6 See Notes so ConsolidatedFinancialStatements.
Certainprior-.year amounts have been reclssified to conform with the current SYars presentation.
72
llllllllll1k'nr-T7Kr-XqT-t M 117-FITT I 7W I Significant Accounting Policies Nature of Our Business The only time we do not use this method is if we can Constellation Energy Group, Inc. (Constellation Energy) is a exercise control over the operations and policies of the company.
North American energy company that conducts its business If we have control, accounting rules require us to use through various subsidiaries induding a merchant energy consolidation.
business and Baltimore Gas and Electric Company (BGE). Our merchant energy business is a competitive provider of energy The Cost Mlethod solutions for a variety of customers. BGE is a regulated electric We usually use the cost method if we hold less than a 20%
transmission and distribution utility company and a regulated voting interest in an investment. Under the cost method, we gas distribution utility company with a service territory that report our investment at cost in our Consolidated Balance covers the City of Baltimore and all or part of ten counties in Sheets. The only time we do not use this method is when we central Maryland. We describe our operating segments in Note 3. can exercise significant influence over the operations and policies This report is a combined report of Constellation Energy of the company. If we have significant influence, accounting and BGE. References in this report to 'We" and 'our" are to rules require us to use the equity method.
Constellation Energy and its subsidiaries. References in this report to the "regulated business(es)" are to BGE. Regulation of Electric and Gas Business The Maryland Public Service Commission (Maryland PSC) and Consolidation Policy the Federal Energy Regulatory Commission (FERC) provide the We use three different accounting methods to report our final determination of the rates we charge our customers for our investments in our subsidiaries or other companies: regulated businesses. Generally, we use the same accounting consolidation, the equity method, and the cost method. policies and practices used by nonregulated companies for financial reporting under accounting principles generally Consolidation accepted in the United States of America. However, sometimes We use consolidation for two types of entities: the Maryland PSC or the FERC orders an accounting treatment
- subsidiaries (other than variable interest entities) in different from that used by nonregulated companies to which we own a majority of the voting stock, and determine the rates we charge our customers.
- variable interest entities (VIEs) for which we are the
- When this happens, we must defer (include as an asset or primary beneficiary. Financial Accounting Standards liability in our Consolidated Balance Sheets and exclude from Board (FASB) Interpretation No. (FIN) 46R, our Consolidated Statements of Income) certain regulated Consolidation of Variable Interest Entities, requires us to business expenses and income as regulatory assets and liabilities.
use consolidation when we are the primary beneficiary We have recorded these regulatory assets and liabilities in our of a VIE, which means that we have a controlling Consolidated Balance Sheets in accordance with Statement of financial interest in a VIE. We discuss FIN 46R in Financial Accounting Standards (SFAS) No. 71, Accountingfor more detail later in this Note. the Effects of Certain Types of Regulation.
Consolidation means that we combine the accounts of these We summarize and discuss our regulatory assets and entities with our accounts. Therefore, our consolidated financial liabilities further in Note 6.
statements include our accounts, the accounts of our majority-owned subsidiaries that are not VIEs, and the accounts of VIEs Use of Accounting Estimates for which we are the primary beneficiary. We have not Management makes estimates and assumptions when preparing consolidated any entities for which we do not have a controlling financial statements under accounting principles generally voting interest. We eliminate all intercompany balances and accepted in the United States of America. These estimates and transactions when we consolidate these accounts. assumptions affect various matters, induding:
- our reported amounts of revenues and expenses in our The Equity AMethod Consolidated Statements of Income during the reporting W'e usually use the equity method to report investments, periods, corporate joint ventures, partnerships, and affiliated companies
- our reported amounts of assets and liabilities in our (including qualifying facilities and power projects) where we Consolidated Balance Sheets at the dates of the financial hold a 20% to 50% voting interest. Under the equity method, statements, and we report:
- our disclosure of contingent assets and liabilities at the
- our interest in the entity as an investment in our dates of the financial statements.
Consolidated Balance Sheets, and These estimates involve judgments with respect to
- our percentage share of the earnings from the entity in numerous factors that are difficult to predict and are beyond our Consolidated Statements of Income. management's control. As a result, actual amounts could materially differ from these estimates.
73
Reclassifications We record valuation adjustments to reflect uncertainties We have reclassified certain prior-year amounts for comparative associated with certain estimates inherent in the determination purposes. These reclassifications did not affect consolidated net of the fair value of mark-to-market energy assets and liabilities.
income for the years presented. To the extent possible, we utilize market-based data together with quantitative methods for both measuring the uncertainties Revenues for which we record valuation adjustments and determining the Nonregulated Businesses level of such adjustments and changes in those levels.
We record revenues from the sale of energy, energy-related We describe below the main types of valuation adjustments products, and energy services under the accrual method of we record and the process for establishing each. Generally, accounting in the period when we deliver energy commodities or increases in valuation adjustments reduce our earnings, and products, render services, or settle contracts. We use accrual decreases in valuation adjustments increase our earnings.
accounting for our merchant energy and other nonregulated However, all or a portion of the effect on earnings of changes in business transactions, including the generation or purchase and valuation adjustments may be offset by changes in the value of sale of electricity, gas, and coal as part of our physical delivery the underlying positions.
activities and for power, gas, and coal sales contracts that are not
- Close-out adjustment-represents the estimated cost to subject to mark-to-market accounting. Sales contracts that are close out or sell to a third-party open mark-to-market eligible for accrual accounting include non-derivative transactions positions. This valuation adjustment has the effect of and derivatives that qualify for and are designated as normal valuing long" positions (the purchase of a commodity) purchases and normal sales of commodities that will be at the bid price and 'short" positions (the sale of a physically delivered. We record accrual revenues, including commodity) at the offer price. We compute this settlements with independent system operators, on a gross basis adjustment based on our estimate of the bid/offer spread because we are a principal to the transaction and otherwise meet for each commodity and option price and the absolute the requirements of Emerging Issues Task Force (EITF) 03-11, quantity of our net open positions for each year. The Reporting Gains and Losses on Derivative Instruments That Are level of total dose-out valuation adjustments increases as Subject to FASB Statement No. 133, Accountingfor Derivative we have larger unhedged positions, bid-offer spreads Instruments and Hedging Activities, and Not Heldfor Trading increase, or market information is not available, and it Purposes, and EITF 99-19. Reporting Revenue Gross as a Principal decreases as we reduce our unhedged positions, bid-offer versus Net as an Agent. spreads decrease, or market information becomes We may make or receive cash payments at the time we available. To the extent that we are not able to obtain assume a power sale agreement for which the contract price observable market information for similar contracts, the differs from current market prices. We recognize the cash close-out adjustment is equivalent to the initial contract payment at inception in our Consolidated Balance Sheets as an margin, thereby recording no gain or loss at inception.
"Other current asset or liability" to the extent that performance In the absence of observable market information, there under the contract is less than 12 months and as an "Other is a presumption that the transaction price is equal to asset or liability" to the extent that performance under the the market value of the contract, and therefore we do not recognize a gain or loss at inception. We recognize contract is greater than 12 months. We amortize these assets and such gains or losses in earnings as we realize cash flows liabilities into revenues based on the expected cash flows under the contract or when observable market data provided by the contracts. becomes available.
We record revenues using the mark-to-market method of
- Credit-spread adjustment-for risk management accounting for derivative contracts for which we are not purposes we compute the value of our mark-to-market permitted to use accrual accounting or hedge accounting. We energy assets and liabilities using a risk-free discount discuss our use of hedge accounting in the Derivatives and rate. In order to compute fair value for financial Hedging Activities section later in this Note. These reporting purposes, we adjust the value of our mark-to-market activities include derivative contracts for energy mark-to-market energy assets to reflect the credit-and other energy-related commodities. Under the worthiness of each customer (counterparty) based upon mark-to-market method of accounting, we record the fair value either published credit ratings, where available, or of these derivatives as mark-to-market energy assets and liabilities equivalent internal credit ratings and associated default at the time of contract execution. We record the changes in probability percentages. We compute this adjustment by mark-to-market energy assets and liabilities on a net basis in applying the appropriate default probability percentage
'Nonregulated revenues" in our Consolidated Statements of to our outstanding credit exposure, net of collateral, for Income. Mark-to-market revenues include: each counterparty. The level of this adjustment increases
- gains or losses on new transactions at origination to the as our credit exposure to counterpanies increases, the extent permitted by applicable accounting rules, maturity terms of our transactions increase, or the credit
- unrealized gains and losses from changes in the fair ratings of our counterparties deteriorate, and it decreases value of open contracts, when our credit exposure to counterparties decreases,
- net gains and losses from realized transactions, and the maturity terms of our transactions decrease, or the
- changes in valuation adjustments. credit ratings of our counterparties improve.
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Mark-to-marker energy assets and liabilities consist of These costs are included in "Fuel and purchased energy derivative contracts. While some of these contracts represent expenses" in our Consolidated Statements of Income. We discuss commodities or instruments for which prices are available from certain of these separately below. We also include certain external sources, other commodities and certain contracts are not non-fuel direct costs, such as ancillary services, transmission actively traded and are valued using modeling techniques to costs, and brokerage fees in "Fuel and purchased energy determine expected future market prices, contract quantities, or expenses" in our Consolidated Statements of Income.
both. The market prices and quantities used to determine fair value reflect management's best estimate considering various Fuel Used to Generate Electricity and Purchases of Electricity factors, including dosing exchange and over-the-counter From Others quotations, time value, and volatility factors. However, future We assemble a variety of power supply resources, including market prices and actual quantities will vary from those used in baseload, intermediate, and peaking plants that we own, as well recording mark-to-market energy assets and liabilities, and it is as a variety of power supply contracts that may have similar possible that such variations could be material. characteristics, in order to enable us to meet our customers' During 2002, the FASB issued EITF 02-3, Issues Involved energy requirements, which vary on an hourly basis. We in Accounting for Derivative Contracts Heldfor Trading Purposes purchase power when our load-serving requirements exceed the and ContractsInvolved in Energy Trading and Risk Management amount of power available from our supply resources or when it Activities, that changed the accounting for energy contracts. is more economic to do so than to operate our power plants.
These changes included requiring the accrual method of The amount of power purchased depends on a number of accounting for energy contracts that are not derivatives and factors, including the capacity and availability of our power darifying when gains or losses can be recognized at the plants, the level of customer demand, and the relative economics inception of derivative contracts. This change applied of generating power versus purchasing power from the spot immediately to new contracts executed after October 25, 2002 market.
and applied to existing non-derivative energy-related contracts WVe also have acquired contracts and certain power purchase beginning January 1, 2003. agreements that qualify as operating leases. Under these In the first quarter of 2003, we adopted EITF 02-3 and operating leases, we are required to make fixed capacity recognized a $430.0 million pre-tax, or $266.1 million after-tax, payments, as well as variable payments based on the actual charge as a cumulative effect of change in accounting principle. output of the plants. We may make or receive cash payments at The contracts that were subject to the requirements of the time we acquire a contract or assume a power purchase EITF 02-3 were primarily our full requirements load-serving agreement when the contract price differs from current market contracts and unit-contingent power purchase contracts, which prices. We recognize the cash payment at inception in our are not derivatives. These contracts were entered into prior to Consolidated Balance Sheets as an "Other current asset or our shift to accrual accounting earlier in 2002. liability' to the extent that performance under the contract is Certain transactions entered into under master agreements less than 12 months and as an "Other asset or liability" to the and other arrangements provide our merchant energy business extent that performance under the contract is greater than with a right of setoff in the event of bankruptcy or default by 12 months. We amortize these assets and liabilities into fuel and the counterparry. We report such transactions net in our purchased energy expenses based on the expected cash flows Consolidated Balance Sheets in accordance with FASB provided by dte contracts.
Interpretation No. 39, Offietting ofAmrounts Related to Certain BGE purchased from our wholesale marketing and risk Contracts. management operation 100% of the energy and capacity We also include equity in earnings from our investments in required to meet its fixed-price standard offer service obligations qualifying facilities and power projects in "Nonregulated through June 30, 2004. BGE purchases 100% of the energy and revenues" in our Consolidated Statements of Income. capacity required to meet its residential fixed-price standard offer service obligations through June 30, 2006 from our wholesale Regulated Business marketing and risk management operation.
We record regulated revenues when we provide service to BGE is obligated to provide market-based standard offer customers. service to residential customers from July 1, 2006 through May 31, 2010, and for commercial and industrial customers for Fuel and Purchased Energy Expenses one, two, or four year periods beyond June 30, 2004, depending We incur costs for: on customer load. The POLR rates charged during these time
- the fuel we use to generate electricity, periods will recover BGE's wholesale power supply costs and
- purchases of electricity from others, and include an administrative fee. The administrative fee includes a
- natural gas and coal that we resell. shareholder return component and an incremental cost component.
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Bidding to supply BGE's standard offer service to SFAS No. 133. Accountingfor Derivative Insmrnients and commercial and industrial customers beyond June 30, 2004 Hedging Activities, as amended, requires that we recognize at fair occurred through a multi-round competitive bidding process in value all derivatives not qualifying for accrual accounting under 2004. As a result, BGE executed one and two-year contracts for the normal purchase and normal sale exception. We record commercial and industrial electric power supply. derivatives that are designated as hedges in "Risk management assets or liabilities" and derivatives not designated as hedges in Regulated Natural Gas "Mark-to-market energy assets or liabilities" in our Consolidated BGE charges its gas customers for the natural gas they purchase Balance Sheets.
from BGE using "gas cost adjustment clauses" set by the We record changes in the value of derivatives that are not Maryland PSC. Under these clauses, BGE defers the difference designated as cash-flow hedges in earnings during the period of between certain of its actual costs related to the gas commodity change. We record changes in the fair value of derivatives and what it collects from customers under the commodity designated as cash-flow hedges that are effective in offsetting the charge in a given period. BGE either bills or refunds its variability in cash flows of forecasted transactions in other customers the difference in the future. The Maryland PSC comprehensive income until the forecasted transactions occur. At approved a modification of the gas cost adjustment clauses to the time the forecasted transactions occur, we reclassify the provide a market-based rates incentive mechanism. Under the amounts recorded in other comprehensive income into earnings.
market-based rates incentive mechanism, BGEs actual cost of \Ve record the ineffective portion of changes in the fair value of gas is compared to a market index (a measure of the market derivatives used as cash-flow hedges immediately in earnings.
price of gas in a given period). The difference between BGE's We summarize our cash-flow hedging activities under SFAS actual cost and the marker index is shared equally between No. 133 and the income statement classification of amounts shareholders and customers. Effective November 2001, the reclassified from "Accumulated other comprehensive income Maryland PSC approved an order that modifies certain (loss)" as follows:
provisions of the market-based rates incentive mechanism. These provisions require that BGE secure fixed-price contracts for at Income Statement least 10%, but not more than 20%, of forecasted system supply Risk Derivative Classification requirements for the November through Mardi period. These Interest rate risk Interest rate swaps Interest expense fixed-price contracts are not subject to sharing under the market- associated with based rates incentive mechanism. new debt issuances Derivatives and Hedging Activities We are exposed to market risk, induding changes in interest Nonregulared Futures and Nonregulated rates and the impact of market fluctuations in the price and energy sales forward revenues transportation costs of electricity, natural gas, and other contracts commodities as discussed further in Note 13. In order to manage Nonregulated fuel Futures and Fuel and purchased these risks, we use both derivative and non-derivative contracts and energy forward energy expenses that may provide for settlement in cash or by delivery of a purchases contracts commodity, including:
- forward contracts, which commit us to purchase or sell Nonregulated gas Futures and Fuel and purchased energy commodities in the future, purchases for forward energy expenses
- futures contracts, which are exchange-traded resale contracts and standardized commitments to purchase or sell a price and basis commodity or financial instrument, or to make a cash swaps settlement, at a specific price and future date, Regulated gas Price and basis Fuel and purchased
- swap agreements, which require payments to or from purchases for swaps energy expenses counterparties based upon the differential between two resale prices for a predetermined contractual (notional) quantity, and
- option contracts, which convey the right to buy or sell a commodity, financial instrument, or index at a predetermined price.
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We designate certain derivatives as fair value hedges. We Taxes record changes in the fair value of these derivatives and changes We summarize our income taxes in Note 10. Our subsidiary in the fair value of the hedged assets or liabilities in earnings as income taxes are computed on a separate return basis. As you the changes occur. We summarize our fair value hedging read this section, it may be helpful to refer to Note 10.
activities and the income statement classification of changes in the fair value of these hedges and the related hedged items as Income Tax Expense follows: We have two categories of income tax expense-current and deferred. WVe describe each of these belowv Income Statement
- current income tax expense consists solely of regular tax Risk Derivative Classification less applicable tax credits, and
- deferred income tax expense is equal to the changes in Optimize mix of Interest rate swaps Interest expense the net deferred income tax liability, excluding amounts fixed and charged or credited to accumulated other comprehensive floating-rate debt income. Our deferred income tax expense is increased or Value of natural Forward contracts Fuel and purchased reduced for changes to the "Income taxes recoverable gas in storage and price and energy expenses through future rates (net)" regulatory asset (described basis swaps later in this Note) during the year.
We record changes in the fair value of interest rate swaps and the debt being hedged in "Risk management assets and Tax Credits We have deferred the investment tax credits associated with our liabilities" and 'Long-term debt" and changes in the fair value of regulated business and assets previously held by our regulated the gas being hedged and related derivatives in "Fuel stocks" and business in our Consolidated Balance Sheets. The investment tax
'Risk management assets and liabilities" in our Consolidated credits are amortized evenly to income over the life of each Balance Sheets. In addition, we record the difference between property. We reduce current income tax expense in our interest on hedged fixed-rate debt and floating-rate swaps in Consolidated Statements of Income for the investment tax "Interest expense" in the periods that the swaps settle. credits and other tax credits associated with our nonregulated businesses.
Credit Risk We have certain investments in facilities that manufacture Credit risk is the loss that may result from counterparty solid synthetic fuel produced from coal as defined under non-performance. We are exposed to credit risk, primarily Section 29 of the Internal Revenue Code for which we daim tax through our merchant energy business. We use credit policies to credits on our Federal income tax return. We recognize the tax manage our credit risk, including utilizing an established credit benefit of these credits in our Consolidated Statements of approval process, daily monitoring of counterparty limits, Income when we believe it is highly probable that the credits employing credit mitigation measures such as margin, collateral will be sustained.
or prepayment arrangements, and using master netting agreements. Were measure credit risk as the replacement cost for Deferred Income Tax Assets and Liabilities open energy commodity and derivative positions (both We must report some of our revenues and expenses differently mark-to-market and accrual) plus amounts owed from for our financial statements than for income tax return purposes.
counterparties for settled transactions. The replacement cost of The tax effects of the temporary differences in these items are open positions represents unrealized gains, less any unrealized reported as deferred income tax assets or liabilities in our losses where we have a legally enforceable right of setoff. Consolidated Balance Sheets. We measure the deferred income Elearic and gas utilities, cooperatives, and energy marketers tax assets and liabilities using income tax rates that are currently comprise the majority of counterparties underlying our assets in effect.
from our wholesale marketing and risk management activities. A portion of our total deferred income tax liability relates WXe held cash collateral from these counterparties totaling to our regulated business, but has not been reflected in the rates
$145.9 million as of December 31, 2004 and $121.9 million as we charge our customers. We refer to this portion of the liability of December 31, 2003. These amounts are included in as 'Income taxes recoverable through future rates (net)." WVe
'Customer deposits and collateral" in our Consolidated Balance have recorded that portion of the net liability as a regulatory Sheets. asset in our Consolidated Balance Sheets. 'We discuss this further in Note 6.
State and Local Taxes State and local income taxes are included in "Income taxes" in our Consolidated Statements of Income.
BGE also pays Maryland public service company franchise tax on distribution, and delivery of electricity and natural gas.
We include the franchise tax in "Taxes other than income taxes" in our Consolidated Statements of Income.
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Earnings Per Share Year Ended December 31, 2004 2003 2002 Basic earnings per common share (EPS) is computed by dividing earnings applicable to common stock by the weighted-average (In millions, except per share number of common shares outstanding for the year. Diluted amounts)
EPS reflects the potential dilution of common stock equivalent Net income, as reported $539.7 $277.3 $525.6 shares that could occur if securities or other contracts to issue Add: Stock-based compensation common stock were exercised or converted into common stock. determined under intrinsic Our dilutive common stock equivalent shares were 1.0 million value method and included in in 2004 and 0.4 million in 2003 and consisted of stock options. reported net income, net of There were no stock options excluded from the computation of related tax effects 13.2 12.0 6.4 diluted EPS for the year ended December 31, 2004. Stock Deduct: Stock-based options to purchase approximately 1.2 million shares in 2003 compensation expense and approximately 4.1 million shares in 2002 were not dilutive determined under fair value and were excluded from the computation of diluted EPS for based method for all awards, these respective years. net of related tax effects (21.3) (20.7) (17.1)
Pro-forma net income $531.6 $268.6 $514.9 Stock-Based Compensation Under our long-term incentive plans, we have granted stock Earnings per share:
options, performance-based units, performance and service-based Basic-as reported $ 3.14 $ 1.67 $ 3.20 restricted stock, and equity to officers, key employees, and Basic-pro-forma $ 3.09 $ 1.62 $ 3.14 members of the Board of Directors. We discuss this in more Diluted-as reported $ 3.12 $ 1.66 $ 3.20 detail in Note 14. Diluted-pro-forma $ 3.07 $ 1.61 $ 3.13 As permitted by SFAS No. 123, Accoueingtfor Stock-Based In the table above, the stock-based compensation expense Compensation, we presently measure our stock-based included in reported net income, net of related tax effects is as compensation using the intrinsic value method in accordance follows:
with Accounting Principles Board Opinion (APB) No. 25,
- in 2004, $13.2 million after-tax, or $21.4 million Acrountingfor Stock Issued to Enployees, and related pre-tax comprised of $1.0 million of pre-tax expense for interpretations. certain stock options, $17.0 million for restricted stock.
Our stock options are granted with an exercise price not $2.9 million for performance-based units, and less than the market value of the common stock at the date of $0.5 million for equity grants, grant. Accordingly, no compensation expense is recorded for
- in 2003, $12.0 million after-tax, or $18.6 million these awards. However, when we grant options subject to a pre-tax comprised of $1.8 million of pre-tax expense for contingency, we recognize compensation expense when options certain stock options, $16.4 million for restricted stock, granted have an exercise price less than the market value of the and $0.4 million for equity grants, and underlying common stock on the date the contingency is
- in 2002, a $6.4 million afier-tax, or S10.1 million satisfied. We amortize compensation expense for restricted stock pre-tax comprised of $3.0 million of pre-tax expense for and stock units over the performance/service period, which is certain stock options, $6.6 million for restricted stock, typically a one to five-year period. and $0.5 million for equity grants.
The following table illustrates the effect on net income and In December 2004, the FASB issued SFAS No. 123R.
earnings per share had we applied the fair value recognition Share-Based Payment, which changed the accounting for stock-provision of SFAS No. 123 to all outstanding stock options and based compensation to require companies to expense stock stock awards in each year. options and other equity awards based on their grant-date fair values. We discuss SPAS No. 123R in more detail in the Accounting Standards Issued section later in this Note.
Cash and Cash Equivalents All highly liquid investments with original maturities of three months or less are considered cash equivalents.
Accounts Receivable and Allowance for Uncollectibles Accounts receivable are stated at the historical carrying amount net of write-offs and allowance for uncollectibles. We establish an allowance for uncollectibles based on our expected exposure to the credit risk of customers based on a variety of factors.
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Materials, Supplies, and Fuel Stocks Evaluation of Assets for Impairment and Other Than We record our fuel stocks, emissions credits, coal held for resale, Temporary Decline In Value and materials and supplies at the lower of cost or market. We Long-Lived Assets determine cost using the average cost method for all of our We are required to evaluate certain assets that have long lives inventory other than our coal held for resale for which we use (for example, generating property and equipment and real estate) the specific identification method. to determine if they are impaired when certain conditions exist.
SFAS No. 144, Acrountingfor the Impairment or Disposal of Real Estate Projects Long-Lived Assets, provides the accounting requirements for In Note 4, we summarize the real estate projects that are in our impairments of long-lived assets. We are required to test our Consolidated Balance Sheets. At December 31, 2004, the long-lived assets for recoverability whenever events or changes in projects primarily consist of approximately 190 acres of land circumstances indicate that their carrying amount may not be holdings in various stages of development located at 4 sites in recoverable.
the central Maryland region, including an operating waste water We determine if long-lived assets are impaired by treatment plant located in Anne Arundel County, Maryland. comparing their undiscounted expected future cash flows to their The costs incurred to develop properties are included as part of carrying amount in our accounting records. We would record an the cost of the properties. impairment loss if the undiscounted expected future cash flows from an asset were less than the carrying amount of the asset.
Financial Investments and Trading Securities We are also required to evaluate our equity-method and In NAte 4, we summarize the financial investments that are in cost-method investments (for example, in partnerships that own our Consolidated Balance Sheets. power projects) for impairment. APB No. 18, The Equity Method SFAS No. 115, Accountingfor Certain Investments in Debt of Accountingfor Investments in Common Stock, provides the and Equity Securities, applies particular requirements to some of accounting requirements for these investments. The standard for our investments in debt and equity securities. We report those determining whether an impairment must be recorded under investments at fair value, and we use either specific identification APB No. 18 is whether the investment has experienced a loss in or average cost to determine their cost for computing realized value that is considered an "other than a temporary" decline in gains or losses. We classify these investments as either trading value.
securities or available-for-sale securities, which we describe We use our best estimates in making these evaluations and separately below. We report investments that are not covered by consider various fctors, including forward price curves for SPAS No. 115 at their cost. energy, fuel costs, legislative initiatives, and operating costs.
However, actual future market prices and project costs could Trading Securities vary from those used in our impairment evaluations, and the In 2002, our other nonregulated businesses classified some of impact of such variations could be material.
their investments in marketable equity securities and financial limited partnerships as trading securities. We included any Debt and Equity Securities unrealized gains or losses on these securities in 'Nonregulated Our investments in debt and equity securities, which primarily revenues" in our Consolidated Statements of Income. We no consist of our nudcear decommissioning trust fund investments, longer hold any investments classified as trading securities for are subject to impairment evaluations under SFAS No. 115, which unrealized gains or losses are recognized in our Accountingfor Certain Investments in Debt andEquity Securities.
Consolidated Statements of Income. SFAS No. 115 requires us to determine whether a decline in fair value of an investment below the amortized cost basis is other Available-for-Sale Securities than temporary. If we determine that the decline in fair value is We dassify our investments in the nuclear decommissioning judged to be other than temporary, the cost basis of the trust funds as available-for-sale securities. We describe the. investment must be written down to fir value as a new cost nuclear decommissioning trusts and the related asset retirement basis. We discuss EITF 03-1, The Meaning of Other Than obligations in the "Nuclear Decommissioning" section of this Temporary Impairment and Its Application to Certain Investments, Note. In addition, we have investments in trust assets securing in the Accounting Standards Issued section later in this note.
certain executive benefits that are classified as available-for-sale securities.
We include any unrealized gains or losses on our available-for-sale securities in "Accumulated other comprehensive income" in our Consolidated Statements of Common Shareholders' Equity and Comprehensive Income and Consolidated Statements of Capitalization.
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Intangible Assets When we retire or dispose of property, plant and Goodwill is the excess of the purchase price of an acquired equipment, we remove the asset's cost from our Consolidated business over the fair value of the net assets acquired. We Balance Sheets. WYc charge this cost to accumulated depreciation account for goodwill and other intangibles under the provisions for assets that were depreciated under the composite, of SFAS No. 142, Goodwill and Other Intangible Assets. We do straight-line method. This includes regulated property, plant and not amortize goodwill and certain other intangible assets. SFAS equipment and nonregulated generating assets transferred to our No. 142 requires us to evaluate goodwill and other intangibles merchant energy business. For all other assets, we remove the for impairment at least annually or more frequently if events and accumulated depreciation and amortization amounts from our circumstances indicate the business might' be impaired. Goodwill Consolidated Balance Sheets and record any gain or loss in our is impaired if the carrying value of the business exceeds fair Consolidated Statements of Income.
value. Annually, we estimate the fair value of the businesses we The costs of maintenance and certain replacements are have acquired using techniques similar to those used to estimate charged to 'Operating expenses" in our Consolidated Statements future cash flows for long-lived assets as previously discussed. If of Income as incurred.
the estimated fair value of the business is less than its carrying value, an impairment loss is required to be recognized to the DepreciationExpense extent that the carrying value of goodwill is greater than its fair We compute depreciation for our generating, electric value. SFAS No. 142 also requires the amortization of intangible transmission and distribution, and gas facilities over the assets with finite lives. We discuss the changes in our intangible estimated useful lives of depreciable property using the following assets in more detail in Note 5. methods:
- the composite, straight-line rates method, approved by Property, Plant and Equipment, Depreciation, the Maryland PSC, applied to the average investrient, Amortization, and Accretion of Asset Retirement adjusted for anticipated costs of removal less salvage, in Obligations classes of depreciable property based on an average rate We report our property, plant and equipment at its original cost, of approximately 3.5% per year for our regulated unless impaired under the provisions of SFAS No. 144. business, Our original costs include
- the composite, straight-line rates applied to the average
- material and labor, investment, in classes of depreciable property based on
- contractor costs, and an average rate of approximately 2.5% per year for the
- construction overhead costs, financing costs, and costs generating assets transferred from BGE to our merchant for asset retirement obligations (where applicable). energy business, or We own an undivided interest in the Keystone and
- the modified units of production method (greater of Conemaugh electric generating plants in Western Pennsylvania, straight-line method or units of production method) for as well as in the transmission line that transports the plants' other generating assets.
output to the joint owners' service territories. Our ownership Other assets are depreciated using the straight-line method interests in these plants are 20.99% in Keystone and 10.56% in and the following estimated useful lives:
Conemaugh. These ownership interests represented a net investment of $191 million at December 31, 2004 and Asset Estimated Useful Lives
$189 million at December 31, 2003. Each owner is responsible for financing its proportionate share of the plants' working Building and improvements 20 - 50 years funds. Working funds are used for operating expenses and Office equipment and furniture 3- 20 years capital expenditures. Operating expenses related to these plants Transportation equipment 5- 15 years are included in 'Operating expenses" in our Consolidated Computer software 3- 10 years Statements of Income. Capital costs related to these plants are included in 'Nonregulated property, plant and equipment' in Amortization Espense our Consolidated Balance Sheets. Amortization is an accounting process of reducing an amount in The 'Nonregulated property, plant and equipment" in our our Consolidated Balance Sheets over a period of time that Consolidated Balance Sheets includes nonregulated generation. approximates the useful life of the related item. When we reduce construction work in progress of $206.4 million at amounts in our Consolidated Balance Sheets, we increase December 31, 2004 and $184.4 million at December 31, 2003. amortization expense in our Consolidated Statements of Income.
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Accretion Epense Nuclear Fuel SFAS No. 143, Accountingfor Asset Retirement Obligations We amortize nuclear fuel based on the energy produced over provides the accounting requirements for recognizing an the life of the fuel including the quarterly fees we pay to the estimated liability for legal obligations associated with the Department of Energy for the future disposal of spent nuclear retirement of tangible long-lived assets. At December 31, 2004, fuel. These fees arc based on the kilowatt-hours of electricity
$821.8 million of our total asset retirement obligation of sold. We report the amortization expense for nuclear fuel in
$825.0 million was associated with our nuclear power plants- "Fuel and purchased energy expenses" in our Consolidated Calvert Cliffs, Nine Mile Point, and Ginna. We have also Statements of Income.
recorded asset retirement obligations associated with our other generating facilities and certain other long-lived assets. We Nuclear Decommissioning record a liability when we are able to reasonably estimate the Effective January 1, 2003, we began to record decommissioning fair value of any future legal obligations associated with expense for Calvert Cliffs Nuclear Power Plant (Calvert Cliffs) retirement char have been incurred and capitalize a in accordance with SFAS No. 143 Acesuntingfor Asset corresponding amount as part of the book value of the related Retirement Obligations (SFAS 143). The 'Asset retirement long-lived assets. The increase in the capitalized cost is included obligations" liability associated with the decommissioning of in determining depreciation expense over the estimated useful Calvert Cliffs w as $286.1 million at December 31, 2004 and life of these assets. Since the fair value of the asset retirement $265.5 million at December 31, 2003. Our contributions to obligations is determined using a present value approach, the nuclear decommissioning trust funds for Calvert Cliffs were accretion of the liability due to the passage of time is $22.0 million for 2004, $13.2 million for 2003 and recognized each period to 'Accretion of asset retirement $17.6 million for 2002. Under the Maryland PSC's order obligations" in our Consolidated Statements of Income until dcrcgulating elcaric generation, BGE's customers must pay a the settlement of the liability. We record a gain or loss when total of $520 million in 1993 dollars, adjusted for inflation, to the liability is settled after retirement. decommission Calvert Cliffs. BGE is collecting this amount on The change in our 'Asset retirement obligations" liability behalf of and passing it to Calvert Cliffs Nuclear Power during 2004 was as follows: Plant, Inc. Calvert Cliffs Nuclear Power Plant, Inc. is responsible for any difference between this amount and the actual costs to decommission the plant.
(In millinsJ)
We began to record decommissioning expense for Nine Liability at January 1, 2004 $595.9 Mile Point Nuclear Station (Nine Mile Point) in accordance Liabilities incurred 177.9 Liabilities settled with SPAS No. 143 on January 1,2003. The "Asset retirement Accretion expense 53.2 obligations" liability associated with the decommissioning was Other (2.0) $351.5 million at December 31, 2004 and $326.2 million at Revisions to cash flows December 31, 2003. WVe determined that the decommissioning Liability at December 31, 2004 $825.0 trust funds established for Nine Mile Point are adequately funded to cover the future costs to decommission the plant and
'Liabilities incurred" in the table above primarily reflect as such, no contributions were made to the trust funds during the asset retirement obligation recorded in connection with our the years ended December 31, 2004, 2003, and 2002.
acquisition of the R.E. Ginna Nuclear Power Plant (Ginna). Upon the dosing of the Ginna acquisition in 2004, the We discuss the acquisition of Ginna in more detail in Note 15. seller transferred $200.8 million in decommissioning funds. In "Other" in the table above represents the asset retirement return, we assumed all liability for the costs to decommission obligation associated with our geothermal facility in Hawaii the unit. Wc believe that this transfer will be sufficient to cover that was sold in the quarter ended June 2004. At the time of the future costs to decommission the plant and as such, no the sale, the asset retirement obligation was transferred to the contributions were made to the trust funds during the year buyer of the geothermal facility. We discuss the sale of the ended December 31, 2004. Effecaive June 2004, we began to geothermal facility in more detail in Note 2. record decommissioning expense for Ginna in accordance with SFAS No. 143. The PAsset retirement obligations" liability associated with the decommissioning was $184.2 million at December 31, 2004. We discuss the acquisition of Ginna in more detail in Note 15.
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In accordance with Nuclear Regulatory Commission Long-Term Debt (NRC) regulations, we maintain external decommissioning We defer all costs related to the issuance of long-term debt.
trusts to fund the costs expected to be incurred to These costs include underwriters' commissions, discounts or decommission Calvert Cliffs, Nine Mile Point and Ginna. The premiums, other costs such as legal, accounting, and regulatory NRC requires utilities to provide financial assurance that they fees, and printing costs. We amortize these costs into interest will accumulate sufficient finds to pay for the cost of nuclear expense over the life of the debt.
decommissioning. The assets in the crusts are reported in When BGE incurs gains or losses on debt that it retires "Nuclear decommissioning trust funds" in our Consolidated prior to maturity, it amortizes those gains or losses over the Balance Sheets. These amounts are legally restricted for funding remaining original life of the debt.
the costs of decommissioning. We classify the investments in the nuclear decommissioning trust funds as available-for-sale Accounting Standards Issued securities, and we report these investments at fair value in our SFAS 123 Revised Consolidated Balance Sheets as previously discussed in this In December 2004, the FASB issued SFAS No. 123 Revised Note. Investments by nuclear decommissioning trust funds are (SEAS No. 123R), S/,are-Based Payment. SFAS No. 123R guided by the "prudent man" investment principle. The funds revises SFAS No. 123, Accountingfor Stock-Based Compensation, are prohibited from investing directly in Constellation Energy and supersedes APB No. 25, Accountingfor Stock Issued to or its affiliates and any other entity owning a nuclear power Employees. SFAS No. 123R requires companies to recognize plant. compensation expense for all equity-based compensation awards As the owner of Calvert Cliffs, we are required, along issued to employees. Equity-based compensation awards include with other domestic utilities, by the Energy Policy Act of 1992 stock options, restriacd stock, and any other share-based to make contributions to a fund for decommissioning and payments. Under SFAS 123R, we must recognize compensation decontaminating the Department of Energy's uranium cost over the period during which an employee is required to enrichment facilities. The contributions are paid by BGE and provide service in exchange for the award. We estimate the fair generally payable over 15 years with escalation for inflation and value of employee stock options using option-pricing models are based upon the proportionate amount of uranium enriched adjusted for the unique characeristics of those instruments.
by the Department of Energy for each utility. BGE amortizes We plan to adopt SFAS No. 123R effective July 1, 2005 the deferred costs of decommissioning and decontaminating the using the Modified Prospective Application method without Department of Energy's uranium enrichment facilities. The restatement of prior interim periods. Under this method, we previous owners retained the obligation for Nine Mile Point will begin to amortize compensation cost for the remaining and Ginna. portion of our outstanding awards on the adoption date for which the requisite service has nor yet been rendered.
Capitalized Interest and Allowance for Funds Used Compensation cost for these awards will be based on the fair During Construction value of those awards as disclosed on a pro-forma basis under CapitalizedInterest SEAS 123 in the Stock-Based Compensation section of this note.
Our nonregulated businesses capitalize interest costs under We will account for awards that are granted, modified, or SFAS No. 34, CapitalizingInterest Costs, for costs incurred to settled after the adoption date in accordance with SFAS finance our power plant construction projects, real estate No. 123R.
developed for internal use, and other capital projects. Currently, we are evaluating the impact of adopting this standard on our financial results. However, we do not believe Allowancefor Funds Used During Construction (AFC) the impact of this standard on our ongoing operating results BGE finances its construction projects with borrowed funds will be materially different than the results as discloscd on a and equity funds. BGE is allowed by the Maryland PSC to pro-forma basis in the Stock-Based Compensation section of this record the costs of these funds as part of the cost of note.
construction projects in its Consolidated Balance Sheets. BGE does this through the AFC, which it calculates using rates EITF 03-1 authorized by the Maryland PSC. BGE bills its customers for In March 2004, the EITF reached a consensus on Issue 03-1, the AFC plus a return after the utility property is placed in The leaning of Other Than Temporary Impairment and Its service. Application to Certain Investments, related to measurement and The AFC rates are 9.4% for electric plant, 8.6% for gas recognition criteria that would have become effective July 1, plant, and 9.2% for common plant. BGE compounds AFC 2004. In accordance with Nuclear Regulatory Commission annually. regulations, we do not manage the day-co-day activities of our nuclear decommissioning trust funds. As a result, a strict interpretation of EITF 03-1 would indicate that we do not have the ability and intent to hold investments whose market value is less than our cost until recovery.
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In September 2004, the FASB issued FSP EITF 03-1-1 FIN 46/FIN 46R which delayed the implementation of the measurement and In January 2003, the FASB issued FIN 46, Consolidation of recognition criteria until additional implementation guidance Variable Interest Entities, which was subsequently revised in its could be developed. If relief from the strict interpretation entirety with the issuance of FIN 46R in December 2003.
previously discussed is not included in the pending FASB FIN 46R establishes conditions under which an entity implementation guidance, we would be required to record into must be consolidated based upon variable interests rather than earnings any decline in market value below the cost of our voting interests. Variable interests are ownership interests or nuclear decommissioning investments. If this interpretation of contractual relationships that enable the holder to share in the EITF 03-1 had become cffcaive at December 31, 2004, we financial risks and rewards resulting from the activities of a would have been required to record a pre-tax charge of Variable Interest Entity (VIE). A VIE can be a corporation, approximately $2.8 million. We have approximately Si billion partnership, trust, or any other legal structure used for business invested in nuclear decommissioning trust assets. Therefore, a purposes. An entity is considered a VIE under FIN 46R if it one percent decline in all of our investments below book value does not have an equity investment sufficient for it to finance would result in approximately a S10 million pre-rax charge. We its activities without assistance from variable interest holders or cannot predict the outcome of the implementation guidance. if its equity investors lack any of the following characteristics of However, the impact could be material to our financial results. a controlling financial interest:
- control through voting rights, Accounting Standards Adopted
- obligation to absorb expected losses, or FSP 106-2
- right to receive expected residual returns.
In May 2004, FASB Staff Position (FSP) 106-2 was issued, FIN 46R requires us to consolidate VIEs for which we are which addresses accounting and disclosure requirements the primary beneficiary and to disclose certain information pertaining to the Medicare Prescription Drug Improvement and about significant variable interests we hold. The primary Modernization Act of 2003. FSP 106-2 is cffcaive July 1, beneficiary of a VIE is the entity that receives the majority of a 2004. We discuss the impacts of the Medicare Prescription VIE's expected losses, expected residual returns, or both.
Drug Improvement and Modernization Act of 2003 recorded FIN 46R was cffective March 31, 2004, for all VIEs in accordance with FSP 106-2 in Note 7. except special purpose entities (SPEs), for which the effective date was December 31, 2003. Therefore, at December 31, FSP 109-2 2003, we and BGE deconsolidated BGE Capital Trust II, an In the fourth quarter of 2004, the President signed into law SPE established to issue trust preferred securities as described the American Jobs Creation Act of 2004 (the Act) that in Note 9, because BGE is not its primary beneficiary. As a provides a temporary incentive for U. S. multinational result, we currently record $257.7 million of deferrable interest companies to repatriate foreign earnings. The temporary subordinated debentures due to BGE Capital Trust 11, and incentive for U. S. companies to repatriate accumulated foreign $7.7 million equity investment in BGE Capital Trust 11 in earnings provides an elective, 85 percent dividends received "Other assets" in our and BGE's Consolidated Balance Sheets.
deduction for certain dividends from controlled foreign As a result of adopting the remainder of the provisions of corporations that will be reinvested in the United States. FIN 46R as of March 31, 2004, we were not required to In response to the issuance of the Act, in December 2004, consolidate or deconsolidate any non-SPE entities with which the FASB issued FSP No. 109-2, Accounting and Disclosure we are involved through variable interests. We had preliminarily Guidancefor the Foreign Earnings RepatriationProvision within determined that we were the primary beneficiary for an the American Jobs CreationAct of2004. FSP No. 109-2 unconsolidated investment in a hydroelectric generating plant provides companies with additional time to evaluate the impact located in Pennsylvania because our two-thirds interest in the of the Act and provides accounting and disclosure guidance for plant's earnings are disproportionate to our 50% voting applying the foreign earnings repatriation provisions of the Act. interest. However, we subsequently determined that the entity In December 2004, we repatriated $15 million in the form of is not a VIE because less than substantially all of the plant's a dividend from our Panamanian distribution faclity, which we activities are conducted on our behalf, and therefore we do not plan to reinvest in the United States to take advantage of the have to consolidate the entity.
dividends received deduction. Since we previously provided We have a significant interest in the following VlEs for federal deferred income taxes on the earnings of our foreign which we are not the primary beneficiary:
subsidiary that issued the dividend, in 2004 we recorded a net reduction of $4.4 million in federal tax expense in connection Nature of Date of with the earnings repatriation. VIE Involvement. Involvement Power projects and Equity investment Prior to 2003 fuel supply entities and guarantees Natural gas Volumetric and price July 2003 producing facility swap 83
The following is summary information about these entities The maximum exposure to loss represents the loss that we as of December 31, 2004: would incur in the unlikely event that our interests in all of these entities were to become worthless and we were required to fund the full amount of all guarantees associated with these (In millions) entities. Our maximum exposure to loss as of December 31, Total assets $291.1 2004 consists of the following:
Total liabilities 147.0
- the carrying amount of our investment totaling Our ownership interest 41.1 $41.1 million, Other ownership interests 103.0
- debt and performance guarantees totaling Our maximum exposure to loss 75.3 $13.4 million, and
- volumetric and price variability of up to $20.8 million associated with a natural gas producer swap, based on contract volumes and gas prices as of December 31, 2004.
We assess the risk of a loss equal to our maximum exposure to be remote.
2 Workforce Reduction, Impairment Losses, and Other Events 2004 Events The fair value of the facility as of March 31, 2004, based on the bids under consideration, was below carrying value.
Pre-Tax After-Tax Therefore, we recorded a $71.6 million pre-tax, or $47.3 million (In millions) after-tax, impairment charge during the first quarter of 2004.
Loss from discontinued operations S(75.6) $(49.1) We reported the after-tax impairment charge as a component of Recognition of 2003 synthetic fuel tax 'Loss from discontinued operations" in our Consolidated credits - 35.9 Statements of Income. Additionally, we recognized $1.5 million Workforce reduction costs (9.7) (5.9) pre-tax, or $1.0 million after-tax, of earnings from the facility Impairment losses and other costs (3.7) (2.2) for the quarter ended Mardc 31, 2004 as a component of "Loss Net loss on sales of investments and from discontinued operations."
other assets (1.2) (0.6) In June 2004, we completed the sale of the facility. Based on the final sales price and other costs incurred over the Total special items $(90.2) $(21.9) remainder of the year, we recognized an additional loss of
$5.5 million pre-tax, or $2.8 million after-tax. The sale of this Loss from Discontinued Operations facility was reflected in our merchant energy business reportable In the fourth quarter of 2003, we began to re-evaluate our segment. In addition, as a result of a current audit relating to strategy regarding our geothermal generating facility in Hawaii. prior tax years for this facility, we could record additional gain The reevaluation of our strategy included soliciting bids to or loss from discontinued operations in future periods.
determine the level of interest in the facility. As of We have not reclassified the prior year results of operations, December 31, 2003, management determined that disposal of which were reported under the equity method as 'Nonregulated the facility was more likely than not to occur. As a result, we revenues," based on the immateriality of the amounts involved.
evaluated the facility for impairment as of December 31, 2003, The facility had a $4.0 million net loss, including a $1.1 million in accordance with SFAS No. 144, Accountingfor the Impairment cumulative cffect of change in accounting principle for the or Disposal ofLong-LivedAssets. and determined that the facility adoption of SFAS No. 143, during 2003.
was not impaired primarily due to indicative bids from third parties above the carrying value of the assets.
In March 2004, after reviewing final binding offers, management committed to a plan to sell the facility that met the "held for sale" criteria under SFAS No. 144. Under SFAS No. 144, we record assets and liabilities held for sale at the lesser of the carrying amount or fair value less cost to sell.
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Synthetic Fuel Tax Credits 2003 Events In 2003, we purchased 99% ownership in a South Carolina facility that produces synthetic fuel. We did not recognize in our Pre-Tax After-Tax Consolidated Statements of Income the tax benefit of (In millions)
$35.9 million for credits claimed on our South Carolina facility Workforce reduction costs $ (2.1) $ (1.3) in 2003 pending receipt of a favorable private letter ruling. In Reduction of financial investment (0.6) (0.4)
April 2004, we received a favorable private letter ruling. We Net gain on sales of investments and believe receipt of the private letter ruling provides assurance that other assets 26.2 16.4 it is highly probable that the credits will be sustained. Therefore, Total special items $23.5 $14.7 we recognized the tax benefit of $35.9 million in our Consolidated Statements of Income in 2004. We discuss the synthetic fuel tax credits in more detail in Note 10. Workforce Reduction Costs During 2003, we recorded $2.1 million in pre-tax expense, or Wiorkforce Reduction Costs $1.3 million after-tax. of which BGE recorded $0.7 million In the fourth quarter of 2004, we approved a restructuring of pre-tax, associated with deferred payments to employees eligible the work forces of the Nine Mile Point and Calvert Cliffs for the 2001 Voluntary Special Early Retirement Program.
nudear generating stations that was effective in January 2005. In In 2004, we completed the 2002 workforce reduction connection with this restructuring, approximately 108 employees programs. As a result, no involuntary severance liability was will receive severance and other benefits under our existing recorded under EITF 94-3, Liability Recognition for Certain benefit programs. At December 31, 2004, we accrued the Employee Termination Benefits and Other Costs to Exit an Activity estimated total cost of this reduction in workforce of (including Certain Costs Incsrred in a Restructuring), at
$9.7 million pre-tax, or $5.9 million after-tax, in accordance December 31, 2004.
with applicable accounting requirements.
Impairment Losses and Other Costs Impairment ofFinancialInvestment In 2003, our other nonregulated businesses recognized an Our other nonregulated businesses recognized a pre-tax impairment loss of $0.6 million pre-tax, or $0.4 million impairment loss of $3.7 million, or $2.2 million after-tax, after-tax, related to the dedine in value of our investment in an during the year ended December 31, 2004 related to an other airplane.
than temporary dedine in fair value of certain financial investments. Net Gain on Sales of Investments and Other Assets During 2003, our other nonregulated businesses recognized Net Loss on Sales of Investmnents and Other Assets $26.2 million of pre-tax, or $16.4 million after-tax, gains on the Our other nonregulated businesses recognized a pre-tax loss of sales of non-core assets as follows:
$1.2 million, or $0.6 million after-tax, during the year ended
- a $13.1 million pre-tax gain on the sale of certain real December 31, 2004 on the sale of non-core assets as follows: estate,
- a $1.1 million pre-tax gain in the first quarter on an
- a $7.2 million pre-tax gain on the sale of an oil tanker installment sale of real estate, to the U.S. Navy,
- a $0.4 million pre-tax gain in the first quarter on the
- a $5.3 million pre-tax gain on the favorable settlement sale of a financial investment, of a contingent obligation we had previously reserved
- a $3.3 million pre-tax gain in the second quarter on the relating to the sale of our Guatemalan power plant sale of a financial investment, operation in the fourth quarter of 2001, and
- a $1.1 million pre-tax gain in the second quarter on the
- a $0.6 million pre-tax gain on the sale of financial sale of real estate, . investments.
- a $7.5 million pre-tax loss in the third quarter on the sale of a financial investment, and Hurricane Isabel
- a $0.4 million pre-tax gain in the fourth quarter on the In September 2003, Hurricane Isabel caused damage to the sale of a financial investment, electric and gas distribution system of BGE. As a result, BGE incurred capitalized costs of $32.0 million and maintenance expenses of $36.8 million, or $22.2 million after-tax to restore its distribution system. The maintenance expenses induded
$32.1 million pre-tax, or $19.4 million after-tax, of incremental expenses.
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2002 Events
- We recorded $29.6 million of settlement charges related to our pension plans under SFAS No. 88, Emplayeri Pra-Tax After-Tax Accountingfor Settlements and Curtailments of Defined (in millions) Benefit Pension Plans andfor Termination Benefits. These Workforce reduction costs: charges reflect the recognition of actuarial gains and Costs associated with 2001 programs $ (50.8) $ (30.8) losses associated with employees who have retired and Costs associated with programs taken their pension in the form of a lump-sum initiated in 2002 (12.0) (7.2) payment. Under SFAS No. 88, the settlement charge Total workforce reduction costs (62.8) (38.0) could not be recognized until lump-sum pension payments exceeded annual pension plan service and Impairment losses and other costs: interest cost, which occurred in 2002.
Impairments of investments in
- We recorded a $1.6 million expense associated with qualifying facilities and power deferred payments to employees eligible for the VSERP.
projects (14.4) (9.9)
- Partially offsetting these costs, we reversed approximately Costs associated with exit of BGE $2.6 million of previously accrued workforce reduction Home merchandise stores (9.0) (6.1) costs primarily as a result of the reversal of education Impairments of real estate and and outplacement assistance benefits we accrued that international investments (1.8) (1.2) employees did not utilize to the extent expeacd.
Total impairment losses and other In 2002, we completed the 2001 workforce reduction costs (25.2) (17.2) programs. Accordingly, no involuntary severance liability Net gain on sales of investments and recorded under EITF 94-3 remained at December 31, 2002.
other assets 261.3 166.7 Costs associatedwith 2002 Programs Totl special items $173.3 $111.5 In 2002, we recorded $12.0 million of expenses for anticipated involuntary severance costs in accordance with EITF 94-3 WorLforce Reduction Costs associated with new workforce reduction initiatives as follows:
During 2002, we incurred costs related to workforce reduction
- We recorded $8.5 million for workforce reduction costs efforts initiated in the fourth quarter of 2001 as discussed in for the severance of 120 employees at Calvert Cliffs this note and additional initiatives undertaken in the third Nuclear Power Plant (Calvert Cliffs).
quarter of 2002. We discuss these costs in more detail below.
- We recorded $1.6 million of workforce reduction costs for the severance of 27 employees in our information Costs associatedwith 2001 Programs technology organization. BGE recorded $0.6 million of In 2002, we recorded $63.7 million of net workforce reduction this amount.
costs associated with our 2001 workforce reduction initiatives as
- We recorded $1.9 million of workforce reduction costs discussed below. The $63.7 million included $50.8 million for the severance of 20 employees in our legal recognized as expense, of which BGE recognized $33.8 million. organization. BGE recorded $0.9 million of this The remaining $12.9 million was recognized by BGE as a amount.
regulatory asset related to its gas business as discussed in Note 6. At December 31, 2002, the involuntary severance liability
- We recorded $52.9 million when 308 employees elected recorded under EITF 94-3 for our 2002 workforce reduction the age 50 to 54 Voluntary Special Early Retirement programs wvas $12.0 million.
Program (VSERP).
- W'e reversed $17.8 million of the $25.1 million Impairment Losses and Other Costs involuntary severance accrual that %%-as recorded in 2001 Investmnents in QualifyingFacilities andPower Projects to reflect the employees that elected the age 50 to 54 In the third quarter of 2002, our merchant energy business VSERP. Ultimately, we involuntarily severed 129 recorded impairment losses on certain of the investments in employees thar resulted in a total cost for the qualifying facilities and power proiects totaling $14.4 million involuntary severance program of $7.3 million. under the provisions of APB No. 18. We describe these investments in Note 4. The provisions of APB No. 18 require that an impairment loss be recognized when an investment experiences a loss in value that is other than temporary as discussed in Note 1.
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During the third quarter of 2002, we performed an analysis Real Estate and InternationalInvestments of whether any of the investments were impaired. As a result of We changed our strategy from an intent to hold to an intent to our analysis, we concluded that the declines in value of sell for certain of our non-core assets in 2001. During 2002, we particular investments in certain qualifying facilities and power determined that the fair value of several real estate projects and projects were other than temporary in nature under the our investment in a South American generation project declined provisions of APB No. 18 and we recognized the following losses below their respective book values due to deteriorating market in 2002: conditions for these projects. Accordingly, we recorded losses
- We recognized a $5.2 million other than temporary that totaled $1.8 million for these projects in accordance with decline in value of our investment in a partnership that SPAS No. 144 and APB No. 18.
owns a geothermal project in Nevada. This project experienced a well implosion and we believe that the Net Gain on Sales ofInvestments and OtherAssets expected cash flows from the project will not be In February 2002, Reliant Resources, Inc. acquired all of the sufficient to recover our equity interest in that outstanding shares of Orion Power Holdings, Inc. (Orion) for partnership. $26.80 per share, including the shares we owned of Orion. We
- We recognized a $2.6 million other than temporary received cash proceeds of $454.1 million and recognized a gain dedine in value of our investment in a fuel processing of $255.5 million on the sale of our investment.
site in Pennsylvania where the expected cash flows from In the fourth quarter of 2001, we announced our decision a sublease arc no longer expected to be sufficient to to focus efforts and capital on core domestic energy businesses recover our lease costs associated with this site. and undertook a plan to sell a number of non-core businesses
- WYe recognized a $6.6 million other than temporary and investments. In 2002, we made further progress on this decline in value of our investment in a partnership that initiative, and recognized approximately $5.8 million in net owns a waste burning power project in Michigan. In gains from the sale of several non-core assets including:
2001, we recognized a $6.1 million pre-tax impairment
- Our other nonregulated businesses recognized gains loss on this investment because we expected operating totaling $6.7 million on the sale of several parcels of cash flows would not be sufficient to pay existing debt real estate and financial investments.
service and that we would not be able to recover our
- In October 2002, we sold all of our 18 senior-living equity investment. However, at that time, we believed facilities for. $77.2 million that represents a combination that we would recover our senior working capital loans of cash and the assumption by the buyer of existing receivable and accounts receivable for operating the mortgages. Our other nonregulated businesses recognized project. As of the third quarter of 2002, the operating a $2.8 million gain on the sale of our entire ownership performance of the project did not improve as expected, interest in these facilities.
and we believed the expected future cash flows were no
- Our merchant energy business recognized a $2.3 million longer sufficient to recover these receivables. Therefore, gain on the sale of a discontinued wind-powered we recognized an additional impairment loss on this development project.
investment.
- In 2001, our merchant energy business recognized an impairment loss on four turbines, associated with a Closing of BGE Home Retail MerchandiseStores discontinued development program. Since that time, In September 2002, we announced our decision to dose our many other companies canceled development projects BGE Home retail merchandise stores. In connection with that and the market values for turbines have declined decision, we recognized $9.5 million in exit costs. We recognized significantly. Orders for three of the four turbines were
$2.9 million related to expected severance costs for 93 employees canceled with termination fees paid to the manufacturer and $2.9 million of costs in connection with the termination of consistent with the amount recognized in leases for the eight stores and other exit costs in accordance with December 2001. The fourth turbine-generator set wvas EITF 94-3. sold during 2002 for $6.0 million below its book value.
We also recognized $3.2 million for the write-off of unamortized leasehold improvements in accordance with SFAS No. 144, and $0.5 million for the write-down of inventory to a lower-of-cost-or-market valuation in accordance with Accounting Research Bulletin No. 43, Restatement and Revision ofAccounting Research Bulletins. The $0.5 million is included in "Operating expenses" in our Consolidated Statements of Income.
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3 Information by Operating Segment Our reportable operating segments are-Merchant Energy, Our remaining nonrcgulated businesses:
Regulated Electric, and Regulated Gas:
- design, construct, and operate heating, cooling, and
- Our nonregulated merchant energy business indudes: cogeneration facilities for commercial, industrial, and
- full requirements load-serving sales of energy and municipal customers throughout North America, and capacity to utilities and commercial and industrial
- provide home improvements, service electric and gas customers, appliances, service heating, air conditioning, plumbing,
- structured transactions and risk management electrical, and indoor air quality systems, and provide services for various customers (including hedging natural gas marketing to residential customers in central of output from generating facilities and fuel Maryland.
costs), In addition, we own several investments that we do not
- gas retail energy products and services to consider to be core operations. These include financial commercial and industrial customers, investments, real estate projects, and interests in Panamanian
- fossil, nuclear, and hydroelectric generating distribution facility and in a fund that holds interests in two facilities and interests in qualifying facilities, fuel South American energy projects.
processing facilities, and power projects in the Our Merchant Energy, Regulated Electric, and Regulated United States, Gas reportable segments are strategic businesses based principally
- coal sourcing services for the variable or fixed upon regulations, products, and services that require different supply needs of North American and technology and marketing strategies. We evaluate the international power generators, and performance of these segments based on net income. We
- operations and maintenance consulting services. account for intcrsegment revenues using market prices. '%Xe
- Our regulated electric business purchases, transmits, present a summary of information by operating segment on the distributes, and sells electricity in Maryland. next page.
- Our regulated gas business purchases, transports, and sells natural gas in Maryland.
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Reportable Segments Merchant Regulated Regulated Ocher Energy Electric Gas Nonregulated Business Business Business Businesses Eliminations Consolidated (In millions) 2004 Unaffiliated revenues S 9,4053 $1,967.6 $ 755.0 $421.8 $ - $12,549.7 Intcrsegment revenues 984.6 0.1 2.0 0.2 (986.9)
Total revenues 10,389.9 1,967.7 757.0 422.0 (986.9) 12,549.7 Depreciation and amortization 248.0 194.2 48.1 35.2 - 525.5 Fixed charges 196.2 803 29.1 24.7 330.3 Income tax expense 69.2 86.8 15.9 0.3 - 172.2 Loss on discontinued operations (49.1) - - - - (49.1)
Net income (loss) (a) 389.9 131.1 22.2 (3.5) - 539.7 Segment assets 12,395.6 3,402.2 1,163.4 675.7 (289.8) 17,347.1 Capital expenditures 455.0 209.0 56.0 42.0 - 762.0 2003 Unaffiliated revenues $ 6,465.9 $1,921.5 $ 712.7 $587.7 S - S 9,687.8 Intersegment revenues 1,167.0 0.1 13.3 0.2 (1,180.6)
Total revenues 7,632.9 1,921.6 726.0 587.9 (1,180.6) 9,687.8 Depreciation and amortization 229.5 181.7 46.6 21.2 - 479.0 Fixed charges 191.9 96.8 28.2 21.0 2.3 340.2 Income tax expense 146.9 73.5 32.0 17.1 - 269.5 Cumulative effects of changes in accounting principles (198.4) - - - _ (198.4)
Net income (b) 114.6 107.5 43.0 12.2 - 277.3 Segment assets 10,503.7 3,512.0 1,069.1 778.7 (270.5) 15,593.0 Capital expenditures 419.0 236.0 53.0 53.0 - 761.0 2002 Unaffiliated revenues $ 1,645.1 $ 1,965.6 $ 570.5 $537.4 $ - $ 4,718.6 Intcrsegment revenues 1,136.2 0.4 10.8 - (1,147.4)
Total revenues 2,781.3 1,966.0 581.3 537.4 (1,147.4) 4,718.6 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 70.6 23.0 88.8 309.6 Net income (c) 247.2 99.3 31.1 148.0 525.6 Segment assets 9,680.4 3,565.1 1,140.4 913.0 (355.6) 14,943.3 Capital expenditures 641.0 167.0 50.0 65.0 923.0 Certain prior-yearamounts have been rerlassifiedto conform with the urrnenyearspresentation.
(a) Our merchant energy business and our other nonregulatedbusinesses recognized after-tax charges (income) of ($30.0 million) and
$2.8 million, respectively for recognition of2003 synthetic fuel sax credits, uworkforre reduction costs, impairment losses and other costs, and net losses on sales of investments and other assets as described in more detail in Note 2.
(b) Our merchant energy business, our regulated electric business. our regulatedgas business, and our other nonregulatedbusinesses recognized after-tax charges (income) of$0.7 million, $0.4 million, $0.) million, and ($15.9 million), respectively, for uorkforce reduction costs, impairment losses and other costs, and net gains on sales of investments and other assets as described in more detail in Note 2 (c) Our merchant energy busines. our regulatedelectric business, our regulatedgas business, and our other nonregulkted businesses recognized after-tax charges (income) of$28.3 million, $20.5 million, $0.8 million, and ($161.1 million), repecsive(,I for orkforce reduction costs, business exit costs, impairment losses and other costs, and net gains on sales of investments and other assets as described in more detail in Note 2.
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4 investments Real Estate Projects Financial Investments Real estate projects recorded in "Other assets" were Financial investments recorded in "Other assets" consist of the
$28.8 million at December 31, 2004 and $44.3 million at following:
December 31, 2003.
At December 31, 2004 2003 Investments In Qualifying Facilities and Power Projects (In millions)
Our merchant energy business holds up to a 50% voting interest Financial limited partnerships $5.7 $22.5 in 24 operating domestic energy projects that consist of electric Leveraged leases - 2.8 generation, fuel processing, or fuel handling facilities. Of these 24 projects, 17 are 'qualifying facilities" that receive certain Total financial investments $5.7 $25.3 exemptions and pricing under the Public Utility Regulatory Policy Aa of 1978 based on the facilities' energy source or the Investments Classified as Avallable-tor-Sale use of a cogeneration process. We classify the following investments as available-for-sale:
Investments in qualifring facilities and domestic power
- nuclear decommissioning trust funds, and projects held by our merchant energy business consist of the
- trust assets securing certain executive benefits.
following- This means we do not expect to hold them to maturity, and we do not consider them trading securities.
At December 31, 2004 2003 We show the fair values, gross unrealized gains and losses, (In millions) and amortized cost basis for all of our available-for-sale Coal $128.7 $130.5 securities, in the following tables. We use specific identification Hydroelectric 55.8 57.3 to determine cost in computing realized gains and losses.
Geothermal 46.3 56.0 Amortized Unrealized Unrealized Fair Biomass 50.2 51.4 At December 31, 2004 Cost Basis Gains Losses v'aiue Fuel Processing 22.5 22.5 Solar 10A 10.5 (In millions)
Marketable equity Total $313.9 $328.2 securities $786.1 $72.5 $(2.5) $ 856.1 Corporate debt and U.S.
The investment in qualifying facilities and domestic power treasuries 73.7 0.7 (0.2) 742 projects were accounted for under the following methods:
State municipal bonds 943 2.9 (0.2) 97.0 At December 31, 2004 2003 Totals $954.1 $76.1 $(2.9) $1,027.3 (In millions)
Amortized Unrealized Unrealized Fair Equity method $303.5 $317.6 At December 31, 2003 Cost Basis Gains Losses Value Cost method 10.4 10.6 (In millions)
Total power projects $313.9 $328.2 Marketable equity securities $644.8 $30.7 $(22.2) $653.3 Corporate debt and U.S.
Our percentage voting interest in qualifying facilities and treasuries 37.2 0.9 - 38.1 domestic power projects accounted for under the equity method State municipal bonds 48.4 4.3 - 52.7 ranges from 16% to 50%. Equity in earnings of these power projects were $18.0 million in 2004, $2.1 million in 2003, and Totals $730.4 $35.9 $ (22.2) $744.1
$9.1 million in 2002. Certainprior-yearamounts have been reclassified to conform with Our power projects include investments of $240.2 million the current years presentation.
in 2004 and $251.8 million in 2003 that sell elearicity in California under power purchase agreements called 'Interim In addition to the above securities, the nuclear Standard Offer No. 4" agreements. decommissioning trust funds included $30.6 million at Our other nonregulated businesses also held international December 31, 2004 and $17.2 million at December 31, 2003 of energy projects accounted for under the equity method of cash and cash equivalents.
$4.5 million at December 31, 2004 and $4.4 million at December 31, 2003.
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The preceding tables include S73.3 million in 2004 of net Gross and net realized gains and losses on available-for-sale unrealized gains and $13.7 million in 2003 of net unrealized securities, excluding the gains on our sales of the Orion gains associated with the nuclear decommissioning trust funds investment, were as follows:
that are reflected as a change in the nuclear decommissioning trust funds in our Consolidated Balance Sheets. 2004 2003 2002 We have unrealized losses relating to certain (In millions) available-for-sale investments included in our decommissioning trust funds. We believe these losses are temporary in nature and Gross realized gains $4.1 $6.7 $ 6.0 expect the investments to recover their value in the future given Gross realized losses (7.7) (6.1) (9.5) the long-term nature of these investments. Decommissioning wvill Net realized (losses) gains $(3.6) $0.6 5(3.5) not occur until the operating licenses for our nuclear facilities expire. We show the fair values and unrealized losses of our Gross realized losses for 2004 include £4.5 million pre-tax investments that were in a loss position at December 31, 2004 impairment charge we recognized on a nuclear decommissioning and 2003. trust fund investment that we believed represented an other than temporary decline in value.
At December 31, 2004 The corporate debt securities, U.S. Government agency Less than 12 obligations, and state municipal bonds mature on the following months 12 months or more Totsl schedule:
Description of Fair Unrealized Fair Unrealized Fair Unrealized Securities Value Losses Value Losses Value Losses At December 31, 2004 (In millions) (In millions)
Marketable Less than I year $ 15.6 equity 1-5 years 42.2 securities $ 23.6 $(2.4) $ - $ - $ 23.6 S (2.4) 5-10 years 69.3 Corporate debt More than 10 years 44.1 and U.S. Total maturities of debt securities S 171.2 treasuries 153 (0.1) 10.1 (0.1) 25.4 (0.2)
State municipal bonds 18.7 (0.2) 3.3 _ 22.0 (0.2)
Total temporarily impaired securities S 57.6 $(2.7) S 13.4 S (0.1) S 71.0 $ (2.8)
At December 31, 2003 Lets than 12 months 12 months or more Total Description of Fair Unrealized Fair Unrealized Fair Unrealized Securities Value Losses Value Losses Value Losses (In millions)
Marketable equity securities $210.7 $(2.7) $308.2 5(19.2) $518.9 5(21.9)
Corporate debt and U.S.
treasuries 16.9 - - - 16.9 State municipal bonds - - 0.7 - 0.7 Total temporarily impaired securities $227.6 S(2.7) $308.9 S(19.2) $536.5 $(21.9) 91
5 Intangible Assets Goodwill Acquired energy contracts (net) represent the fair value of a Goodwill is the cost of an acquisition less the fair value of the contract at the time of contract acquisition, which includes net assets acquired. Our goodwill balance is primarily related to contracts acquired as part of a business, asset, or portfolio our merchant energy business acquisitions that occurred in 2002 acquisition. Energy contracts acquired in connection with a and 2003. We discuss our acquisitions in more detail in business combination can either be an asset or a liability and are Note 15. The changes in the carrying amount of goodwill for rcflectcd on a net basis in the table above.
the years ended December 31, 2004 and 2003 are as follows: We recognized amortization expense related to our intangible assets as follows:
Balance at Goodwill Balance at * $114.2 million, of which BGE recognized 2004 January 1I Acquired Other(a) December 31,
$41.4 million, during 2004 G1n1millions)
- $84.6 million, of which BGE recognized $33.0 million, Goodwill $ 146.3 $ - $ (1.5) $ 144.8 during 2003, and Balance at Goodwill Balance at * $46.4 million, of which BGE recognized $29.2 million, 2003 January 1, Acquired Other(a) December 31, during 2002.
(anmillions) The following is our, and BGE's, estimated amortization Goodwill $118.2 $27.5 S 0.6 S146.3 expense for 2005 through 2009 for the intangible assets included (a) Other represents purchase price adjustments in our, and BGE's, Consolidated Balance Sheets at December 31, 2004:
Goodwill is not amortized, rather it is evaluated for impairment at least annually. We evaluated our goodwill in 2004 Year Lided December 31. 2005 2006 2007 2008 2009 and determined that it was not impaired. For tax purposes, (Ln millions)
$115.7 million of our goodwill balance is deductible. Estimated amortization expense-Nonregulated businesses S53.6 $51.9 $36.1 531.2 $27.8 Intangible Assets Subject to Amortization Estimated amortization expense-BGE 31.0 22.4 22.1 21.4 21.2 Intangible assets with finite lives arc subject to amortization over their cstimated useful lives. The primary assets included in this Total estimated amortization expense-.Constellation Energy $84.6 $74.3 $58.2 $52.6 $49.0 category are as follows:
As December 31, 2004 2003 Accumul- Accumul-Gross ated Gross ated Carrying Amortiz- Net Carrying Amortiz- Net Amount ation Asset Amount ation Asset an millions)
Sofrware $3s8.4 s205.4 $183.0 $285.6 $155.1 $130.5 Acquired energy contracts (net) 185.2 84.8 100.4 182.5 36.7 145.8 Permits and licenses 37.7 5.7 32.0 28.8 3.2 25.6 Operating manuals and procedures 38.6 4.5 34.1 12.5 2.7 9.8 Other 20.0 12.1 7.9 22.6 10.7 11.9 Total $669.9 $312.5 $357.4 $532.0 $208.4 $323.6 BGE recordedintangible assets uith a gross ranying amount of $253.1 million and accumulated amortization of$1612 miLon in 20041and a grss carrying amount of$212.2 mnillion and acnumulatedamortization of
$127.3 million in 2003 and are included in the table aboe. Substanitaly al of BGE1 intangible assets relate to sofiware.
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6 Regulatory Assets (net)
As discussed in M'ote 1, the Maryland PSC and the FERC A portion of this regulatory asset represents the provide the final determination of the rates we charge our decommissioning and decontamination fund payment for federal customers for our regulated businesses. Generally, we use the uranium enrichment facilities that do not earn a return on the same accounting policies and practices used by nonregulated rate base investment. These amounts were $10.5 million at companies for financial reporting under accounting principles December 31, 2004 and $13.4 million at December 31, 2003.
generally accepted in the United States of America. However, Prior to the deregulation of electric generation, these costs were sometimes the Maryland PSC or FERC orders an accounting recovered through the electric fuel rate mechanism, and were treatment different from that used by nonregulated companies to excluded from rate base. We will continue to amortize this determine the rates we charge our customers. When this amount through 2008.
happens, we must defer certain regulated expenses and income in our Consolidated Balance Sheets as regulatory assets and Net Cost of Removal liabilities. We then record them in our Consolidated Statements As discussed in Note 1, we use the composite depreciation of Income (using amortization) when we include them in the method for the regulated business. This method is currently an rates we charge our customers. acceptable method of accounting under accounting principles We summarize regulatory assets and liabilities in the generally accepted in the United States of America and is widely following table, and we discuss each of them separately below. used in the energy, transportation, and telecommunication industries.
At December 31, 2004 2003 Historically, under the composite depreciation method, the (In millions) anticipated costs of removing assets upon retirement were Electric generation-related regulatory asset $ 192.4 S 211.3 provided for over the life of those assets as a component of Net cost of removal (132.5) (147.8) depreciation expense. However, effective January 1, 2003, we Income taxes recoverable through future adopted SFAS No. 143, Accounting for Aset Retirement rates (net) 74.9 81.8 Obligations. In addition to providing the accounting Deferred postretirement and requirements for recognizing an estimated liability for legal postemployment benefit costs 25.8 29.0 obligations associated with the retirement of tangible long-lived Deferred environmental costs 17.6 20.4 assets, SPAS No. 143 precludes the recognition of expected net Deferred fuel costs (net) 5.9 11.9 future costs of removal as a component of depreciation expense VX'rkforce reduction costs 14.1 21.2 Other (net) (2.8) 1.7 or accumulated depreciation.
BGE is required by the Maryland PSC to use the Total regulatory assets (net) $ 195.4 $ 229.5 composite depreciation method, including cost of removal, under regulatory accounting. In accordance with SFAS No. 71, BGE Electric Generation-Related Regulatory Asset continues to accrue for the future cost of removal for its As a result of the deregulation of electric generation, BGE does regulated gas and electric assets by increasing its regulatory not meet the requirements for the application of SFAS No. 71 liability. This liability is relieved when actual removal costs are for the electric generation portion of its business. In accordance incurred.
with SPAS No. 101, RegulatedEnterprises--Accountingfor the Discontinuation ofApplication of FASB Statement No. 71, and Income Taxes Recoverable Through Future Rates (net)
EITF 97-4, Deregulation ofthe PricingofEkectricity-Issues As described in Note 1, income taxes recoverable through future Related to the Application ofFASB Statements No. 71 and 101, all rates are the portion of our net deferred income tax liability that individual generation-related regulatory assets and liabilities must is applicable to our regulated business, but has not been reflected be eliminated from our balance sheet unless these regulatory in the rates we charge our customers. These income taxes assets and liabilities will be recovered in the regulated portion of represent the tax effect of temporary differences in depreciation the business. BGE wrotc-off all of its individual, generation- and the allowance for equity funds used during construction, related regulatory assets and liabilities. BGE established a single, offset by differences in deferred tax rates and deferred taxes on new generation-related regulatory asset for amounts to be deferred investment tax credits. We amortize these amounts as collected through its regulated transmission and distribution the temporary differences reverse.
business. The new regulatory asset is being amortized on a basis that approximates the pre-existing individual regulatory asset amortization schedules.
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Deferred Postretirement and Postemployment Benefit In December 2002, a Hearing Examiner from the Costs Maryland PSC issued a proposed order related to our annual gas Deferred postretirement and postemployment benefit costs arc adjustment clause review disallowing $7.7 million of a previously the costs we recorded under SFAS No. 106, Employers established regulatory asset of $9.4 million for certain credits Accounting for Postretirement Benefits Other Than Prnsions, and that were over-refunded to customers through our market-based SFAS No. 112. Employers'Accountingfor Postemployment Benefits, rates. BGE reserved the $7.7 million as disallowed fuel costs in in excess of the costs we included in the rates we charge our the fourth quarter of 2002. In August 2003, the Maryland PSC customers. We began amortizing these costs over a 15-year issued an order authorizing us to recover the $7.7 million and period in 1998. we reinstated the $9.4 million regulatory asset.
We exclude gas deferred fuel costs from rate base because Deferred Environmental Costs their existence is relatively short-lived. These costs are recovered Deferred environmental costs are the estimated costs of in the following year through our gas cost adjustment clauses.
investigating and cleaning up contaminated sites we own. We discuss this further in ANote 12. ecare amortizing $21.6 million Workforce Reduction Costs of these costs (the amount we had incurred through The portions of the costs associated with our VSERP and October 1995) and $6.4 million of these costs (the amount we workforce reduction programs that relate to BGE's gas business incurred from November 1995 through June 2000) over 10-year are deferred as regulatory assets in accordance with the Maryland periods in accordance with the Maryland PSC's orders. PSC's orders in prior rate cases. These costs are amortized over 5-year periods.
Deferred Fuel Costs As described in Note 1, deferred fuel costs are the difference between our actual costs of natural gas and our fuel rate revenues collected from customers. We reduce deferred fuel costs as we collect them from or refund them to our customers.
7 Penslon, Postretirement, Other Postemployment, and Employee Savings Plan Benefits We offer pension, postretirement, other postemployment, and We fund the qualified plans by contributing at least the employee savings plan benefits. BGE employees participate in minimum amount required under Internal Revenue Service the benefit plans that we offer. We describe each of our plans (IRS) regulations. We calculate the amount of funding using an separately below. Nine Mile Point offers its own pension, actuarial method called the projected unit credit cost method.
postretirement, other postemployment, and employee savings The assets in all of the plans at December 31, 2004 and 2003 plan benefits to its employees. The benefits for Nine Mile Point were mostly marketable equity and fixed income securities.
are included in the tables beginning on the next page.
We use a December 31 measurement date for our pension, Postretirement Benefits postretirement, other postemployment. and employee savings We sponsor defined benefit postretirement health care and life plans. insurance plans that cover the vast majority of our employees.
Generally, we calculate the benefits under these plans based on Pension Benefits age, years of service, and pension benefit levels or final base pay.
We sponsor several defined benefit pension plans for our We do not fund these plans.
employees. These include basic qualified plans that most For nearly all of the health care plans, retirees make employees participate in and several nonqualified plans that are contributions to cover a portion of the plan costs.
available only to certain employees. A defined benefit plan. Contributions for employees who retire after June 30. 1992 specifies the amount of benefits a plan participant is to receive are calculated based on age and years of service. The amount of using information about the participant. Employees do not retiree contributions increases based on expected increases in contribute to these plans. Generally, we calculate the benefits medical costs. For the life insurance plan, retirees do not make under these plans based on age, years of service, and pay. contributions to cover a portion of the plan costs.
Sometimes we amend the plans retroactively. These Effective in 2002, we amended our postretirement medical retroactive plan amendments require us to recalculate benefits plans for all subsidiaries other than Nine Mile Point. Our related to participants' past service. We amortize the change in contributions for retiree medical coverage for future retirees that the benefit costs from these plan amendments on a straight-line were under the age of 55 on January 1, 2002 are capped at the basis over the average remaining service period of active 2002 level. We also amended our plans to increase the Medicare employees. eligible retirees' share of medical costs.
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In 2003, the President signed into law the Medicare As required under SFAS No. 87, we recorded additional Prescription Drug Improvement and Modernization Act of 2003 minimum pension liability adjustments as follows:
(the Act). This legislation provides a prescription drug benefit for Medicare beneficiaries, a benefit that we provide to our Increase (Decrcase)
Medicare eligible retirees. Our actuaries concluded that Accumulated Other prescription drug benefits available under our postretirement Pension Comprehensive medical plan are currently "actuarially equivalent" to Medicare Liability Intangible Income (Loss)
Adiusimcmn Asset Pre-tax Afier-tax Part D and thus qualify for the subsidy under the Act. This
- (In milions) conclusion requires that we meet both the 'gross test" and 'net 2001 $133.0 $59.0 $ (74.0) $ (44.7) test" regulations. Our prescription drug plan provides a higher 2002 189.5 (5.8) (195.3) (118.1) level of benefits than Medicare Part D. thereby satisfying the 2003 (27.3) (6.5) 20.8 12.6
'gross test". Our share of these costs exceeds that of Medicare 2004 64.4 (6.1) (70.5) (42.6)
Part D, thereby satisfying the 'net test" method. Total $359.6 $40.6 S(319.0) $(192.8)
The expected subsidy will offset or reduce our share of the cost of the underlying postretirement prescription drug coverage.
- Included in 'Other assets' in our ConsolidatedBalance Sheets.
The estimated impact of this legislation reduced our Accumulated Postretirement Benefit Obligation by $30.6 million Obligations, Assets, and Funded Status at January 1, 2004 and our annual postretirement benefit In June 2004, we assumed pension and postretirement benefit expense in 2004 by $4.0 million. Final implementation guidance obligations for new employees in connection with the acquisition was issued in January 2005. This guidance will not have a of the RE. Ginna Nuclear Plant (Ginna). The sellers of Ginna material impact on our estimated impact of this legislation. This transferred assets into our qualified plan trust. We discuss the subsidy will reduce estimated 2006 cash per capita medical costs Ginna acquisition further in Note 15. As a result of a workforce from $3,199 to $2,671, or 17%. reduction initiative in the generation business, pension and postretirement special termination benefits were recorded in Additional Minimum Pension Liability Adjustment December 2004. We discuss the workforce reduction initiative Our pension accumulated benefit obligation has exceeded the further in Note 2. We show the change in the benefit fair value of our plan assets since 2001. At December 31, 2004 obligations, plan assets, and funded status of the pension and and 2003, our pension obligations were greater than the fair postretirement benefit plans in the following tables.
value of our plan assets for our qualified and our nonqualified pension plans as follows: Pension Postreirement Benefits Benefits Qualified Plans Non-Qualified 2004 2003 2004 2003 At Decemler 31. 2004 Nine Mile Other Plans Total (In millions)
(In millions) Change in benefit obligation Accumulated benefit Benefit obligation at obligation $122.1 $1,185.9 $46.1 S1,354.1 January 1 51326.0 $1,247.5 $430.8 $415.4 Fair value of assets 78.6 1,005.8 - 1,084.4 Service cost 40.1 33.7 6.5 6.1 Interest cost 82.4 81.3 22.6 26.3 Unfunded obligation S 43.5 $ 180.1 $46.1 $ 269.7 Plan participants' contributions - - 5.8 6.1 Qualified Plans Non-Qualified Actuarial loss (gain) 117.1 76.0 (17.2) 11.4 At Decemler 31, 2003 Nine Mile Other Plans Total Plan amendments - (0.4) - -
(In millions) Ginna acquisition 40.5 - 6.1 -
Special termination benefits 2.4 - 1.2 -
Accumulated benefit Benefits paid (1) (95.3) (112.1) (32.6) (34.5) obligation $98.3 $1,044.9 S37.1 $1,180.3 Fair value of assets 66.7 887.9 - 954.6 Benefit obligation at December 31 $1,513.2 $1.326.0 $423.2 $430.8 Unfunded obligation $31.6 $ 157.0 £37.1 S 225.7 (l) Benefits paid include annuity payments, lump-sum distributions, and transfers to nonqualified deferred compensation plans.
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Pension Postretiremcnt We show the components of net periodic poscretircment Benefits Benefits benefit cost in the following table:
2004 2003 2004 2003 (In millions) Star Ended Derember 31, 2004 2003 2002 Change in plan assets (In milions)
Fair value of plan assets at January 1 $ 954.6 S 767.7 S - $ Components of net periodic posuttirement Actual return on plan assets 114.1 183.6 benefit cost Employer contribution 60.2 115.4 26.7 28.4 Service cost S 6.5 S 6.1 $ 5.0 Plan participants' contributions - - 5.9 6.1 Interest cost 22.6 26.3 26.7 Grina acquisition 50.8 - - - Amortization of transition obligation 2.1 2.1 2.1 Bencfits paid (1) (95.3) (112.1) (32.6) (34.5) Recognized net actuarial loss 3.1 5.8 6.4 Amortization of unrecognized prior service Fair value of plan assets at cost (3.5) (3.5) (3.5)
December 31 $1,084.4 S 954.6 S - S Amount capitalized as construction cost (7.0) (8.8) (9.1)
(1) Benefits paid include annuity payments, lump-sum distributions. and Net periodic postretircment benefit cost (I) $ 23.8 528.0 $27.6 transfers to nonqualified deferred compensation plans.
(I) Net periodic postretirement benefit cost excludes SFAS No. 106 termination benefits of 51.2 million in 2004 and $9.2 million in Pension Postretirement 2002. BGE's portion of our net periodic postretirement benefit cost Bcncfits Bcncfits was I 5.1 million in 2004, 519.4 million in 2003, and Ar Decemler 31. 2004 2003 2004 2003 521.1 million in 2002.
(In millions)
Funded Status Expected Cash Benefit Payments Funded Status S(428.8) S(371.4) S(423.2) S(430.8) The pension and postrctirement bencfits we expect to pay in Unrecognized net actuarial loss 480.8 397.0 121.1 140.6 Unrecognized prior service cost 37.9 43.9 (36.7) (40.2) each of the next five calendar years and in the aggregate for the Unrecognized transition subsequent five years are shown below. These estimated bcncfits obligation - - 17.0 19.2 are based on the same assumption used to measure the benefit Pension liability adjustment (359.6) (295.2) - -
obligation at December 31, 2004, but includes benefits Accrued benefit cost S(269.7) 5(225.7) S(321.8) S(311.2) attributable to estimated future employee service.
Net Periodic Benefit Cost Postretirmcent Benefits We show the components of net periodic pension benefit cost in Before After the following table: Pension Medicare Medicare Benefits Part D Subsidy Part D Y'ar Ended December 31. 2004 2003 2002 (In milliomn)
(In millions) 2005 S 90.6 S 26.5 S - $ 26.5 Components of net periodic pension 2006 83.0 28.2 2.1 26.1 benefit cost 2007 85.5 29.6 2.3 27.3 Service cost 5 40.1 5 33.7 5 29.6 2008 87.9 30.4 24 28.0 Intcrest cost 82.3 81.3 82.2 Expected return on plan assets (97.9) (95.0) (91.0) 2009 92.1 31.1 2.6 28.5 Amortizatinn of unrecognized prior service 2010-2014 553.3 164.4 14A 150.0 cost 5.8 5.8 6.7 Recognized net actuarial loss 143 5.0 1.3 Assumptions Amount capitalized as construction cost (4.5) (2.6) (2.9) We made the assumptions below to calculate our pension and Net periodic pension benefit cost (I) S 40.1 5 28.2 S 25.9 postrctirement benefit obligations and periodic cost.
(I) Net periodic pension benefit cost excludes SFAS No. 88 settlement charge of 52.8 million and termination benefits of 52.4 million in Pension Postretirement Assumption 2004, SFAS No. 88 settlement charge of 52.8 million in 2003. and Bencfits Bcncfits Impacts .
SFAS No. 88 settlement charge of 529.6 million and termination 2004 2003 2004 2003 Calculation of benefits of S43.0 million in 2002. BGE's portion of our net periodic pension benefit costs was $8.6 million in 2004. 54.3 million in Benefit 2003, and $5.0 million in 2002. Obligation and Discount rate 5.75% 6.25% 5.75% 6.25% Periodic Cost Expected return on plan assets 9.0 9.0 N/A N/A Periodic Cost Ratc of Bcncfit compensation Obligation and increase 4.0 4.0 4.0 4.0 Periodic Cost Our 9.0% overall expected long-term rate of return on plan assets rcflcts our long-term investment strategy in terms of asset mix targets and expected returns for each asset class.
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Annual health care inflation rate assump tions also impact Contributions and Benefit Payments the calculation of our postretirement benefit cobligation and We contributed an additional $50 million to our qualified periodic cost. We assumed the following heali:h care inflation pension plans in March 2005, even though there is no IRS rates to produce average claims by year as sheawn below: required minimum contribution in 2005.
Our non-qualified pension plans and our postretirement At December 31, 2004 2003 benefit programs are not funded. We estimate that we will incur approximately $2.7 million in pension benefits for our Next year 10.0% 8.0% non-qualified pension plans and approximately $26.5 million Following year 9.0% 6.0% for retiree health and life insurance costs during 2005.
Ultimate trend rate Year ultimate trend rate reached 2010 2010 Other Postemployment Benefits We provide the following postemployment benefits:
A one-percent increase in the health care inflation rare
- health and life insurance benefits to eligible employees from the assumed rates would increase the accumulated determined to be disabled under our Disability postretirement benefit obligation by approximately Insurance Plan,
$31.9 million as of December 31, 2004 and would increase the
- income replacement payments for Nine Mile Point combined service and interest costs of the postretirement union-represented employees determined to be benefit cost by approximately $2.0 million annually. disabled, and A one-percent decrease in the health care inflation rate
- income replacement payments for other employees from the assumed rates would decrease the accumulated determined to be disabled before November 1995 postretirement benefit obligation by approximately (payments for employees determined to be disabled
$26.9 million as of December 31, 2004 and would decrease after that date are paid by an insurance company, and the combined service and interest costs of the postretirement the cost is paid by employees).
benefit cost by approximately $1.7 million annually. The liability for these benefits totaled $53.5 million as of December 31, 2004 and $50.6 million as of December 31, Qualified Pension Plan Assets 2003.
The asset allocations for our qualified pension plans were as We assumed the discount rate for other postemployment follows: benefits to be 5.0% in 2004 and 5.25% in 2003. This assumption impacts the calculation of our other At December 31, 2004 2003 postemployment benefit obligation and periodic cost.
Equity securities 57% 56%
Debt securities 33 32 Employee Savings Plan Benefits Other 10 12 We sponsor defined contribution savings plans that are offered to all eligible employees. The savings plans are qualified 401(k)
Total 100% 100% plans under the Internal Revenue Code. In a defined The category "Other" primarily represents investments in contribution plan, the benefits a participant is to receive result financial limited partnerships. Our long-term pension plan from regular contributions to a participant account. Matching investment strategy is to seek an asset mix of 53% equity, 35% contributions to participant accounts are made under these fixed income, and 12% other investments. We rebalance our plans. Matching contributions to these plans were:
portfolio periodically when the sum of equity and other * $16.7 million, of which BGE contributed investments differs from 65% by three percentage points or $4.7 million, in 2004, more, we change an outside investment advisor, or we make * $14.1 million, of which BGE contributed contributions to the trust. $4.6 million, in 2003, and
- $13.3 million, of which BGE contributed
$4.9 million, in 2002.
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8 Credit Facilities and Short-Term Borrowings Our short-term borrowings may include bank loans, commercial BGE paper, and bank lines of credit. Short-term borrowings mature BGE had no commercial paper outstanding at December 31, within one year from the date of issuance. We pay commitment 2004 and 2003.
fees to banks for providing us lines of credit. When we borrow During 2004, certain credit facilities expired and BGE under the lines of credit, we pay market interest rates. renewed those facilities. BGE continues to maintain
$200.0 million in committed credit facilities, expiring May 2005 Constellation Energy through November 2005. BGE can borrow directly from the Constellation Energy had committed bank lines of credit under banks or use the facilities to allow the issuance of commercial four credit facilities of $2.2 billion at December 31, 2004 for paper.
short-term financial needs as follows:
- $640.0 million three-year revolving credit facility Other Nonregulated Businesses expiring in June 2005, Our other nonregulated businesses had no short-term borrowings
- $447.5 million three-year revolving credit facility outstanding at December 31, 2004 and $9.6 million at expiring in June 2006, December 31, 2003. The weightcd-average effective interest rates
- $800.0 million three-year revolving credit facility for our other nonregulated businesses' short-term borrowings expiring in June 2007, and were 3.11% at December 31, 2003.
- $300.0 million five-year revolving credit facility expiring in June 2009, We use these facilities to allow issuance of commercial paper and letters of credit primarily for our merchant energy business. These facilities can issue letters of credit up to approximately $2.2 billion. Letters of credit issued under all of our facilities totaled $809.9 million at December 31, 2004 and
$507.1 million at December 31, 2003. Constellation Energy had no commercial paper outstanding at December 31, 2004 and 2003.
9 Long-Term Debt and Preference Stock Long-term Debt In connection with the sale of our geothermal generating Long-term debt matures in one year or more from the date of facility in Hawaii, we repaid prior to maturity $43.3 million of issuance. We detail our long-term debt in our Consolidated long-term debt. Xec discuss the sale of this facility in more detail Statements of Capitalization. As you read this section, it may be in Note 2.
helpful to refer to those statements.
BGE Constellation Energy BGE! First Refunding Mortgage Bonds During 2004, we decided to continue our ownership in a BGE's first refunding mortgage bonds are secured by a mortgage synthetic fuel processing facility in South Carolina. We discuss lien on all of its assets. The generating assets BGE transferred to this facility in more detail in Note 10. In connection with our subsidiaries of Constellation Energy also remain subject to the decision to continue with our ownership in this facility, we arc lien of BGE's mortgage, along with the stock of Safe Harbor committed to making fixed payments until the end of 2007. Water Power Corporation and Constellation Enterprises, Inc.
Accordingly, during 2004, we recorded a liability of
$39.3 million, net of discount related to imputed interest, in "Long-term debt" in our Consolidated Balance Sheets for these fixed payments. We used an imputed interest rate because there was no stated interest rate on these fixed payments. The imputed interest rate was calculated to be 3.47% and was based on our borrowing rate for a similar loan.
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BGE is required to make an annual sinking fund payment BGE Deferrab1e Interest SubordinatedDebentures each August I to the mortgage trustee; he amount of the On November 21, 2003, BGE Capital Trust 11 (BGE Trust 11),
payment is equal to 1% of the highest principal amount of a Delaware statutory trust established by BGE, issued bonds outstanding during the preceding 12 months. The trustee 10,000,000 Trust Preferred Securities for $250 million ($25 uses these funds to retire bonds from any series through liquidation amount per preferred security) with a distribution repurchases or calls for early redemption. However, the trustee rate of 6.20%.
cannot call the following bonds for early redemption: BGE Trust 11 used the net proceeds from the issuance of
- 7W1% Series, due 2007 common securities to BGE and the Trust Preferred Securities to
- 6s%%Series, due 2008 purchase a series of 6.20% Deferrable Interest Subordinated Holders of the Remarketed Floating Rate Series due Debentures due October 15, 2043 (6.20% debentures) from September 1, 2006 have the option to require BGE to BGE in the aggregate principal amount of $257.7 million with repurchase their bonds at ace value on September I of each the same terms as the Trust Preferred Securities. BGE Trust 11 year. BGE is required to repurchase and retire at par any bonds must redeem the Trust Preferred Securities at $25 per preferred that are not remarketed or purchased by the remarketing agent. security plus accrued but unpaid distributions when the 6.20%
BGE also has the option to redeem all or some of these bonds - debentures are paid at maturity or upon any earlier redemption.
at face value each September 1. BGE has the option to redeem the 6.20% debentures at any During 2004, BGE called $4.8 million principal amount of time on or afier November 21, 2008 or at any time when its Remarketed Floating Rate Series due September 1, 2006 to certain tax or other events occur.
satisfy the sinking fund requirement under the First Refunding BGE Trust 11 will use the interest paid on the 6.20%
Mortgage Bond indenture. These bonds were redeemed in whole debentures to make distributions on the Trust Preferred or in part at the sinking fund call price of 100% of principal Securities. The 6.20% debentures are the only assets of BGE amount plus accrued interest from June 1, 2004 to, but not Trust 11.
including, August 25. 2004. BGE fully and unconditionally guarantees the Trust Preferred Securities based on its various obligations relating to BGE! Other Long-Term Debt dte trust agreement, indentures, 6.20% debentures, and the On July 1, 2000, BGE transferred $278.0 million of tax-exempt preferred security guarantee agreement.
debt to our merchant energy business related to the transferred For the payment of dividends and in the event of assets. At December 31, 2004, BGE remains contingently liable liquidation of BGE, the 6.20% debentures are ranked prior to for the $269.8 million outstanding balance of this debt. preference stock and common stock.
We show the weighted-average interest rates and maturity At December 31, 2003, we applied the provisions of FIN dates for BGE's fixed-ratc medium-tcrm notes outstanding at 46R as it relates to special purpose entities. FIN 46R establishes December 31, 2004 in the following table. conditions under which an entity must be consolidated based upon variable interests rather than voting interests. FIN 46R Weighted-Average requires us to consolidate variable interest entities for which we Series Interest Rate are the primary beneficiary. Therefore, at December 31, 2003, B 8.63% 2006 we and BGE deconsolidated BGE Trust IT because BGE is not D 6.62 2005-2006 its primary benefitcary. As a result, we and BGE removed the E 6.66 2006-2012 Trust Preferred Securities from our and BGE's Consolidated G 6.08 2008 Balance Sheets and from our Consolidated Statements of Some of the medium-term notes include a "put option.' Capitalization as of December 31, 2003. At December 31, 2004 These put options allow the holders to sell their notes back to and 2003, we and BGE recorded the $257.7 million of 6.20%
BGE on the put option dates at a price equal to 100% of the Deferrable Interest Subordinated Debentures due to BGE Trust principal amount. The following is a summary of mcdium-term II and recorded our and BGE's $7.7 million equity investment notes with put options. in BGE Trust II in 'Other assets" in our and BGE's Consolidated Balance Sheets. We discuss FIN 46R in more Series E Notes Principal Put Option Dates detail in Accounting Standards Adopted section in Note 1.
(In millions) .
6.75%, due 2012 $59.5 June 2007 Other Nonregulated Businesses 6.75%, due 2012 25.0 June 2007 In 2004, we terminated certain loans under other revolving 6.73%, due 2012 25.0 June 2007 credit agreements of $41.4 million related to our Panamanian distribution facility. NXe replaced these revolving credit agreements with loans under new revolving credit agreements totaling $100.0 million.
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Retolving Credit Agreement Maturities of Long-Tern Debt On December 18, 2001, ComfortLink entered into a All of our long-term borrowings mature on the following
$25.0 million loan agreement with the Maryland Energy schedule (includes sinking fund requirements):
Financing Administration (MEFA). The terms of the loan exactly match the terms of variable rate, tax exempt bonds due Constellation Nonregulared Year Energy Businesses BGE December 1, 2031 issued by MEFA for Comfortlink to finance (In millions) the cost of building a chilled water distribution system. The 2005 $ 300.0 $ 14.5 $ 41.6 interest rate on this debt resets weekly. These bonds, and the 2006 - 20.1 442.9 corresponding loan, can be redeemed at any time at par plus 2007 600.0 19.5 122.4 accrued interest while under variable rates. The bonds can also 2008 - 8.3 296.0 be converted to a fixed rate at ComfortLink's option. 2009 500.0 10.0 11.5 Thereafter 1,963.3 364.8 589.2 Debt Compliance and Covenants Total long-term debt at The credit facilities of Constellation Energy and BGE have December 31, 2004 $3.363.3 $437.2 $1,503.6 limited material adverse change clauses that only consider a material change in financial condition and are not directly At December 31, 2004, we had long-term loans totaling affected by decreases in credit ratings. If these dauses are $381.6 million that mature after 2004 which contain certain put invoked, the lending institutions can decline making new options under which lenders could potentially require us to advances or issuing newv letters of credit, but cannot accelerate repay the debt prior to maturity. At December 31, 2004, existing amounts outstanding. The long-term debt indentures of $124.3 million is classified as current portion of long-term debt Constellation Energy and BGE do not contain material adverse as a result of these provisions.
change dauses or financial covenants.
Certain credit facilities of Constellation Energy contain a Weighted-Average Interest Rates for Variable Rate Debt provision requiring Constellation Energy to maintain a ratio of Our weighted-avCrage interest rates for variable rate debt were.
debt to capitalization equal to or less than 65%. At At DIrember 31, 2004 2003 December 31, 2004, the debt to capitalization ratio as defined in the credit agreements was no greater than 51%. NonregulatedBusinesses (including Constellation Energy)
Certain credit agreements of BGE contain provisions Loans under credit agreements 3.58% 3.98%
requiring BGE to maintain a ratio of debt to capitalization equal Tax-exempt debt transferred from BGE 1.54 1.40 to or less 65%. At December 31, 2004, the debt to BGE capitalization ratio for BGE as defined in these credit agreements Remarketed floating rate series mortgage bonds 1.39% 1.29%
was 46%. At December 31, 2004, no amounts were outstanding under these agreements. As discussed in Note 13 we have entered into interest rate Failure by Constellation Energy, or BGE, to comply with swaps relating to $450 million of our fixed-rate debt.
these covenants could result in the maturity of the debt outstanding under these facilities being accelerated. The credit Preference Stock facilities of Constellation Energy contain usual and customary Each series of BGE preference stock has no voting power, except cross-default provisions that apply to defaults on debt by for the following:
Constellation Energy and certain subsidiaries over a specified
- the preference stock has one vote per share on any threshold. Certain BGE credit facilities also contain usual and charter amendment which would create or authorize any customary cross-default provisions that apply to defaults on debt shares of stock ranking prior to or on a parity with the by BGE over a specified threshold. The indentures pursuant to preference stock as to either dividends or distribution of which BGE has issued and outstanding mortgage bonds and assets, or which would substantially adversely affect the subordinated debentures provide that a default under any debt contract rights, as expressly set forth in BGE's charter, instrument issued under the relevant indenture may cause a of the preference stock, each of which requires the default of all debt outstanding under such indenture. affirmative vote of two-thirds of all the shares of Constellation Energy also provides credit support to Calvert preference stock outstanding; and.
Cliffs, Ginna, and Nine Mile Point to ensure these plants have
- whenever BGE fails to pay full dividends on the funds to meet expenses and obligations to safely operate and preference stock and such failure continues for one year, maintain the plants. the preference stock shall have one vote per share on all matters, until and unless such dividends shall have been paid in full. Upon liquidation, the holders of the preference stock of each series outstanding are entitled to receive the par amount of their shares and an amount equal to the unpaid accrued dividends.
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1 0 Taxes The components of income tax expense are as follows:
Year Ended December 31, 2004 2003 2002 (Dollar amounts in millions)
Income Taxes Current Federal $ 33.9 $134.0 $145.0 State 22.1 33.6 24.2 Current taxes charged to expense 56.0 167.6 169.2 Deferred Federal 98.5 93.2 131.2 State 24.9 16.0 17.1 Deferred taxes charged to expense 123.4 109.2 148.3 Investment tax credit adjustments (7.2) (7.3) (7.9)
Income taxes per Consolidated Statements of Income $172.2 $269.5 $309.6 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) $774.2 $758.4 $848.4 Statutory federal income tax rate 35% 35% 35%
Income taxes computed at statutory federal rate 271.0 265.4 296.9 Increases (decreases) in income taxes due to Depreciation differences not normalized on regulated activities 4.0 4.1 4.8 Amortization of deferred investment tax credits (7.2) (7.3) (7.9)
Synthetic fuel tax credits flowed through to income (123.2) (35.0) (20.7)
State income taxes, net of federal income tax benefit 30.0 34.1 31.4 Other (2A) 8.2 5.1 Total income taxes $172.2 $269.5 $309.6 Effective income tax rate 22.2% 35.5% 36.5%
BGE's effective tax rate was 38.1% in 2004, 39.2% in 2003, and 39.5% in 2002. The difference between BGE's effective tax rate and the 35% statutory federal income tax rate is primarily related to Maryland corporate income taxes at an effective rate of 4.55%, which is net of the related federal income tax benefit.
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The major components of our net deferred income tax liability are as follows:
Constellation Energy BGE At December 31, 2004 2003 2004 2003 (In millions)
Deferred Income Taxes Deferred tax liabilities Net property, plant and equipment $1,522.7 $1,373.0 $ 540.5 $ 501.4 Qualified nuclear decommissioning trust funds 317.6 252.6 - -
Regulatory assets, net 95.1 105.7 95.1 105.7 Mark-to-market energy assets and liabilities, net 83.7 72.6 -
Financial investments and hedging instruments - 39.9 Other 88.8 132.1 62.6 63.1 Total deferred tax liabilities 2,107.9 1,975.9 698.2 670.2 Deferred tax assets Asset retirement obligation 327.3 235.3 -
Accrued pension and post-employment benefit costs 194.0 183.3 58.3 62.9 Financial investments and hedging instruments 10.3 - -
Deferred investment tax credits 26.9 27.4 5.9 6.5 Reduction of investments 46.4 40.4 -
Other 104.7 109.4 15.7 15.0 Total deferred tax assets 709.6 595.8 79.9 84.4 Total deferred tax liability, net 1,398.3 1,380.1 618.3 585.8 Current portion of deferred tax liability, net-recorded in accrued expenses and other 95.0 68.3 10.3 9.6 Long-term portion of deferred tax liability, net $1,303.3 $1,311.8 $ 608.0 $ 576.2 Synthetic Fuel Tax Credits In 2003, we purchased 99% ownership in a South Our merchant energy business has investments in facilities that Carolina facility that produces synthetic fuel. We did not manufacture solid synthetic fuel produced from coal as defined recognize in our Consolidated Statements of Income the tax under Section 29 of the Internal Revenue Code for which we benefit of $35.9 million for credits claimed on our South can claim tax credits on our Federal income tax return through Carolina facility in 2003 pending receipt of a favorable private 2007. We recognize the tax benefit of these credits in our letter ruling. In 2004, we received a favorable private letter Consolidated Statements of Income when we believe it is ruling. We believe receipt of the private letter ruling provides highly probable that the credits will be sustained. The synthetic reasonable assurance that it is highly probable that the credits fuel process involves combining coal material with a chemical will be sustained. Therefore, we recognized the tax benefit of reagent to create a significant chemical change. A taxpayer may $35.9 million in our Consolidated Statements of Income request a private letter ruling from the IRS to support its during 2004.
position that the synthetic fuel produced undergoes a Under Section 29, only synthetic fuel sold before significant chemical change and thus qualifies for Section 29 January 1, 2008 can be claimed for synthetic fuel tax credits.
credits. Additionally, Section 29 provides for a phase-out of the tax As of December 31, 2004, we have recognized cumulative credit to the extent that average annual oil prices per barrel tax benefits associated with Section 29 credits of exceed an inflation adjusted oil price as determined annually by
$201.2 million, of which $123.2 million was recognized during the IRS. For 2005, we estimate that the credit reduction would the year ended December 31, 2004. begin if the average annual oil price per barrel exceeds We own a minority ownership in four synthetic fuel approximately $52 and would be fully phased out if the facilities located in Virginia and West Virginia. These facilities average annual oil price exceeds $65 per barrel.
have received private letter rulings from the IRS. In While we believe the production and sale of synthetic fuel January 2004, the IRS concluded its examination of the from all of our synthetic fuel facilities meet the conditions to partnership that owns these facilities for the tax years 1998 qualify for tax credits under Section 29 of the IRS Code, we through 2001 and the IRS did not disallow any of the cannot predict the timing or outcome of any future challenge previously recognized synthetic fuel credits. During the second by the IRS, legislative or regulatory action, oil prices, or the quarter of 2004, we received final written notice of the ultimate impact of such events on the Section 29 credits that resolution of the examination from the IRS. we have claimed to date or expect to claim in the future, but the impact could be material to our financial results.
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I I Leases There are two types of Ieases-operating and capital. Capital Lease expense was:
leases qualify as sales or purchases of property and are reported * $34.1 million in 2004, in our Consolidated Balance Sheets. Capital leases are not * $22.7 million in 2003, and material in amount. All other leases are operating leases and are * $19.4 million in 2002.
reported in our Consolidated Statements of Income. We expense At December 31, 2004, we owed future minimum all lease payments associated with our regulated business. Lease payments for long-term, noncancelable, operating leases as expense and future minimum payments for long-term, follows:
noncancelable, operating leases are not material to BGE's financial results. We present information about our operating Year leases below. (In millions) 2005 $113.2 Outgoing Lease Payments 2006 113.2 We, as lessee, lease some facilities and equipment. The lease 2007 106.0 agreements expire on various dates and have various renewal 2008 61.2 options. We also enter into certain power purchase agreements 2009 13.4 which are accounted for as operating leases. Under these Thereafter 127.9 agreements, we are required to make fixed capacity payments, as Total future minimum lease payments $534.9 well as variable payments based on actual output of the plants.
We exdude from our future minimum lease payments table the variable payments related to the output of the plant due to the contingency associated with these payments.
1 2 Commitments, Guarantees, and Contingencies Commitments Our regulated electric business enters into various long-term We have made substantial commitments in connection with our contracts for the procurement of electricity. These contracts merchant energy, regulated electric and gas, and other expire between 2005 and 2006. The cost of power under these nonregulared businesses. These commitments relate to: contracts are recoverable under the POLR agreement reached
- purchase of electric generating capacity and energy, with the Maryland PSC, as discussed in Alote I and therefore are
- procurement and delivery of fuels, and exduded from the table on the next page.
- long-term service agreements, capital for construction Our regulated gas business enters into various long-term programs and other. contracts for the procurement, transportation, and storage of gas.
Our merdhant energy business enters into various long-term Our regulated gas business has gas transportation and storage contracts for the procurement and delivery of fuels to supply our contracts that expire between 2005 and 2023. These contracts generating plant requirements. In most cases, our contracts are recoverable under BGE's gas cost adjustment dause discussed contain provisions for price escalations, minimum purchase in Note I and therefore are excluded from the table on the next levels, and other financial commitments. These contracts expire page.
in various years between 2005 and 2012. In addition, our. Our other nonregulated business has committed to gas merchant energy business enters into long-term contracts for the purchases and to contributions of additional capital for capacity and transmission rights for the delivery of energy to construction programs and joint ventures in which they have an meet our physical obligations to our customers. These contracts interest.
expire in various years between 2005 and 2018. We have also committed to long-term service agreements Our merchant energy business also has committed to and other obligations related to our information technology long-term service agreements and other purchase commitments systems.
for our plants.
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At December 31, 2004, we estimate our future obligations
- Constellation Energy guaranteed $5,504.2 million on to be as follows: behalf of our subsidiaries for competitive supply activities. These guarantees are put into place in order Payments to allow our subsidiaries the flexibility needed to 2006- 2008- 'conduct business with counterparties without having to 2005 2007 2009 Thereafcer Total post substantial cash collateral. While the face amount (In midloni)
Merchant Energy of these guarantees is $5,504.2 million, our calculated Purchased capacity and fair value of obligations covered by these guarantees was energy S 794.2 $ 743.3 $184.9 $157.0 $1,879.4 $1,395.6 million at December 31, 2004. If the parent Fuel and transporration 1,292.0 816.3 142.8 37.3 2,288.4 company was required to fund subsidiary obligations, Long-term service the total amount at current market prices is agreements, capital.
$1,395.6 million. The recorded fair value of obligations and other 59.3 47.2 70.0 208.6 385.1 in our Consolidated Balance Sheets for these guarantees Total merchant energy 2,145.5 1,606.8 397.7 402.9 4,552.9 was $781.1 million at December 31, 2004.
Corporate and Other:
- Constellation Energy guaranteed $945.6 million Long-term service agreementa, capital, primarily on behalf of our nuclear generating facilities and other 25.4 12.2 3.1 1.9 42.6 primarily related to nuclear insurance and for credit Regulated: support to ensure these plants have funds to meet Purchase obligations expenses and obligations to safely operate and maintain and other 12.5 3.6 1.8 0.5 18.4 the plants.
Total future obligations $2,183.4 $1,622.6 $402.6 $405.3 $4,613.9
- Constellation Energy guaranteed $48.2 million on behalf of our other nonregulated businesses primarily for loans and performance bonds of which $25.0 million Long-Term Power Sales Contracts was recorded in our Consolidated Balance Sheets at We enter into long-term power sales contracts in connection December 31, 2004.
with our load-serving activities. We also enter into long-term
- Our merchant energy business guaranteed $18.7 million power sales contracts associated with certain of our power plants.
for loans and other performance guarantees related to Our load-serving power sales contracts extend for terms through certain power projects in which we have an investment.
2012 and provide for the sale of full requirements energy to
- Our other nonregulated business guaranteed electricity distribution utilities and certain retail customers. Our
$11.2 million for performance bonds.
power sales contracts associated with our power plants extend for
- BGE guaranteed two-thirds of certain debt of Safe terms into 2014 and provide for the sale of all or a portion of Harbor Water Power Corporation, an unconsolidated the actual output of certain of our power plants. All long-term investment. At December 31, 2004, Safe Harbor Water contracts were executed at pricing that approximated market Power Corporation had outstanding debt of rates, induding profit margin, at the time of execution.
$20 million. The maximum amount of BGE's guarantee is $13.3 million.
Guarantees
- BGE guaranteed the Trust Preferred Securities of The terms of our guarantees are as follows:
$250.0 million of BGE Trust II, an unconsolidated Expiration investment, as discussed in Note 9. .
2006- 2008- The total fair value of the obligations for our guarantees 2005 2007 2009 Thereafter Total recorded in our Consolidated Balance Sheets was $806.1 million (us miliom) and not the $6.8 billion of total guarantees. We assess the risk Competitive Supply $3,693.4 $918.5 $314.5 S 577.8 $5,504.2 of loss from these guarantees to be minimal.
Other 6.7 3.6 15.7 1,261.0 1,287.0 Total Guarantees $3,700.1 $922.1 $330.2 $1,838.8 $6,791.2 Environmental Matters Solid and Hazardous Wuste At December 31, 2004, Constellation Energy had a total of The Environmental Protection Agency (EPA) and several state
$6,791.2 million guarantees outstanding related to loans, credit agencies have notified us that we are considered a potentially facilities, and contractual performance of certain of its responsible party with respect to the dean-up of certain subsidiaries as described below. These guarantees do not environmentally contaminated sites. We cannot estimate the final represent our incremental obligations, and we do not expect to dean-up costs for all of these sites, but the costs and current fund the full amount under these guarantees. status of each site is described in more detail on the next page.
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Metal Bank Spring Gardns In 1997, the EPA, under the Comprehensive Environmental In December 1996, BGE signed a consent order with the Response, Compensation and Liability Act ("Superfund"), issued Maryland Department of the Environment that requires it to a Record of Decision (ROD) for the proposed clean-up at the implement remedial action plans for contamination at and Metal Bank of America site, a metal redaimer in Philadelphia. around the Spring Gardens site, located in Baltimore, Maryland.
We had previously recorded a liability in our Consolidated The Spring Gardens site was once used to manufacture gas from Balance Sheets for BGE's 15.47% share of probable dean-up coal and oil. Based on the remedial action plans, BGE estimates costs. Based on current settlement negotiations among the EPA its probable dean-up costs will total $47 million. BGE has and the potentially responsible parties involved at the site, we do recorded these costs as a liability in its Consolidated Balance not believe we Vill incur dean-up costs in excess of the amount Sheets and has deferred these costs, net of accumulated recorded as a liability. The EPA and the potentially responsible amortization and amounts it recovered from insurance parties, including BGE, are currently pursuing claims against companies, as a regulatory asset. Based on the results of studies Metal Bank of America for an equitable share of expected site at this site, it is reasonably possible that additional costs could remediation costs. exceed the amount BGE has recognized by approximately
$14 million. Through December 31, 2004, BGE has spent 68dh Street Dump approximately $40 million for remediation at this site.
In 1999, the EPA proposed to add the 68th Street Dump in BGE also has investigated other small sites where gas was Baltimore, Maryland to the Superfund National Priorities List manufactured in the past. We do not expect the dean-up costs
("NPL"), which is its list of sites targeted for clean-up and of the remaining smaller sites to have a material effect on our enforcement, and sent a general notice letter to BGE and 19 financial results.
other parties identifying them as potentially liable parties at the site. In March 2004, we and other potentially responsible parties Litigation formed the 68th Street Coalition, which has entered into In the normal course of business, we are involved in various consent order negotiations with the EPA to investigate dean-up legal proceedings. We discuss the significant matters below.
options for the site under the Superfund Alternative Sites Program. While negotiations under this program are ongoing, Western Power AMarkets the 68th Street Dump will not be placed on the NPL At this Baldwin Aksociates, Inc. v. Gray Davis, Governor of California and stage' it is not possible to predict the outcome of those 22 other defendants (including Constellation Power discussions or our share of the liability However, the costs could Development, Inc., a subsidiary of Constellation Power, Inc.)-This have a material ceffct on our financial results. putative class action lawsuit was filed on October 5, 2001 in the Superior Court, County of San Francisco. The action requested Kane and Lombard damages, recession and reformation of approximately 38 The EPA issued its ROD for the Kane and Lombard Drum site long-term power purchase contracts, and an injunction against located in Baltimore, Maryland on September 30, 2003. The improper spending by the state of California.
ROD specifies the dean-up plan for the site, consisting of Constellation Power Development, Inc. was named as a enhanced reductive dechlorination, a soil management plan, and defendant but was never served with process in this case. On institutional controls. In July 2004, the EPA issued a Special December 6, 2004, the Court ordered dismissal of this action Notice/Demand Letter to BGE and three other potentially since the plaintiff had failed to serve the defendants.
responsible parties regarding implementation of the remedy. In response, the potentially responsible parties have proposed negotiations with the EPA regarding the implementation. The total dean-up costs are estimated to be approximately
$10 million. We estimate our current share of site-related costs to be 11.1%. In December 2002, we recorded a liability in our Consolidated Balance Sheets for our share of the dean-up costs that we believe is probable. Our final share of the $10 million has not been determined and it may vary from the current estimate.
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James M. Mfillar v. Allegheny Energy Supply. Constellation Power In a ruling applicable to all but several of the cases, the Source, Inc., High Desert Power Project, LLC,: at,-On Circuit Court for Baltimore City dismissed with prejudice all December 19, 2003, plaintiffs filed an amended complaint in claims against BGE and Constellation Energy and entered a stay Superior Court of California, County of San Francisco, naming of the proceedings as they relate to other defendants. Plaintiffs for the first time, Constellation Power Source, Inc., renamed may attempt to pursue appeals of the rulings in favor of BGE Constellation Energy Commodities Group, Inc. (CCG), and and Constellation Energy once the cases are finally concluded as High Desert Power Project, LLC (High Desert), two of our to all defendants. We believe that we have meritorious defenses subsidiaries, as additional defendants. The complaint is a and intend to defend the actions vigorously. However, we cannot putative class action on behalf of California electricity consumers predict the timing or outcome of these cases, or their possible and alleges that the defendant power suppliers, including CCG effect on our, or BGE's, financial results.
and High Desert, violated California's Unfair Competition Law in connection with certain long-term power contracts that the Employment Discrimination defendants negotiated with the California Department of Water Miller, et. al P.Baltimore Gas and Electric Company, et al,-This Resources in 2001 and 2002. Notwithstanding the amended action was filed on September 20, 2000 in the U.S. District long-term power contracts and the releases and settlement Court for the District of Maryland. Besides BGE, Constellation agreements negotiated at the time of such amendments, the Energy Group, Constellation Nuclear, and Calvert Cliffs Nuclear plaintiff seeks to have the Court certify the case as a class action Power Plant are also named defendants. The action seeks class and to order the repayment of any monies that were acquired by certification for approximately 150 past and present employees the defendants under the long-term contracts or the amended and alleges racial discrimination at Calvers Cliffs Nuclear Power long-term contracts by means of unfair competition in violation Plant. The amount of damages is unspecified, however the of California law. Vec believe that wvehave meritorious defenses plaintiffs seek back and front pay, along with compensatory and to this action and intend to defend against it vigorously. punitive damages. The Court scheduled a briefing process for However, we cannot predict the timing, or outcome, of this case, the motion to certify the case as a class action suit. The briefing or its possible effect on our financial results. process concluded, oral argument on the class certification motion was held on April 16, 2004, and the parties are awaiting City of Tacoma v. AE1R et al.,-The City of Tacoma, on June 7, the court's decision. We do not believe class certification is 2004, in the U.S. District Court, Western District of appropriate and we further believe that we have meritorious Washington, filed a complaint against over 60 companies, defenses to the underlying claims and intend to defend the including CCG. The complaint alleges that the defendants action vigorously. However, we cannot predict the timing, or engaged in manipulation of electricity markets resulting in prices outcome, of the action or its possible effea on our, or BGE's, for power in the western power markets that were substantially financial results.
above what market prices would have been in the absence of the alleged unlawful contracts, combinations and conspiracy in violation of Section I of the Sherman Act. The complaint Asbestos Since 1993, BGE has been involved in several actions further alleges that the total amount of damages is unknown, concerning asbestos. The actions are based upon the theory of but is estimated to exceed $175 million. On February 11, 2005, the Court granted the defendants' motion to dismiss the action "premises liability," alleging that BGE knew of and exposed based on the Court's lack of jurisdiction over the claims in individuals to an asbestos hazard. The actions relate to two types question. The plaintiff may seek to appeal the Court's dismissal of claims.
of the action. We believe that we have meritorious defenses to The first type is direct claims by individuals exposed to this action and intend to defend against it vigorously. However, asbestos. BGE is involved in these claims with approximately 70 other defendants. Approximately 490 individuals that were never we cannot predict the timing, or outcome, of this case, or its possible effect on our financial results. employees of BGE each claim $6 million in damages ($2 million compensatory and $4 million punitive). These claims are currently pending in state courts in Maryland and Pennsylvania.
Mfercury BGE does not know the specific facts necessary to estimate its Beginning in September 2002, BGE, Constellation Energy, and potential liability for these claims. The specific facts BGE does several other defendants have been involved in numerous actions not know include:
filed in the Circuit Court for Baltimore City, Maryland alleging
- the identity of BGE's facilities at which the plaintiffs mercury poisoning from several sources, including coal plants allegedly worked as contractors, formerly owned by BGE. The plants are now owned by a
- the names of the plaintiff's employers, subsidiary of Constellation Energy. In addition to BGE and
- the date on which the exposure allegedly occurred, and Constellation Energy, approximately 11 other defendants,
- the facts and circumstances relating to the alleged consisting of pharmaceutical companies, manufacturers of exposure.
vaccines, and manufacturers of Thimerosal have been sued.
To date, 351 asbestos cases were dismissed or resolved for Approximately 70 cases have been filed to date, with each case amounts that were not significant. Approximately 20 cases are seeking $90 million in damages from the group of defendants.
scheduled for trial through the end of 2006.
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The second type is claims by one manufacturer-Pittsburgh Nuclear Insurance Corning Corp. (PCC)-against BGE and approximately eight We maintain nuclear insurance coverage for Calvert Cliffs, Nine others, as third-party defendants. On April 17, 2000, PCC Mile Point, and Ginna in four program areas: liability, worker declared bankruptcy. radiation, property, and accidental outage. These policies contain These claims relate to approximately 1.500 individual certain industry standard exclusions, including, but not limited plaintiffs and were filed in the Circuit Court for Baltimore City, to, ordinary wear and tear, and war.
Maryland in the fall of 1993. To date, about 375 cases have In November 2002, the President signed into law the been resolved, all without any payment by BGE. BGE does not Terrorism Risk Insurance Act ("TRIA") of 2002. Under the know the specific facts necessary to estimate its potential liability TRIA, property and casualty insurance companies are required to for these claims. The specific facts we do not know indude: offer insurance for losses resulting from Certified acts of
- the identity of BGE facilities containing asbestos terrorism. Certified acts of terrorism are determined by the manufactured by the manufacturer, Secretary of State and Attorney General and primarily are based
- the relationship (if any) of each of the individual upon the occurrence of significant acts of international terrorism.
plaintiffs to BGE, Our nuclear property and accidental outage insurance programs,
- the settlement amounts for any individual plaintiffs who as discussed later in this section, provide coverage for Certified are shown to have had a relationship to BGE, acts of terrorism.
- the dates on which/placcs at which the exposure If there were an accident or an extended outage at any unit allegedly occurred, and of Calvert Cliffs, Nine Mile Point or Ginna, it could have a
- the facts and circumstances relating to the alleged substantial adverse impact on our financial results.
exposure.
Until the relevant facts for both types of claims are Nuclear Liability Insurance determined, we are unable to estimate what our, or BGE's, Pursuant to the Price-Anderson Act, we are required to insure liability might be. Although insurance and hold harmless against public liability claims resulting from nuclear incidents to agreements from contractors who employed the plaintiffs may the full limit of public liability. This limit of liability consists of cover a portion of any awards in the actions, the potential ceffect the maximum available commercial insurance of $300 million on our, or BGE's, financial results could be material. and mandatory participation in an industry-wide retrospective premium assessment program. The retrospective premium Storage of Spent Nuclear Fuel assessment is $100.6 million per reactor, increasing the total The Nuclear Waste Policy Act of 1982 (NWPA) required the amount of insurance for public liability to approximately federal government through the Department of Energy (DOE), $10.8 billion. Under the retrospective assessment program, we to develop a repository for, and disposal of, spent nuclear fuel can be assessed up to $503 million per incident at any and high-level radioactive waste. The NWPA and our contracts commercial reactor in the country, payable at no more than with the DOE required the DOE to begin taking possession of $50 million per incident per year. This assessment also applies in spent nuclear fuel generated by nuclear generating units no later excess of our worker radiation claims insurance and is subject to than January 31, 1998. The DOE has stated that it will not inflation and state premium taxes. Claims resulting from meet that obligation until 2010 at the carliest. This delay has non-certified acts of terrorism are limited to the commercial required that we undertake additional actions related to on-site insurance discussed above, regardless of the number of nuclear fuel storage at Calvert Cliffs and Nine Mile Point, including the plants affected. In addition, the U.S. Congress could impose installation of on-site dry fuel storage capacity at Calvert Cliffi. additional revenuc-raising measures to pay claims.
In January 2004, we filed a complaint against the federal government in the United States Court of Federal Claims Worker Radiation Claims Insurance seeking to recover damages caused by the DOE's Lhilure to meet We participate in the American Nuclear Insurers Master Worker its contractual obligation to begin disposing of spent nuclear fuel Program that provides coverage for worker tort claims filed for by January 31, 1998. The cases are currently stayed, pending radiation injuries. Effective January 1, 1998, this program was litigation in other related cases. modified to provide coverage to all workers whose nuclear-In connection with our purchase of Ginna, all of Rochester related employment began on or after the commencement date Gas & Electric Corporation's (RG&E) rights and obligations of reaor operations. Waiving the right to make additional related to recovery of damages from the DOE were assigned to claims under the old policy was a condition for coverage under us. However, we have an obligation to reimburse RG&E for up the new policy. We describe the old and new policies below:
to the first S10 million in recovered damages. We and RG&E
- Nuclear worker claims reported on or after January 1, are currently requesting to allow us to replace RG&E as the 1998 are covered by a new insurance policy with a party in interest in the complaint filed against the federal single industry aggregate limit of $300 million for government by RG&E. radiation injury claims against all those insured by this policy.
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- All nuclear worker claims reported prior to January 1, Non-Nuclear Property Insurance 1998 are still covered by the old policy. Insureds under Our conventional property insurance provides coverage of the old policies, with no current operations, are not $1.0 billion per occurrence for Certified acts of terrorism as required to purchase the new policy described on the defined under the Terrorism Risk Insurance Act of 2002.
previous page, and may still make claims against the old Certified acts of terrorism are determined by the Secretary of policies through 2007. If radiation injury claims under State and Attorney General of the United States and primarily these old policies exceed the policy reserves, all are based upon the occurrence of significant acts of intemational policyholders could be retroactively assessed, with our terrorism. Our conventional property insurance program also share being up to $6.3 million. provides coverage for non-ccrtificd acts of terrorism up to an The sellers of Nine Mile Point retain the liabilities for annual aggregate limit of $333.0 million. If a terrorist act occurs existing and potential daims that occurred prior to November 7, at any of our facilities, it could have a significant adverse impact 2001. In addition, the Long Island Power Authority which on our financial results.
continues to own 18% of Unit 2 at Nine Mile Point, is obligated to assume its pro rata share of any liabilities for California Power Purchase Agreements retrospcaivc premiums and other premiums assessments. RG&E, Our merchant energy business has $240.2 million invested in the seller of Ginna, retains the liabilities for existing and operating power projects of which our ownership percentage potential claims that occurred prior to June 10, 2004. If daims represents approximately 140 megawatts of electricity that are under these policies exceed the coverage limits, the provisions of sold to Pacific Gas & Electric (PGE) and to Southern California the Pricc-Andcrson Act would apply. Edison (SCE) in California under power purchase agreements.
As a result of two proceedings initiated by certain Nuclear Property Insurance California utilities and others before the California Public Utility Our policies provide $500 million in primary coverage at Commission challenging prices under power purchase agreements Calvert Cliffs, Nine Mile Point, and Ginna. In addition, we for periods bewveen June 2000 and March 2001, the potential maintain $2.25 billion in excess coverage at Calvert Cliffs and exists that certain California power generation projects in which Nine Mile Point and S1.77 billion of excess coverage at Ginna we have an ownership interest could be required to pay refunds.
for property damage, decontamination, and premature We believe the price for energy payments were appropriate and decommissioning liability. This coverage currently is purchased any refund would be unwarranted. Our current estimate of through an industry mutual insurance company. If accidents at potential exposure that could result from an adverse ruling in plants insured by the mutual insurance company cause a the proceeding is between $2.5 million and $5.0 million.
shortfall of funds, all policyholders could be assessed, with our However, we cannot determine the actual amount we could be share being up to $91.7 million. required to pay because litigation is ongoing and new events Losses resulting from non-ccrtified acts of terrorism are could occur that may cause the actual amount, if any, to be covered as a common occurrence, meaning that if non-ccrtificd materially different from our estimate.
terrorist acts occur against one or more commercial nuclear power plants insured by our nudcear property insurance company within a 12-month period, they would be treated as one event and the owners of the plants would share one full limit of liability (currently $3.24 billion).
Accidental Nuclear Outage Insurance Our policies provide indemnification on a weekly basis for losses resulting from an accidental outage of a nuclear unit. Coverage begins after a 12-wcck deductible period and continues at 100%
of the weekly indemnity limit for 52 weeks and then 80% of the weekly indemnity limit for the next 110 weeks. Our coverage is up to $490.0 million per unit at Calvert Cliffs and Ginna, $420.0 million for Unit 1 of Nine Mile Point, and
$401.8 million for Unit 2 of Nine Mile Point. This amount can be reduced by up to $98.0 million per unit at Calvert Cliffs and
$84.0 million for Nine Mile Point if an outage of more than one unit is caused by a single insured physical damage loss.
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1 3 Hedging Activities and Fair Value of Financial Instruments SPAS No. 133 Hedging Activities Commodity Prices We are exposed to market risk, including changes in interest Our merchant energy business uses a variety of derivative and rates and the impact of market fluctuations in the price and non-derivative instruments to manage the commodity price risk transportation costs of electricity, natural gas, and other of our competitive supply activities and our elearic generation commodities. facilities, including power sales, fuel and energy purchases, gas purchased for resale, emission credits, weather risk, and the Interest Rates market risk of outages. In order to manage these risks, wevmay We use interest rate swaps to manage our interest rate exposures enter into fixed-price derivative or non-derivative contracts to associated with new debt issuances and to optimize the mix of hedge the variability in future cash flows from forecasted sales of fixed and floating-rate debt. The swaps used to manage our energy and purchases of fuel and energy. The objectives for exposure prior to the issuance of new debt are designated as entering into such hedges include-cash-flow hedges under SFAS No. 133, Accountingfor Derivative
- fixing the price for a portion of anticipated future Instruments and Hedging Activities, as amended, with the effective electricity sales at a level that provides an acceptable portion of gains and losses, net of associated deferred income tax return on our electric generation operations, effects, recorded in "Accumulated other comprehensive income"
- fixing the price of a portion of anticipated fuel in our Consolidated Statements of Common Shareholders' purchases for the operation of our power plants, Equity and Comprehensive Income and Consolidated Statements
- fixing the price for a portion of anticipated energy of Capitalization, in anticipation of planned financing purchases to supply our load-serving customers, and transactions. We reclassify gains and losses on the hedges from
- fixing the price for a portion of anticipated sales of "Accumulated other comprehensive income" into "Interest natural gas to customers.
expense" in our Consolidated Statements of Income during the The portion of forecasted transactions hedged may vary periods in which the interest payments being hedged occur. based upon management's assessment of market, weather, The swaps used to optimize the mix of fixed and floating- operational, and other factors.
rate debt are designated as fair value hedges under SFAS At December 31, 2004, our merchant energy business had No. 133. We record any gains or losses on swaps that qualify for designated certain fixed-price forward contracts as cash-flow fair value hedge accounting treatment, as well as changes in the hedges of forecasted sales of energy and forecasted purchases of fair value of the debt being hedged, in "Interest expense," and fuel and energy for the years 2005 through 2011 under SFAS we record any changes in fair value of the swaps and the debt in No. 133. Our merchant energy business had net unrealized "Risk management assets and liabilities" and 'Long-term debt" pre-tax losses on these cash-flow hedges recorded in in our Consolidated Balance Sheets. In addition, we record the "Accumulated other comprehensive income" of $103.8 million at difference between interest on hedged fixed-rate debt and December 31, 2004 and net unrealized pre-tax gains of
$16.1 million at December 31, 2003. We expect to reclassify floating-rate swaps in 'Interest expense" in the periods that the
$154.5 million of net pre-tax gains on cash-flow hedges from swaps settle.
"Accumulated other comprehensive income" into earnings during At December 31, 2004 and 2003, we had net unrealized the next twelve months based on the market prices at pre-tax gains on interest rate cash-flow hedges recorded in December 31, 2004. However, the actual amount reclassified
'Accumulated other comprehensive income" of $18.3 million into earnings could vary from the amounts recorded at and $21.2 million, respcaively. We expect to reclassify December 31, 2004, due to future changes in market prices.
$2.9 million of pre-tax net gains on these cash-flow hedges from Additionally, for cash-flow hedges settled by physical delivery of "Accumulated other comprehensive income" into "Interest the underlying commodity, "Reclassification of net gains on expense" during the next twelve months. We had no hedge hedging instruments from OCI to net income" represents the ineffectiveness on these swaps. fair value of those derivatives, which is realized through gross During 2004, to optimize the mix of fixed and floating-rate settlement at the contract price. In 2004, we recognized debt, we entered into interest rate swaps qualifying as fair value $3.0 million of pre-tax losses in earnings related to cash-flow hedges relating to $450 million of our fixed-rate debt maturing hedge ineffectiveness.
in 2012 and 2015, and converted this notional amount of debt Our merchant energy business also enters into natural gas to floating-rate. At December 31, 2004, the $13.3 million storage contracts that qualify for fair value hedge accounting increase in the fair value of these hedges, for which there was no treatment under SPAS No. 133. During 2004, we had hedge ineffectiveness, was recorded as an increase in our 'Risk unrealized pre-tax gains of $2.2 million and unrealized pre-tax management assets" and "Long-term debt." losses of $0.4 million due to hedge ineffectiveness, and the resulting pre-tax net gain of $1.8 million was recognized into earnings during 2004. We record changes in fair value of these hedges as a component of "Fuel and purchased energy expenses" in our Consolidated Statements of Income.
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Regulated Gas Business
- investments and other assets: the fair value is based on BGE uses basis swaps in the winter months (November quoted market prices where available, and through March) to hedge its price risk associated with natural
- long-term debt: the fair value is based on quoted gas purchases under its market-based rates incentive mechanism market prices where available or by discounting and under its off-system gas sales program. BGE also uses remaining cash flows at current market rates.
fixed-to-floating and floating-to-fixed swaps to hedge its price We show the carrying amounts and fair values of financial risk associated with its off-system gas sales. The fixed portion instruments included in our Consolidated Balance Sheets in the represents a specific dollar amount that BGE will pay or following table.
receive, and the floating portion represents a fluctuating amount based on a published index that BGE will receive or At December 31, 2004 2003 pay. BGE's regulated gas business internal guidelines do not Carrying Fair Carrying Fair Amount Value Amount Value permit the use of swap agreements for any purpose other than to hedge price risk. (In millions)
Investments and other assets-Fair Value of Financial Instruments Constellation The fair value of a financial instrument represents the amount Energy $1,190.0 $1,191.2 $ 898.7 S 902.2 at which the instrument could be exchanged in a current Fixed-rate long-transaction between willing parties, other than in a forced sale term debt:
or liquidation. Significant differences can occur between the Constellation Energy 4,468.5 4,979.7 5,069.4 5,723.5 fair value and carrying amount of financial instruments that are BGE 1,404.3 1,468.2 1,549.3 1,787.4 recorded at historical amounts. We use the following methods Variable-rare and assumptions for estimating fair value disclosures for long-term financial instruments: debt:
- cash and cash equivalents, net accounts receivable, Constellation Energy 835.6 835.6 323.2 323.2 other current assets, certain current liabilities, BGE 99.3 993 104.1 104.1 short-term borrowings, current portion of long-term debt, and certain deferred credits and other liabilities: Certainprior-year amounts hwave been reclassified to conform U'ith because of their short-term nature, the amounts the currentyears presentation.
reported in our Consolidated Balance Sheets approximate fair value, 1 4 Stock-Based Compensation Under our long-term incentive plans, we granted stock options, In February 2002, our Compensation Committee of the performance and service-based restricted stock, performance- Board of Directors granted options, contingent on shareholder based units, and equity to officers, key employees, and members approval of our long-term incentive plan, with an exercise price of the Board of Directors. Under the plans, we can grant up to equal to the fair market value of our stock on the date of grant a total of 18,000,000 shares. At December 31, 2004, we had of $27.93. Our shareholders approved the plan at the annual stock options, restricted stock, and stock unit grants outstanding meeting in May 2002 when the stock price had increased to as discussed below. BGE officers and key employees participate $31.21. The difference between the exercise price and the fair in our stock-based compensation plans. The expense recognized marker value in May when the shareholder approval contingency by BGE in 2004, 2003, and 2002 was not material to BGE's was satisfied was $6.3 million and is being amortized to financial results. compensation expense over a period up to five years. We recorded compensation expense of $1.0 million in 2004, Non-Qualilfed Stock Options $1.8 million in 2003, and $3.0 million in 2002 related to this Options are granted with an exercise price not less than the grant.
market value of the common stock at the date of grant, become All other stock option grants have an exercise price equal to vested over a period up to five years, and expire ten years from or greater than market value on the date of grant and were not the date of grant. In accordance with APB No. 25, no subject to any future contingencies, therefore no compensation compensation expense is recognized for these awards. 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:
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2004 2003 2002 Wcighted- Wcighted- Wcighted-Average Avcrae Avecra Shares Exercise Price Shares Exercise Price Shares Exercise Price (In thousands, exceptfor eercie prices)
Outstanding, beginning of year 7,117 $29.53 6,081 S29.65 2,646 $30.73 Granted with exercise prices:
At fair market value 1,640 39.60 1,485 29.24 1]708 30.62 Less than fair market value on the date contingency was satisfied (1) - - - - 1,935 27.93 Greater than fair market value - - 9 28.53 103 31.21 Total granted 1,640 39.60 1,494 29.24 3,746 29.25 Exercised (834) 28.49 (267) 27.92 - -
Canceled/Expircd (558) 33.09 (191) 33.28 (311) 34.01 Outstanding, end of year 7,365 $31.62 7,117 $29.53 6,081 $29.65 Exercisable, end of year 3,844 $29.99 3,169 829.89 1.413 $30.78 Weighted-average fair value per share of options granted with exercise prices:
At fair market value $ 7.22 $ 6.80 $ 7.79 Less than fair marker value on the date contingency was satisfied (1) - - 9.15 Greater than fair marker value - 5.56 5.89 (1) Shares were granted in February 2002 with an exercise price equal to the 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 marker 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 We recorded compensation expense related to our options outstanding at December 31, 2004 (stock options in restricted stock awards of $17.0 million in 2004, $16.4 million thousands): in 2003, and $6.6 million in 2002. Summarized share information for our restricted stock awards is as follows:
Wcighted-Stock Average Stock 2004 2003 2002 Range of Options ReainingE Options (In thousands)
Exercise Prices Outstanding Concrncrual Lie Exercisable Outstanding, beginning of year 752 314 435
$21.47 - $25.00 33 7.8 years 18 Granted 1,002 555 344
$25.00 - $30.00 3,678 7.5 years 2,053 Released to participants (467) (109) (170)
$30.00 - $35.00 2,167 6.3 years 1,768 Canceled (64) (8) (295)
$35.00 - $40.72 1,487 9.2 years 5 Outstanding, end of year 1,223 752 314 Restricted Stock Awards Weighted-average fair value restricted stock granted $38.83 $30.53 $27.23 In addition, we issue common stock based on meeting certain performance and/or service goals. This stock vests to participants at various times ranging from one to five years if Performance-Based Units the performance and/or service goals are met. In accordance During 2004, we granted 11.6 million of performance-based with APB No. 25, we recognize compensation expense for our units to officers and key employees of which 1.1 million units performance-based awards using the variable accounting were forfeited prior to year end. Each unit is equivalent to $1 method, whereby we amortize the value of the market price of in value and vests at the end of a three-year service and the underlying stock on the date of grant (adjusted for performance period. The level of payout is based on the subsequent changes in fair market value through the achievement of certain performance goals at the end of the performance measurement date) to compensation expense over three-year period and at least 50% of any payouts will be the service period. WVe account for our service-based awards settled in cash, and the other 50% may be settled in either using the fixed accounting method, whereby we amortize the stock or cash at our discretion. We recorded compensation value of the market price of the underlying stock on the date expense of $2.9 million in 2004 related to these performance-of grant to compensation expense over the service period. We based units.
reverse any expense associated with restricted stock that is canceled or forfeited during the performance or service period. Equity-Based Grants We recorded compensation expense of $0.5 million in 2004,
$0.4 million in 2003, and $0.5 million in 2002 related to equity-based grants to members of the Board of Directors.
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Pro-forma Information We disclose the pro-forma effect on net income and Disclosure of pro-forma information regarding net income and earnings per share in accordance with SFAS No. 148, earnings per share is required under SFAS No. 123, which uses Accountng for Stock-Based Compensauion-Transitonand the air value method. The fair value of our stock-based awards Disclosure, in Note 1. Also, as discussed in more detail in were estimated as of the date of grant using the Black-Scholes Note 1, the FASB issued SFAS No. 123R in December 2004, option pricing model based on the following weighted-average which changed the accounting for stock-based compensation, assumptions: requiring companies to expense stock options and other equity awards based on their grant-date fair values.
2004 2003 2002 Risk-free interest rate 3.15% 2.92% 4.45%
Expected life (in years) 5.0 5.0 5.0 Expected market price volatility factor 23.7% 32.0% 31.9%
Expected dividend yield 3.0% 3.3% 3.3%
I 5 Acquisitions Acquisition of Ginna The intangible assets acquired consist of the following:
On June 10, 2004, we completed our purchase of the Ginna nuclear facility, which is located in Ontario, New York from Weighted-RG&E. Ginna consists of a 495 megawatt reactor that entered Average service in 1970 and is licensed to operate until 2029. Description Amount useful Life We purchased 100 percent of Ginna for $457.3 million (In millions) (In years) including direct costs associated with the acquisition, of which Operating procedures and manuals $261. 25
$430.0 million was paid in cash at dosing and the remaining Permits and licenses 8.5 25 Software 4.2 5
$27.3 million was paid during the second half of 2004. RG&E also transferred to us £200.8 million in decommissioning funds. Total intangible assets $38.8 We wivll sell 90 percent of Ginna's output back to RG&E at an average price of nearly $44 per megawatt-hour until Acquisition of Biackhawk Energy Services and Kaztex June 2014 under a unit contingent power purchase agreement (if Energy Management the output is not available because the plant is not operating, On October 22, 2003, we completed our purchase of Blackhawvk there is no requirement to provide output from other sources). Energy Services (Blackhawk) and Kaztex Energy Management The acquisition of Ginna was immediately accretive to earnings. (Kaztex). We include Blackhawk and Kaztex, part of our retail We accounted for this transaction as an asset acquisition gas operation, in our merchant energy business segment and and included Ginna in our merchant energy business segment. have included their results in our consolidated financial Our purchase price allocation for the net assets acquired is as statements since the date of acquisition. Blackhawk and Kaztex follows: are providers of natural gas and electricity services. At the time of the acquisition, Blackhawk and Kaztex served approximately Arjune 10, 2004 1,100 customers representing approximately 70 billion cubic feet (In million") of natural gas and 0.9 million megawatt hours of electricity Current Assets $ 27.9 throughout Illinois and SXisconsin. We acquired 100%
Nuclear Decommissioning Trust Fund 200.8 ownership of both companies for $26.9 million cash. We Nuclear Fuel 14.5 Net Property, Plant and Equipment 382.8 acquired cash of $1.2 million as part of the purchase.
Intangible Assets (details below) 38.8 Other Assets 124.0 Total Assets Acquired 788.8 Current Liabilities (20.8)
Asset Retirement Obligations (177.3)
Deferred Credits and Other Liabilities (133.4)
Net Assets Acquired $457.3 112
Our purchase price allocation for the net assets acquired is NXWebelieve that the pro-forma impact on "Income before as follows: cumulative effect of change in accounting principle," "Net income," and "Earnings per common share" would not have At October 2Z 2003 been material had the acquisition of Blackhawk and Kaztex (7n milhiom) occurred on the first day of each of the years presented.
Cash $ 1.2 Other Current Assets 41.0 Acquisition of the High Desert Power Project Total Current Assets 42.2 In April 2003, our High Desert Power Project in Victorville, Net Property, Plant and Equipment 0.1 California, an 830 megawatt (MW) gas-fired combined cycle Goodwill 25.9 facility, commenced operations. The project has a long-term Other Assets 0.9 power sales agreement with the California Department of Water Total Assets Acquired 69.1 Resources (CDVR). The contract is a 'tolling" structure, under Current Liabilities (40.8) which the CDWR pays a fixed amount of $12.1 million per Deferred Credits and Other Liabilities (1.4) month and provides CDNWIR the right, but not the obligation, to Net Assets Acquired $26.9 purchase power from the project at a price linked to the variable We recorded the existing contracts at fair value as part of cost of production. During the term of the contract, which runs for seven years and nine months from the April 2003 the purchase price allocation. The fair value of the contracts was commercial operation date of the plant, the project will provide a net liability of $0.4 million. We recorded the fair value of these contracts as follows: energy exclusively to the CDWR.
Prior to June 2003, we accounted for this proiect as an Nerfair salu. of ae'qired contratct operating lease. In June 2003, we elected to refinance the lease (In millions) to extend the tenor of the financing at attractive interest rates.
Current Assets $ 3.2 Accordingly, we exercised our option under the lease associated Noncurrent Assets 0.1 with the High Desert Power Project, paid off the lease, and acquired the assets from the lessor. Beginning June 30, 2003, the Total Assets 3.3 assets and liabilities associated with the High Desert Power Current Liabilities (2.3) Project were included in our Consolidated Balance Sheets. We Noncurrent liabilities (1.4) accounted for this transaction as an asset acquisition and Total Liabilities (3.7) included the High Desert Power Project in our merchant energy Net fair value of acquired contracts $(0.4) segment.
Our purchase price allocation for the net assets acquired is Acquired contracts include both executory contracts and as follows:
risk management liabilities associated with certain hedges. We are amortizing the acquired executory contracts over a period At June 27, 2003 extending through 2008. The weighted-average amortization (In millions) period is approximately 20 months and represents the expected Cash S 4.3 contract duration. The risk management liabilities are accounted Other Current Assets 1.6 for as described in Note 1. Other Noncurrent Assets 1.7 On an unaudited pro-forma basis, had the acquisition of Net Property Plant and Equipment 528.3 Blackhawk and Kaztex occurred on the first day of each of the Total Assets Acquired 535.9 periods presented below, our nonregulated revenues and total Accounts Payable (17.5) revenues would have been as follows: $518.4 Net Assets Acquired Year Ended December31, 2003 2002 (In millions)
Aonreguaied revenues As reported 7,053.6 2,182.5 Pro-forma 7,408.5 2,410.0 Total reventues As reported 9,687.8 4,718.6 Pro-forma 10,042.7 4,946.1 113
Acquisition of Alliance Acquisition of NewEnergy On December 31, 2002, we purchased Alliance Energy Services, On September 9, 2002, we purchased AES NewEnergy, Inc.
LLC and Fellon-McCord Associates, Inc. (collectively, Alliance) from AES Corporation. Subsequent to the acquisition, we from Allegheny Energy, Inc. We include Alliance (renamed renamed AES NcwEnergy, Inc. as Constellation NewEnergy, Inc.
Constellation NewEnergy Gas in 2004), our retail gas operation, (NewEnergy). WXe include NewEnergy, our retail electric in our merchant energy business segment and have included operation, in our merchant energy business segment and have their results in our consolidated financial statements since the included their results in our consolidated financial statements date of acquisition. These businesses provide gas supply and since the date of acquisition. NewEnergy is a leading national transportation services and energy consulting services to provider of electricity, natural gas, and energy services, serving commercial and industrial customers primarily in the Midwest approximately 4,300 megawatts of load at acquisition associated region, but also in other competitive energy markets including with commercial and industrial customers in competitive energy the Northeast, Mid-Atlantic, Texas and California regions. markets including the Northeast, Mid-Atlantic, Midwest, Texas On an unaudited pro-forma basis, had the acquisition of and California.
our retail gas operation occurred on the first day of 2002, our On an unaudited pro-forma basis, had the acquisition of nonregulated revenues and total revenues would have been as NewEnergy occurred on the first day of 2002, our nonregulated follows: revenues and total revenues would have been as follows:
Year Ended December 31, Year Ended December 31, (In millions) (In millions)
ANonregueited revenues Nonregulatedrevenues As reported $2,182.5 As reported $2,182.5 Pro-forma 2,722.2 Pro-forma 3,323.3 Total revenues Total revenues As reported $4.718.6 As reported $4,718.6 Pro-forma 5,258.3 Pro-forma 5,859.4 We believe that the pro-forma impact on "Income before We believe that the pro-forma impact on "Income before cumulative effca of change in accounting principle," "Net cumulative effect of change in accounting principle," 'Net income," and "Earnings per common share" would not have income," and "Earnings per common share" would not have been material had the acquisition of our retail gas operation been material had the acquisition of NewEnergy occurred on the occurred on the first day of each of the years presented. first day of each of the years presented.
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1 6 Related Party Transactions-BCGE Income Statement Balance Sheet BGE provides standard offer service to those customers that do BGE participates in a cash pool under a Master Demand Note not choose an alternate supplier. Our wholesale marketing and agreement with Constellation Energy. Under this arrangement, risk management operation provided BGE with the energy and participating subsidiaries may invest in or borrow from the pool capacity required to meet its commercial and industrial standard at market interest rates. Constellation Energy administers the offer service obligations through June 30, 2004 and provides the pool and invests excess cash in short-term investments or issues energy and capacity required to meet its residential standard commercial paper to manage consolidated cash requirements.
offer service obligations through June 30, 2006. Effective July 1, Under this arrangement, BGE had invested $127.9 million at 2004, BGE executed one and two-year contracts for commercial December 31, 2004 and $230.2 million at December 31, 2003.
and industrial electric power supply totaling approximately 2,300 Amounts related to corporate functions performed at the megawatts. Our wholesale marketing and risk management Constellation Energy holding company, BGE's purchases to meet operation is supplying a significant portion of this electric power its standard offer service obligation, BGE's charges to supply. Constellation Energy and its nonregulared affiliates for certain The cost of BGE's purchased energy from nonregulated services it provides them, and the participation of BGE's affiliates of Constellation Energy to meet its standard offer employees in the Constellation Energy pension plan result in service obligation was as follows: intercompany balances on BGE's Consolidated Balance Sheets.
We believe our allocation methods are reasonable and On'r Ended December 31, 2004 2003 approximate the costs that would be charged to unaffiliated (In millions) entities.
Electricity purchased for resale expenses $ 948.9 $1,023.4 $1,080.5 In addition, Constellation Energy charges BGE for the costs of certain corporate functions. Certain costs are directly assigned to BGE. We allocate other corporate function costs based on a total percentage of expeced use by BGE. We believe this method of allocation is reasonable and approximates the cost BGE would have incurred as an unaffiliated entity. These costs were:
- $99.8 million for the year ended December 31, 2004,
- S84.0 million for the year ended December 31, 2003, and
- $37.6 million for the year ended December 31, 2002.
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1 7 Quarterly Financial Data (Unaudited)
Our quarterly financial information has not been audited but, in managements opinion, includes all adjustments necessary for a fair prescntation. Our business is seasonal in nature with the peak sales periods generally occurring during the summer and winter months. Accordingly, comparisons among quarters of a year may not represent overall trends and changes in operations.
2004 Quarterly Data-Constellatin Energy 2004 Quarterly Djt3-BGE Income Before Cumulative Earnings P r Earnings Per Effects of Earnings Shim o Share of Earnin' Income Changes in Applies Ic Contnuing Common Income AppliesI from Accounting to Common Operations- Stock- from to Common Revenues Operations Principles Stock Diluted Diluted Revenues Operations Stock (In millins. Or per sarr Fmounts) (In millions)
Quarter Ended Quarter Ended March 31 S 3,036.6 $ 235.7 5112.5 S 66.2 50.66 $ 0.39 March 31 S 803.9 $149.8 S 72.7 June 30 2,793.0 195.9 130.9 128.2 0.77 0.76 June 30 589.8 65.6 21.9 September 30 3,434.5 396.5 210.6 210.4 1.19 1.19 September 30 657.3 77.1 28.1 December 31 3,285.6 249.1 134.8 134.9 0.76 0.76 December 31 673.7 78.9 30.4 Year Ended YWarEnded December 31 $12549.7 $1,077.2 $588.8 S 539.7 $3.40 $ 3.12 December 31 $2,724.7 $371.4 S153.1 The sum of the quarterly earningsper share amounts may not equal the totalfor the year due to the effocts of rounding and dilution as a result of issuing common shares during theyear.
First quarter results include:
Constellation Energy
- a $46.3 million loss after-tax for the discontinued operations of our Hawaiian geothermal facility, and
- gain on the sale of investments and other assets of $1.0 million after-tax.
Second quarter results include:
Constellation Energy
- recognition of 2003 synfuel tax credits of $35.9 million after-tax,
- a $2.7 million loss after-tax for the discontinued operations of our Hawaiian geothermal facility,
- gain on the sale of investments of $2.7 million after-tax, and
- an other than temporary decline in value of our investments of $1.6 million after-tax.
Third quarter results include:
Constellation Energy
- net loss on sale of investment and other assets of $4.6 million after-tax,
- an other than temporary decline in value of our investments of $0.6 million after-tax, and
- a $0.2 million loss after-tax for the discontinued operations of our }-lawaiian geothermal facility.
Fourth quarter results include:
Constellation Energy
- workforce reduction costs totaling $5.9 million after-tax,
- net gain on sale of investments of $0.3 million after-tax, and
- a $0.1 million gain after-tax for the discontinued operations of our Hawaiian geothermal facility.
We discuss our special items in Note 2.
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2003 Quarterly Data-Consnellation Energy 2003 Quarterly Dat&-BGE Earnings Per Share Assuming Dilution Income Before Before Cumulative (Loss)
Cumulative (Loss) Effeas of Earnings Effecus of Earnings Changes in Per Share of Earnings Income Changs in Appliablc Acountng Common Income ib from Accounting o Common rtindcples- Stock- from7 o = locmn Revenues Operations PrincipleZ Stock Diluted Diluted Revenues Openrtions Stock (In mil5:enr. erceppar ,/srs Omeners) (Jfr m;itins)
Quarter Ended Quarter Ended March 31 S 2.326.1 S 175.6 S 67.0 S (131.4) S 0.40 S (0.80) March 31 $ 789.8 S164.6 $ 78.5 June 30 2266.6 229.1 96.8 96.8 0.58 0.58 June 30 577.0 69.2 21.7 September30 2.600.6 389.2 192.9 192.9 1.15 1.15 September 30 663.3 62.8 20.6 December31 2.494.5 272.A 119.0 119.0 0.71 0.71 December 31 617.5 88.4 29.2 Year Ended Year Ended December 31 S 9.687.8 S 1.0663 S 475.7 S 277.3 S 2.85 S 1.66 December 31 12.647.6 S385.0 $150.0 The sumn of the quarterly earningsper share amounts may not equal the totalfor the year due to the efects of rounding and dilution as a result of issuing common shares during the year.
Certainprior-periodamounts have been reclasified to conform with the current years presentation.
First quarter results include:
Contellation Energy and BGE
- workforce reduction costs totaling $0.4 million after-tax, of which BGE recorded $0.1 million.
Constellation Energy
- a $266.1 million loss after-tax for the cumulative effect of adopting EITF 02-3,
- a $67.7 million gain after-tax for the cumulative effect of adopting SFAS 143, and
- gain on the sale of investments and other assets of $8.3 million after-tax.
Second quarter results include:
Constellation Energ and BGE
- workforce reduction costs totaling $0.4 million after-tax, of which BGE recorded $0.1 million.
Constellation Energy
- gain on the sale of investments of $0.3 million after-rtx.
Third quarter results include:
Constellation Energy and BGE
- workforce reduction costs totaling $0.5 million after-tax, of which BGE recorded $0.2 million.
Constellation Energy
- net gain on sale of investment and other assets of $1.4 million after-tax.
Fourth quarter results include.
Constellation Energy
- net gain on sale of investments of $6.4 million after-tax and,
- an other than temporary decline in the value of our investment in an airplane of $0.4 million after-tax.
We discuss our special items in Note 2.
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Item 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure None.
Item 9A. Controls and Procedures Evaluation of Disclosure Controls and Procedures The principal executive officers and principal financial officer of both Constellation Energy and BGE have evaluated the effectiveness of the disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act")) as of December 31, 2004 (the
'Evaluation Date"). Based on such evaluation, such officers have concluded that, as of the Evaluation Date, Constellation Energys and BGE'S disclosure controls and procedures arc effective, in that they provide reasonable assurance that such officers are alerted on a timely basis to material information relating to Constellation Energy and BGE that is required to be included in Constellation Energys and BGE's periodic filings under the Exchange Act.
Internal Control Over FinancialReporting Constellation Energy maintains a system of internal control over financial reporting as defined in Exchange Act Rule 13a-15(f). Constellation Energy's Management Report on Internal Control Over Financial Reporting is included in Item 8. Financial Statements and Supplementary Data included in this report. As BGE is not an accelerated filer as defined in Exchange Act Rule 12b-2, it is not required to provide a report of management on the effectiveness of its internal control over financial reporting as of December 31, 2004, but will be required to do so as of December 31, 2006.
Changes In Internal Control During the quarter ended December 31, 2004, there has been no change in either Constellation Energys or BGE'S internal control over financial reporting (as such term is defined in Rules 13a -15(f) and 15d-15(f) under the Exchange Act) that has materially affected, or is reasonably likely to materially affect, either Constellation Energy's or BGE's internal control over financial reporting.
Subsequent to this reporting period, during January 2005, Constellation Energy implemented a new enterprise reporting platform, which included a general ledger and various sub-ledgers, for certain of its operating subsidiaries.
Following this implementation, substantially all of Constellation Energy's operating subsidiaries are using the new system. The implementation affected systems that indude certain internal controls, and accordingly, the implementation has required revisions to our internal control over financial reporting. We reviewed the system as it was implemented as well as the controls affected by the implementation of the system and made appropriate changes to affeacd internal controls.
Item 9B. Other Information None.
PART Ill - The information required by this item with respect BGE meets the conditions set forth in General to executive officers of Constellation Energy Group, Instruction l(l)(a)and (b) of Form 10-K for a reduced pursuant to instruction 3 of paragraph (b) of Item 401 disclosure format. Accordingly, all items in this section of Regulation S-K, is set forth following Item 4 of related to BGE are not presented. Part I of this Form 10-K under Executive Officers of the Registrant.
Item 10. Directors and Executive Officers of the Registrant Item 11. Executive Compensation The information required by this item with respect to The information required by this item is set forth under directors is set forth under Fkction of Constellation Directors'Compensation, Erecutive Compensation, Energy Directors in the Proxy Statement and is Common Stock Performance Graph and Report of incorporated herein by reference. Compensation Committee on Executive Compensation in the Proxy Statement and is incorporated herein by reference.
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Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters Equity Compensation Plan Information The following table reflects our equity compensation plan information as of December 31, 2004:
(a) (b) (c)
Number of securities Number of securities remair iing to be issued upon Weighted-average available for future issuanc:e exercise of exercise price of under equity compensatio n outstanding options, outstanding options, plans (excluding securities Plan Category warrants, and rights warrants, and rights reflected in item (a))
(In thousands) (In thousands)
Equity compensation plans approved by security holders 5,346 $32.18 3,814 Equity compensation plans not approved by security holders 2,019 $30.14 2,071 Total 7,365 $31.62 5,885 The plans that do not require security holder approval are the Consteliation Energy Group, Inc. 2002 Senior Management Long-Tcrm Incentive Plan (Designated as Exhibit No. 10(V)) and the Constellation Energy Group, Inc.
Management Long-Term Incentive Plan (Designated as Exhibit No. 10(w)). A brief description of the material features of each of these plans is set forth below.
2002 Senior Management Long-Term Incentive Plan The 2002 Senior Management Long-Term Incentive Plan was effective May 24, 2002. Grants under the plan may be made to employees who are officers of Constellation Energy or hold senior management level or key employee positions with Constellation Energy or its subsidiaries. Under the plan, the Board of Constellation Energy has authorized the issuance of up to 5,000,000 shares of Constellation Energy common stock in connection with the grant of stock options, performance and service-based restricted stock and restricted stock units, performance units, stock appreciation rights, dividend equivalents and other equity awards. Any shares covered by an award that is forfeited or canceled, expires or is settled in cash, induding the settlement of tax withholding obligations using shares, will become available for issuance under the plan. Shares delivered under the plan may be authorized and unissued shares, shares held in treasury or shares purchased on the open market in accordance with the applicable securities laws. Restricted stock, restricted stock unit and performance unit award payouts will be accelerated and stock options and stock appreciation rights gains will be paid in cash in the event of a change in control, as defined in the plan. The plan is administered by Constellation Energy's Chief Executive Officer.
Management Long-Tern Incentive Plan The Management Long-Term Incentive Plan was ceffcaive February 1, 1998. Grants under the plan may be made to employees of Constellation Energy who hold a management level position and other employees of Constellation Energy and its subsidiaries as may be designated by Constellation Encrgys Chief Executive Officer. Under the plan, the Board of Constellation Energy has authorized the issuance of up to 3,000,000 shares of Constellation Energy common stock in connection with the grant of stock options, performance and service-bascd restricted stock and restricted stock units, performance units, stock appreciation rights and dividend equivalents. The number of shares available for issuance under the plan includes shares subject to awards that have lapsed or terminated. Shares delivered under the plan may be authorized and unissued shares, shares held in treasury or shares purchased on the open market in accordance with applicable securities laws. Restricted stock, restricted stock unit and performance units award payouts will be accelerated and stock options and stock appreciation rights will become fully exercisable in the event of a change in control, as defined by the plan. The plan is administered by Constellation Energy's Chief Executive Officer.
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Item 13. Certain Relationships and Related Transactions The additional information required by this item is set forth under Certain Reationshs and Transactions in the Proxy Statement and is incorporated herein by reference.
Item 14. Principal Accountant Fees and Services The information required by this item is set forth under Proposal No. 2-Ratfication ofAppointuent of PriceuwaterhouseCoopersLLP as Independent Registered PublicAccounting Firm for 2005 in the Proxy Statement and is incorporated herein by reference.
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PART IV Item 15. Exhibits and Financial Statement Schedules (a) The following documents are filed as a part of this Report:
- 1. Financial Statements:
Reports of Independent Registered Public Accounting Firm dated March 10, 2005 of PricewatcrhouseCoopers LLP Consolidated Statements of Income-Constellation Energy Group for three years ended December 31, 2004 Consolidated Balance Sheets-Constellation Energy Group at December 31, 2004 and December 31, 2003 Consolidated Statements of Cash Flowvs-Constellation Energy Gmup for three years ended December 31, 2004 Consolidated Statements of Common Shareholders' Equity and Comprehensive Income-Constellation Energy Group for three years ended December 31, 2004 Consolidated Statements of Capitalization-Constellation Energy Group at December 31, 2004 and December 31, 2003 Consolidated Statements of Income-Baltimore Gas and Electric Company for three years ended December 31, 2004 Consolidated Statements of Comprehensive Income-Baltimore Gas and Electric Company for three years ended December 31, 2004 Consolidated Balance Sheets-Baltimore Gas and Electric Company at Deceniber 31, 2004 and December 31, 2003 Consolidated Statements of Cash Flows-Baltimore Gas and Electric Company for three years ended December 31, 2004 Notes to Consolidated Financial Statements
- 2. Financial Statement Schedules:
Schedule Il-Valuation and Qualifying Accounts Schedules other than Schedule 11 are omitted as not applicable or not required.
- 3. Exhibits Required by Item 601 of Regulation S-K.
Exhibit Number 2 - Agreement and Plan of Share Exchange between Baltimore Gas and Electric Company and Constellation Energy Group, Inc. dated as of February 19, 1999. (Designated as Exhibit No. 2 to the Registration Statement on Form S4 dated March 3, 1999, File No. 33-64799.)
- 2(a) - Agreement and Plan of Reorganization and Corporate Separation (Nuclear). (Designated as Exhibit No. 2(a) to the Current Report on Form 8-K dated July 7, 2000, File Nos. 1-12869 and 1-1910.)
- 2(b) - Agreement and Plan of Reorganization and Corporate Separation (Fossil). (Designated as Exhibit No. 2(b) to the Current Report on Form 8-K dated July 7, 2000, File Nos. 1-12869 and 1-1910.)
- 3(a) - Articles of Amendment and Restatement of the Charter of Constellation Energy Group, Inc. as of April 30, 1999. (Designated as Exhibit No. 99.2 to the Current Report on Form 8-K dated April 30, 1999, File No. 1-1910.)
'3(b) - Articles Supplementary to the Charter of Constellation Energy Group, Inc., as of July 19, 1999.
(Designated as Exhibit No. 3(a) to the Quarterly Report on Form IO-Q for the quarter ended June 30, 1999, File Nos. 1-12869 and 1-1910.)
- 3(c) - Certificate of Correction to the Charter of Constellation Energy Group, Inc. as of September 13, 1999.
(Designated as Exhibit No. 3(c) to the Annual Report on Form 10-K for the year ended December 31, 1999, File Nos. 1-12869 and 1-1910.)
- 3(d) - Charter of BGE, restated as of August 16, 1996. (Designated as Exhibit No. 3 to the Quarterly Report on Form I0-Q for the quarter ended September 30, 1996, File No. 1-1910.)
- 3(e) - Articles Supplementary to the Charter of Constellation Energy Group, Inc. as of November 20, 2001.
(Designated as Exhibit No. 3(e) to the Annual Report on Form 10-K for the year ended December 31, 2001, File Nos. 1-12869 and 1-1910.)
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- 3(f) - Bylaws of Constellation Energy Group, Inc., as amended to February 27, 2004. (Designated as Exhibit 3(a) to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, File Nos.
1-12869 and 1-1910.)
- 3(g) - Bylaws of BGE, as amended to October 16, 1998. (Designated as Exhibit No. 3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 1998, File No. 1-1910.)
- 4(a) - Indenture bcvteen Constellation Energy Group, Inc. and the Bank of New York, Trustee dated as of March 24, 1999. (Designated as Exhibit No. 4(a) to the Registration Statement on Form S-3 dated March 29, 1999, File No. 333-75217.)
'4(b) - First Supplemental Indenture between Constellation Energy Group, Inc. and the Bank of New York, Trustee dated as of January 24, 2003. (Designated as Exhibit No. 4(b) to the Registration Statement on Form S-3 dated January 24, 2003, File No. 333-102723.)
- 4(c) - Supplemental Indenture between BGE and Bankers Trust Company, as Trustee, dated as of June 20, 1995, supplementing, amending and restating Deed of Trust dated February 1, 1919. (Designated as Exhibit No. 4 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 1995, File No. 1-1910); 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)
'February 15, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(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 10-Q dated August 13, 1996) 4
- 4(d) -Indenture dated July I, 1985, between BGE and The Bank of New York (Successor to Mercantile-Safe Deposit and Trust Company), Trustee. (Designated as Exhibit 4(a) to the Registration Statement on Form S-3, File No. 2-98443); as supplemented by Supplemental Indentures dated as of October 1, 1987 (Designated as Exhibit 4(a) to the Current Report on Form 8-K, dated November 13, 1987, File No. 1-19 10) and as of January 26, 1993 (Designated as Exhibit 4(b) to the Current Report on Form 8-K, dated January 29, 1993, File No. 1-1910.)
'4(e) -Form of Subordinated Indenture between the Company and The Bank of New York, as Trustee in connection with the issuance of the Junior Subordinated Debentures. (Designated as Exhibit 4(d) to the Registration Statement on Form S-3 dated August 5, 2003, File No. 333-107681.)
'4(f) -Form of Supplemental Indenture between the Company and The Bank of New York, as Trustee in connection with the issuances of the Junior Subordinated Debentures. (Designated as Exhibit 4(c) to the Registration Statement on Form S-3 dated August 5, 2003, File No. 333-107681.)
'4(g) -Form of Preferred Securities Guarantee (Designated as Exhibit 4(f) to the Registration Statement on Form S-3 dated August 5, 2003, File No. 333-107681.)
'4(h) - Form of Junior Subordinated Debenture (Designated as Exhibit 4(h) to the Registration Statement on Form S-3 dated August 5, 2003, File No. 333-107681.)
'4(i) - Form of Amended and Restated Declaration of Trust (including Form of Preferred Security) (Designated as Exhibit 4(c) to the Registration Statement on Form S-3 dated August 5, 2003, File No. 333-107681.)
- 10(2) - Executive Annual Incentive Plan of Constellation Energy Group, Inc., as amended and restated.
(Designated as Exhibit No. 10(a) to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, File Nos. 1-12869 and 1-1910.)
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'10(b) - Constellation Energy Group, Inc. 1995 Long-Term Incentive Plan, as amended and restated. (Designated as Exhibit No. IO(b) to the Quarterly Report on Form I0-Q for the quarter ended September 30, 2004, File Nos. 1-12869 and 1-1910.)
'10(c) - Constellation Energy Group, Inc. Nonqualified Deferred Compensation Plan, as amended and restated.
(Designated as Exhibit No. 10(c) to the Annual Report on Form 10-K for the year ended December 31, 2002, File Nos. 1-12869 and 1-1910.)
10(d) - Constellation Energy Group, Inc. Deferred Compensation Plan for Non-Employee Directors, as amended and restated.
'10(e) - Compensation agreements between Constellation Energy Group, Inc. and E. Follin Smith (Attachment I-Employment Agreement; Attachment 2-Severance Agreement). (Designated as Exhibit 10(c) to the Quarterly Report on Form I0-Q for the quarter ended June 30, 2004, File Nos.
1-12869 and 1-1910.)
'10(f) - Change in control severance agreement between Constellation Energy Group, Inc. and Thomas V.
Brooks. (Designated as Exhibit 1O(f) to the Quarterly Report on Form I0-Q for the quarter ended March 31, 2004, File Nos. 1-12869 and 1-1910.)
'10(g) - Grantor Trust Agreement Dated as of February 27, 2004 between Constellation Energy Group, Inc. and Citibank, N.A. (Designated as Exhibit No. 1O(d) to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, File Nos. 1-12869 and 1-1910.)
'10(h) - Change in control severance agreement between Constellation Energy Group, Inc. and Mayo A. Shattuck 111. (Designated as Exhibit 10(e) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2004, File Nos. 1-12869 and 1-1910.)
'10(i) - Grantor Trust Agreement dated as of February 27, 2004 between Constellation Energy Group, Inc. and T. Rowe Price Trust Company. (Designated as Exhibit No. 10(b) to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, File Nos. 1-12869 and 1-1910.)
- 10(j) - Full Requirements Service Agreement between Constellation Power Source, Inc. and Baltimore Gas and Electric Company. (Designated as Exhibit No. 10(a) to the Quarterly Report on Form I0-Q for the quarter ended June 30, 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) to the Quarterly Report on Form 10-Q for the quarter ended 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(l) - Full Requirements Service Agreement between Baltimore Gas and Electric Company and Allegheny Energy Supply Company, LL.C. (Designated as Exhibit No. 10(b) to the Quarterly Report on Form I 0-Q for the quarter ended September 30, 2001, File Nos. I -12869 and 1-1910.) (Portions of this exhibit have been omitted pursuant to a request for confidential treatment.)
'10(m) - Consent to Assignment and Assumption Agreement by and among Allegheny Energy Supply, LL.C. and Baltimore Gas and Electric Company and Constellation Power Source, Inc. (Designated as Exhibit 10(1) to the Quarterly Report on Form I0-Q for the quarter ended June 30, 2003, File Nos. 1-12869 and 1-1910.) (Portions of this exhibit have been omitted pursuant to a request for confidential treatment.)
'10(n) - 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(o) - Constellation Energy Group, Inc. Supplemental Pension Plan, as amended and restated. (Designated as Exhibit No. 10(d) to the Quarterly Report on Form I0-Q for the quarter ended March 31, 2004, File Nos. 1-12869 and 1-1910.)
'I O(p) - Constellation Energy Group, Inc. Senior Executive Supplemental Plan, as amended and restated.
(Designated as Exhibit No. 10(e) to the Quarterly Report on Form I0-Q for the quarter ended March 31, 2004, File Nos. 1-12869 and 1-1910.)
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'10(q) - 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(r) - Change in control severance agreement between Constellation Energy Group, Inc. and Michael J.
Wallace. (Designated as Exhibit 10(f) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2004, File Nos. 1-12869 and 1-1910.)
10(s) - Change in control severance agreement between Constellation Energy Group, Inc. and Thomas F. Brady.
'10(t) - Constellation Energy Group, Inc. Executive Long-Term Incentive Plan, as amended and restated.
(Designated as Exhibit 10(d) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2004, File Nos. 1-12869 and 1-1910.)
'10(u) - Constellation Energy Group, Inc. 2002 Executive Annual Incentive Plan, as amended and restated.
(Designated as Exhibit 10(h) to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, File Nos. 1-12869 and 1-1910.)
'10(v) - Constellation Energy Group, Inc. 2002 Senior Management Long-Term Incentive Plan, as amended and restated. (Designated as Exhibit 10(c) to the Quarterly Report on Form I0-Q for the quarter ended September 30, 2004, File Nos. 1-12869 and 1-1910.)
- 10(w) - Constellation Energy Group, Inc. Management Long-Term Incentive Plan, as amended and restated.
(Designated as Exhibit 10(a) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2004, File Nos. 1-12869 and 1-1910.)
10(x) - Summary of Constellation Energy Group, Inc. Board of Directors 2005 Non-Employee Director Compensation Program.
12(a) - Constellation Energy Group, Inc. and Subsidiaries Computation of Ratio of Earnings to Fixed Charges.
12(b) - Baltimore Gas and Electric Company and Subsidiaries Computation of Ratio of Earnings to Fixed Charges and Computation of Ratio of Eamings to Combined Fixed Charges and Preferred and Preference Dividend Requirements.
21 - Subsidiaries of the Registrant.
23 - Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm.
31 (a) - Certification of Chairman of the Board, Chief Executive Officer and President of Constellation Energy Group, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31 (b) - Certification of Executive Vice President and Chief Financial Officer of Constellation Energy Group, Inc.
pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31 (c) - Certification of President and Chief Executive Officer of Baltimore Gas and Electric Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(d) - Certification of Senior Vice President and Chief Financial Officer of Baltimore Gas and Electric Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32(a) - Certification of Chairman of the Board, Chief Executive Officer and President of Constellation Energy Group, Inc. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32(b) - Certification of Executive Vice President and Chief Financial Officer of Constellation Energy Group, Inc.
pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32(c) - Certification of President and Chief Executive Officer of Baltimore Gas and Electric Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32(d) - Certification of Senior Vice President and Chief Financial Officer of Baltimore Gas and Electric Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
124
CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES AND BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES SCHEDULE II-VALUATION AND QUALIFYING ACCOUNTS Column A Column B Column C Column D Column E Additions Balance Charged Charged to at to costs Oher Balance at b eginning and Accounts- (Deductions)- end of Description o perod expenses Describe Describe period (In millions)
Reserves deducted in the Balance Sheet from the assets to which they apply:
Constellation Energy Accumulated Provision for Uncollecnibles 2004 $ 51.7 $22.2 1- $ (30.8)(A) $ 43.1 2003 41.9 22.0 (12.2)(A) 51.7 2002 22.8 26.4 12.5 (B) (19.8)(A) 41.9 Valuation Allowance-Net unrealized (gain) loss on available for sale securities 2004 _ _ 0.1 (C) 0.1 2003 2002 (243.7) - 243.7 (C)
Net unrealized (gain) loss on nuclear decommissioning trust funds 2004 (13.7) (59.6)(C) (73.3) 2003 47.4 (61.1)(C) (13-7) 2002 (21.0) 68.4 (C) 47.4 BGE Accumulated Provision for Uncollectibles 2004 10.7 16.3 - (14.0)(A) 13.0 2003 11.5 9.0 - (9.8)(A) 10.7 2002 13.4 14.5 - (16.4)(A) 11.5 (A) Represents principally net amounts charged off as uncollectible.
(B) Represents amounts acquired resulting from our acquisitions of NewvEnergy and Alliance.
(C) Represents amounts recorded in or reclassified from accumulated other comprehensive income.
125
SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Constellation Energy Group, Inc., the Registrant, has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.
CONSTELLATION ENERGY GROUP, INC.
(REGISTRANT)
Date: March 11, 2005 By 1sf MAYO A. StAlTuCK III Mayo A. Shattuck 111 Chairman of the Board, ChiefErecutive Officer and President Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of Constellation Energy Group, Inc., the Registrant, and in the capacities and on the dates indicated.
Signature ride Date Principal executive officer and director:
By 1sf M. A. Shattuck III Chairman of the Board, Chief March 11, 2005 M. A. Shattuck III Executive Officer, President and Director Principal financial and accounting officer:
By /sl E. E Smith Executive Vice President. Chief March 11, 2005 E. F. Smith Financial Officer, and Chief Administrative Officer Directors:
/sI Y. C. de Balmann Director March 11, 2005 Y. C. de Balmann
/s/ D. L. Becker Director March 11, 2005 D. L Becker
/sI J. T. Brady Director March 11, 2005 J. T. Brady
/sf F. P. Bramble, Sr. Director March 11, 2005 F. P.Bramble, Sr.
/sI E. A. Crooke Director March 11, 2005 E. A. Crooke
/s) J. R Curtiss Director March 11, 2005 J. R. Curtiss 126
Signature itle Date
/s/ R. W. Gale Director March 11, 2005 R. W. Gale
/s- F. A. Hrabowski, III Director March 11, 2005 F. A. Hrabowski, III Is/ E. J. Kelly, IlIl Director March 11, 2005 L J. KlcHy, III
/si N. Lampton Director March 11, 2005 N. Lampton
/s- R. J. Lawless Director March 11, 2005 R. J. Lawless is/ L. M. Martin Director March 11, 2005 L M. Martin
/s/ M. D. Sullivan Director March 11, 2005 M. D. Sullivan 127
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 11, 2005 By Isl KENNETH W. DEFONTES, JR.
Kenneth W. DeFontes, Jr.
Presidentand ChiefExecutive Offcer Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of Baltimore Gas and Electric Company, the Registrant, and in the capacities and on the dates indicated.
Signature Tide Date Principal executive officer and director:
By /s/ K. W. DeFontes, Jr. President, Chief Executive March 11, 2005 K. W. DeFontes, Jr. Officer, and Director Principal financial and accounting officer and director:
By /s/ E. E Smith Senior Vice President, Chief March 11, 2005 E. F.Smith Financial Officer, and Director Directors:
Is! M. A. Shattuck III Director March 11, 2005 M. A. Shattuck III 128
Exhibit 31(a)
CONSTELLATION ENERGY GROUP, INC.
CERTIFICATION 1, Mayo A. Shattuck 111, certify that:
- 1. I have reviewed this report on Form 10-K of Constellation Energy Group, Inc.;
- 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
- 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
- 4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
- 5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's Board of Directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Dare: March 11, 2005 Isl MAYO A. SHATrUCK III Chairman of the Board, Chief Executive Officer, and President
Exhibit 31 lb)
CONSTELLATION ENERGY GROUP, INC.
CERTIFICATION
- 1. E. Follin Smith, certify that:
- 1. I have reviewed this report on Form 10-K of Constellation Energy Group, Inc.;
- 2. Based on my knowledge, this report does not contain any untrue statement of a material fca or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
- 3. Based on my knowledge, the financial statements, and other financial information induded in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
- 4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-1 5(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
- 5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's Board of Directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: March 11, 2005 Isl E. FOLLuN SMiTH Executive Vice President, Chief Financial Officer, and Chief Administrative Officer
Exhibit 31(c)
BALTIMORE GAS AND ELECTRIC COMPANY CERTIFICATION 1, Kenneth W. DeFontes, Jr., certify that:
- 1. I have reviewed this report on Form 10-K of Baltimore Gas and Electric Company;
- 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
- 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
- 4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
- 5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's Board of Directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: Mardh 11, 2005 1s1 KENNErH W. DEFONTES, JR.
President and Chief Executive Officer
Exhibit 31 (dl BALTIMORE GAS AND ELECTRIC COMPANY CERTIFICATION 1, E. Follin Smith, certify that:
- 1. I have reviewed this report on Form 10-K of Baltimore Gas and Elearic Company;
- 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
- 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
- 4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affea, the registrant's internal control over financial reporting; and
- 5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's Board of Directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: March 11, 2005 Asl E. FoIaN SMmIT Senior Vice President and Chief Financial Officer
Exhibit 32(a)
CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 1, Mayo A. Shattuck 111, Chairman of the Board, Chief Executive Officer and President of Constellation Energy Group, Inc., certify pursuant to 18 U.S.C. Section 1350 adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that to my knowledge:
(i) The accompanying Annual Report on Form 10-K for the year ended December 31, 2004 fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934, as amended; and (ii) The information contained in such report fairly presents, in all material respects, the financial condition and results of operations of Constellation Energy Group, Inc.
Is/ M.kYo A. SInATucKC IIl Mayo A. Shattuck IlI Chairman of the Board, Chief Executive Officer, and President Date: March 11, 2005
Exhibit 32(b)
CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 1, E. Follin Smith, Executive Vice President, Chief Financial Officer, and Chief Administrative Officer of Constellation Energy Group, Inc., certify pursuant to 18 U.S.C. Section 1350 adopted pursuant to Section 906 of the Sarbanes-Oxlqy Act of 2002 that to my knowledge:
(i) The accompanying Annual Report on Form 10-K for the year ended December 31, 2004 fully complies with dte requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934, as amended; and (ii) The information contained in such report fairly presents, in all material respects, the financial condition and results of operations of Constellation Energy Group, Inc.
Isl E. FOLLIN SMITH E. Follin Smith Executive Vice President, Chief Financial Officer, and Chief Administrative Officer Date: March 11, 2005
Exhibit 32(c)
CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 I, Kenneth W. DeFontes, Jr., President and Chief Executive Officer of Baltimore Gas and Electric Company, certif6 pursuant to 18 U.S.C. Section 1350 adopted pursuant to Section 906 of the Sarbanes-Oxtey Act of 2002 that to my knowledge:
(i) The accompanying Annual Report on Form 10-K for the year ended December 31, 2004 fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934, as amended; and (ii) The information contained in such report fairly presents, in all material respects, the financial condition and results of operations of Baltimore Gas and Electric Company.
/Is KENNETH W. DEFONTES, JR.
Kenneth W. DeFontes, Jr.
President and Chief Executive Officer Date: March 11, 2005
Exhibit 32(d)
CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 1, E. Follin Smith, Senior Vice President and Chief Financial Officer of Baltimore Gas and Electric Company, certify pursuant to 18 U.S.C. Section 1350 adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that to my knowledge:
(i) The accompanying Annual Report on Form 10-K for the year ended December 31, 2004 fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934, as amended; and (ii) The information contained in such report fairly presents, in all material respects, the financial condition and results of operations of Baltimore Gas and Electric Company.
Isl E. FOWN SMMi E. Follin Smith Senior Vice President and Chief Financial Officer Date: March 11, 2005