Text

1998 Annual Rept for Bg&E. with
	ML20207M228
Person / Time
Site:	Calvert Cliffs
Issue date:	12/31/1998
From:	Cruse C, Poindexter C; BALTIMORE GAS & ELECTRIC CO.
To:	; NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
	NUDOCS 9903190029
	Download: ML20207M228 (69)
	v • d • e

{{#Wiki_filter:! CIIARLES II. CRUSE Baltimore Gas and Electric Company Vice President Calvert Cliffs Nuclear Power Plant Nuclear Energ) 1650 Calvert Cliffs Parkway Lusby, Maryland 20657 410 495-4455 March 16,1999 U. S. Nuclear Regulatory Commission Washington, DC 20555 ATTENTION: Document Control Desk

SUBJECT:

Calvert Cliffs Nuclear Power Plant Unit Nos.1 & 2; Docket Nos. 50-317 & 50-318 Calvert Cliffs Independent Spent Fuel Storage Installation, Docket No. 72-8 1998 Annual Reoort la accordance with the requirements of 10 CFR 50.7)(L) and 10 CFR 72.80(b), erclosed please find at copy of the Baltimore Gas and Electric Company's 1998 Annual Report to its shareholders. / Should you have questions regarding this matter, we will be pleased to discuss them with you. Very truly yours, / CHC/JKK/ dim

Enclosure:

As stated cc: Resident Inspector, NRC (Without Enclosure) R. S. Fleishman, Esquire H. J. Miller, NRC J. E. Silberg, Esquire R.1. McLean, DNR Director, Project Directorate I-1, NRC J. H. Walter, PSC A. W. Dromerick, NRC - A9 9903190029 981231 PDR ADOCK 05000317 I PDR

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i FinancialI14..lg11 gilts' -1998 1997: : 4 % Change (in milliont. exeptperdweemouna)

COMMON STOCK DATA :
Earnings per shore

< Earnings per share from operations Utility business? ' $ ' 1.93 $ ' 1.94 . - (0.5)% - 1 0.27 - ' O.34 - (20.6)% : Diversified businesses 4 . Total earnings per share from operations - - $ 2.70 $ 2.28, . (3.5)% ; ~' ' Write-off of merger costs " (0.25)

--e

? Write-downs of real estate investmentsi

(0.10)

(0.31) E

Write off ofenergy services investment (0.04)

-1 s

Total earnings per share

. $ 2.06 ' $ 1.72 ,19.8% - 1 Dividends Coclored 'psr shore - $ 1,67 $ -1.63

2.5% -'

j Average shms ovessanding. 148.5 147.7 l0.5% i i - Retum on i,verage common equity Reported / 10.5 % 8.9% - 18.0% - L Exduding nonrecurring charges to e.arnings 11.2 % 11.7 % (4.3)% sook volve per' shore-year-end. $ 19.98 $ 19.44

2.8% -

Market price per shore-year-end $30.875 $34.125 (9.5)% - ' FINANCIAL DATA L l j Revenues: . 1.2 % ? , Electric . $ 2,219 $ 2,192 , Gas :. 449 522 (13.9)%. 1 Diversified businesses / 690 594 ' 16.1% ' ? Total revenues $ 3,358 < - $ 3,308

1.5% :

Not income -4 328- $j 283' < 15.8% Eamings opplicable to common stock ; $ 306= $ ' '254 -

20.4%L Assets '

Utility business $ 7,271 - $ 7,305 - (0.5)% 4 ~ Diversified businesses - 1,924 1,595 20.6%,

Total assets -

$ 9,195 $ 8,900 [ 3.3% '. 1 . Utility construction empendievres 1 329 $ =365.. (9.9)% ' i 1 (excluding Allowance for Funds Used During Cons 0ruction) $ . BGE investment in diversified businesses'-- $ 515 $ 488 - 5.5% - s UTIUTY SY ' DATA' i Electric system sales--megawatt hours 28.8 28.1 . 2.5 % i Gas system sales-dekatherms. 100.1 112.4' (10.9)% - I .j Q};h ' . %ecurring dwps a earning discuuedin Now2 m de ConwlidatedSnancialStatemena onpage 51. l y9 Certain priomar amonna har been rechtmfed to confmn with he currentyearipresensation. Md %@ I k $t

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-f ?Qf d Who We Are 2 letter to Shareholders' 4 Financial Review 17 Forward looking Statements 35. s $;$gf 9 [MQM d {i S$ Directors and Officers 66 Five-Year Statistical Summary 68 Shareholder Information 69 Mk Ouf Strasgies: Concentrating on Our Home-Field Advantage in Maryland ~ 8 7 9l Targeting Wholesale Power Marketing and Generation 12 : Focusing on Latin America 16 'y y Ty( i i 4 1 15d. p Q' g,.;.p+g m w,e u w y

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= Nobody just steps out on the court and wins. You have to have a p Rn. You have to make tough choices. You have to be COm mitteCAnd y ou have to work at it, and work at it, and Work ,j (; at it. @ That's what matters on the court and in the evolving energy marketplace. Today hundreds of experienced power compames are compenng for good position along with a host of niche players and newcomers. While it's early on in the 4 game, BGE's made some SmRrC plRfS with a growing wholesale power business, a s 8 l f E f. commitment to power generation, and a pro-customer choice stance at home. B In the end, BGE _1_ i plans to be a Winner. That's why we're doing everything we can to prepare. Building a strong team. Setting competitive SlrR[egkeS. And playing hard, very hard. G Bottom line 3 3 at BGE,We re uetermineC. CO Win. 1 Earnings and Dividends Return on Average Common Equitv Common Stock Market Price Declared per Share of Common Stock and Book Value per Share $ 2,8. - 12% - $15 $ 2... 38% sas 4 i 81.5. l
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$21 l .s Tl .l... .l. i.... ir U 1 i 1994 1995 1996 1997 199. 1994 1995 1996 1997 199. 1994 1995 1996 1997 199. aum (armngs per %are Market Price per bre usan Dividenh per %sre look Value per Wre y e se << 1 2
Dg A .A A u a Our. ti..Ity Business! Our Nonregdlat.ed Our regulated, inwstor-ownedelectrie andgas utilityscrws mm than U million . BGEs nonregulated businesses, consolidated ; ' industrial commercial andresidentialelectric customers andour573,000 gas underits whollyoumedsubsidiarg customersin CentralMarylan[ Constellstion* Enterprises, Inc., focus on i emerging opportunities in the competitinL, operationes..
Gas Distribution: Stores and delivers
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f a Generation:Ownsand operates. ' 10 Maryland-based power ' stations, natural gas through two peak-shaving. " induding theCalven Cliffs Nuclear plants, nine gate stations, and nearly _ Constellation Power Source" Inc, - Power Plant; shares ownership ofthree 5,600 square miles ofgas maim in a more Desselyties: power plantsin Pennsylvania; total gener- ' than 600-square-mile service territory Provides wholesale power-marketing and risk. ating capacity exceeds 6,200 megawatts management services, with Goldman Sachs - .ElectricTransmission and M8lugldigids: Power as its exdusive advisor Distribution: Provides electricity
S** "C" Production records in fossil and -
throughout its 2,300-square-mile service nudear plants by gerierating 32.4 million . Costomers and aterkets: -. territory through its transmission and . megawatt hours, an increase of14% : Wholesale energy customers in North America distribution system; is a member of the since1994 I8ll31dlI8'88 PJM (Pennsylvania-NewJersey-
Became first in the U.S.'to fde for nudear-9 5
. Maryland) Interconnection, a regional : plant reticensing to extend Calvert Cliffs e increased trading volume nearly 12-fold to . power poolofwholesale marker ~ Nudear Power Plant's operatinglicense 116 mill on megawatt hours corapared to : 9 *illi "
I997'
participants and eight utility companies
. Filed transition plan for introducing ' electric retail competition with the
Developed New England business base by Maryland Public Service entering into long-term contracts with Granite Commission (PSC)
State Electric Company, Fitchburg Gas and - = Gained $16 million natural gas base Electric Company, and Eastern Utilities ^**'I*'" rateincrease that included a provision to protect revenues from
Formed Orion Power Holdings, Inc. with weather fluctuations Goldman Sachs Capital Partners to pursue a Added nearly 12,000 newnaturalgas Purchasing existing power plants in North '
^ " * " '
customers and more than 15,600 electric customers to system a Orion acquired the 105-megawatt Carr Street

Ranked in *.he top 17th percentile Power plant in Syracuse, NY ofcomparable utilities for safety

Entered into five-year contract to purchase N' O /
. performance all capacity, energy, and ancillary services generated by Carr Sueer power plant a Moved into new downtown Baltimore head-quarters with a state-of-the-an trading floor
w w+ 4 g. w m p m m e,m w w,2 m may ~ o w msdp%g3 A wa n pp y mm e sqw ~ h. , h Mh 4 hh,p g x ._x - cgp,y a a1 _ u m a,N h h b h g +y (yQ,43 s,j n~,,x u a c a. n p :p,h _;h a bm~ ja 3 e n Bvl}fjf-xw* ytp 3 ? areGasa~nd:Elecm, gSL.p,yw w C o , 4 %j g J.Cn BG_. E g m;h L p %%%%4k%Mbe%p%yc(M);n.%gk m w dgy .L g q s we s w w np . - ~y w n x o n nivestor oMed envr r c c m an LMCMMSMNQDgg%g amgg Mh@% .N y & f u g, h$kf M%%% f@ g wh l g g~ wj I "N h ;. 4, ^,; j M 1 % hQ Eriergy Services Businesses
gk Constellation Power," Inc; BGE Home Products Constellation Energy q} M and Services,.Inc.
Source," Inc. h/[p y m, m, ' 51 ops, owns,'and operates domestic Descriptica:1
Deaription:
D and in'temational power projectsi provides Offers a wide range ofhome energy.. ~ exclusively to businesses 14 Provides customized energy solutions products and services; commercial build- ' operations and maintenance services to. . ing systems; and retail gas markering : @Mg . energy facilities through its wholly owned : . Costeams and Merkets: subsidiary, Constellation Operating
fWp Costeams and Merketss

L Mid-sized commercial and industrial y pM 4 Services,Inc.(COSI) ; . Residential and commercial customers in cus'omers primarily in the mid-3 W t C:stsaws and Markets:- thW e - Wholesale and retail energy m,arkets in the ' MD,VA, and Washington, D.C. Atlantic region - g8 U.S. and Latin America. - 1998 Nigidights: - 1998 Nighlights:. [h
Added naturalgas toits existing
= More than doubled naturalgas sales ~ qMN 1998 Nigidights:, portfolio ofproducts and services to : in oneyear
N #
Set production record ofover 4 million.
take ndvantage ofopportunities
Expanded productline to offer ik N megawatt hours, the most ever generated openingwith the deregulation ofthe full complement ofenergy and fQ byits domestic powerplantportfoho
retailnaturalgas supplymarket energy-related services to mid-sized fg$
Reorganized management team,7
. Concluded sales and marketing drive commercial, industrial, and Mph ' aligning operations to pursue wholesale L as a participantin Maryland's Gas governmental customers MQ
power-marketmg and merchant- -
' Options pilot program, attracting . Invested in new information systems %8 generation strategies - significant interest from residential and to support large transaction vohtmes 7D2 required to serve sophisticated hMQ
Acquired controllinginterest in' small-commercialmarkets Elektra Noreste, S.A., Panama's ;
. Won two
Baltimore's Best" Awards customers' complex energy needs MM
= second-largest electric distribution from Baltimore magazine for appliance $2i
company stores and plumbingservices k%h
CO3I gained contract to operate Carr
. Continued to strategically n eposition
BGEalso has other nonregulated NQ Street powerplantin Syracuse,NY retail operations, relocating two businesses that au not energy-ulated-gd

Signed long-term power-supply.,
existing stores and opening a third Constellation Investments,mInc. Qg agreement with privatized Guatemalan in a new market engagesinfnancialinvestments, j jf; *g distribution company;added 60 ; including markerable securities.fnan-megawat ts ofnew generating capacity ciallimitedpartnerships, andjnancial y guaranteesnss,ran ecompanses. j g
Constellation RealEstate Group,m inc.
W g develops, owns, andmanages realestate , ng andsenior-livingfacilities. GQ w a' ~* i y I ( Nhk m pk Mk hh k l 1 E o a --' M5hbh fhhhhh m m M h m} a s m A A [m M [M C u s i % a <" m - 7 adphdhw s
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O~R LETTER ~. t. L l [ l' Our 1 [ / - F gi Strategies l p I. \\, .s V
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i' Transition toa ; e V X" b . CompetitinEnergy ; l Marketytace b-4 BeaIsaderin l. yyj,,,7,jy,,,. [ ^ Marketingand Generationin NortsAmerica [- i)
Ben Signipcant Generationand.
Ene,xyvetirer,' ? Supplierin ' ; p LatinAmerica i: t: N s
g..
-e L Edward A. Crooke Christian H. Poindexter Vice Chairman Chairman of the Board, President and Chief Executive OfEcer ~- 1 L
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- p@ g ; yng% 3 p a a w 3 3 ge g p k. , %e gy a- ~ u% uw.ew ~, n u w w y. +: wu = n ~.= w ti.ity Business Our Nonregulated Our Our reguLited investor-ownedelectric andgas utility serves more than 1.1 million BGE's nonregulated businesses, consolidated industrial, commercial and residentialelectric customers and at er 573,000 gas underits u holly ownedsubsidiary, customasin CentralMarylami. Constellation
Enterprises, Inc., focus on emnging opportunities in the competitive Operctionst
"#E# ###4##E,"'
f a Generatiom Owns and operates . Gas Distributiom Stores and delivers 10 Maryland-based power stations, natural gas through two peak-shaving l including the Calvert Cliffs Nuclear plants, nine gate stations, and nearly C,onstellan.on Power Source,n, Inc. l Power Plant; shares ownership of three 5,600 square miles ofgas mains in a more Destriptiom l power plants in Pennsylvania; total gener-than 600-square-mile service territory Provides wholesale power-marketing and risk-l ating capacity exceeds 6,200 megawatts manage.nent services, with Goldman Sachs
Electric Transmission and 1998 Highlights:
Power as its exclusive advisor l Distributiom Provides electricity
Set new production records in fossil and throughout its 2,300-square-mile service nuclear plants by generating 32.4 million Customers and Marketst territory through its transmission and megawatt hours, an increase of 14%
Wholesale energy customers in North America distribution system;is a member of the since 1994 PJM (Pennsylvania-New Jersey-13ecame first in the U.S. to file for nuclear-1998 Highlights: Maryland) Interconnection, a regional plant relicensing to extend Calvert Cliffs
Increased trading volume nearly 12-fold to power pool ofwholesale market Nuclear Power Plant's operating license 116 milhon megawatt hours compared to 9*
participants and eight utility companies . Filed transition plan for introducing electric retail competition with the
Developed New England business base sy Maryland Public Service entering into long-term contracts with Granitt Commission (PSC)
State Electric Company, Fitchburg Gas and Electic Company, and Eastern Utilities
Gained $16 million natural gas base
^ " ' "' rate increase that included a l provision to protect revenues from
Formed Orion Power Holdings,Inc. with weather fluctuations Goldman Sachs Capital Partners to pursue

Added nearly 12,000 new natural gas purchasing existing power plants in North Amenca customers and more than 15,600 electric customers to system

Orion acquired the 105-megawatt Carr Street P **'P '"' " ' '"'# #

Ranked in the top 17th percentile T]'-
ofcomparable utilities for safety + Entered into five-year contract to purchase N performance all capacity, energy, and ancillary services ) . b w, generated by Carr Street power plant Moved into new downtown llaltimore head-quarters with a state-of-the-art trading floor
m .#.y x t 4 .R * . E. Ob ' ? g_ y% LBaltimore Gas' and:ElectricLCompany;(BGE)l is an investor-owned energy a company cornb.c.tning a core electnc and ga;s u.h.tt tywith diversified businesses.:In:1998,, - combinscGh/enbE tst, alm $3.4 $illiori.: h a p ~ T g ie t }. Energy Services 3usinesses* Q tm Constellation Power" Inc. BGE Home Products Constellation Energy M and Services," Inc. Source," Inc. !Ni
== Description:== LO Develops, owns, and operates domestic
== Description:== == Description:== FJ and international power projects; provides Offers a wide range of home energy Provides customized energy solutions [R operations and maintenance services to Products and services; commercial build-exclusively to businesses c1 energy facilities through its wholly owned ing systems; and retail gas marketing 9M.. hy, <ubsidiny, Constellation Operating Customers med Merkets: Services,Inc. (COSI) Customers and Markets: Mid-sized commercial and industrial
. 4 L
Residential and commercial customers in customers primarily in the mid-b'- Castem:rs and Merkets: MD, VA, and Washington, D.C. Atlantic region Wholesale and retail energy markets in the { U.S. and Latin America 1998 Highlights: 1998 Highlights: n
Added naturalgas toits existing

More than doubled naturalgas sales k
1998 Highlights: portfolio ofproducts and services to in one year b
Set production record ofover 4 million take advantage ofopportunities
. Expanded product line to offer h megawatt hours, the most ever generated openingwith the deregulation of the full complement ofenergy and b byits domesucpower plant portfobo retail naturalgas supply market energy-related services to mid-sized [
Reorganized management team,
. Concluded ; ales and marketing drive commercial, industrial, and aligning operations to pursue wholesale as a partic: pant in Maryland's Gas governmental customers h( power-marketing and merchant-Options p lor program, attracting . Invested in new information systems generanon strategies significant interest from residential and to support large transaction volumes li i
Acquired controlling interest in small-commercial markets required to serve sophisticated b
Elektra Noreste, S.A., Panama's . Won two
Baltimore's Best" Awards customers' complex energy needs E
second-largest electric distribution from Baltimon magazine for appliance h co.npany stores and plumbing services [ 4
COSI gained contract to operate Carr
. Continued to strategically reposition
BGEalso has other nonregulated Street power plant in Syracuse, NY retail operations, relocating two businesses that are not energy-related:

Signed long-term power-supply existing stores and opening a third

Constellation lurl<stments,'Inc.
agreement with privatized Guatemalan in a new market engagesinfnancea/ investments, distribution company; added 60 including marketable securities,fnan-megawatts ofnew generating capacity ciallimitedpartnerships, andfnancial guaranteeinsurance companies.
Constellarion Real15 tate Group,~ Inc.
l develops, owns, and manages realestate andsenior-livingfacilities. R g 7.. y yyg., m. .mc-. r s,- I
~ 3 r f. g ..f m_, q LETTER V I 7.. Lp i L o .i, - Strategies Our i b l i. j ij [- t L . Continue to Ofer y y 1%mier Utility; - ^ 4 '4 ~ ~ s Servicesto l . ' Maryland %ile ' .i } f ~ . Managingthe. Tramition to a l e
d
[. 9l~ 4 CompetitiveEne gy t t Marketplace : N ^ Y ! '* Bea Leaderin W%lesaleibuer Marketingand - Generationin ' NorthAmerica - ll ~ *Bea Signspcant 'f' \\i\\ Generationand 1:
EnergyDelivery

Supplierin. \\i LatinAmerica [:. v - h, . -l: o. ? I e r Edward A. Crooke Christian H. Poindexter I Vice Chairman ' . Chairman of the Board, President i and Chief Executive Oflicer t. p. t'. 1 E.L
le d oday, and for the foreseeable futu're, tiie'best description for our business is "an industry in transition." Transition means change, and change is filled with uncertainty.The events of 1998 bear this out. We're determined to win in the new energy market. As we go through this transition, we'll work to preserve the integrity ofyour investment, shed assets that no longer fit the emerging market, and seize opportunities for growth, SH REHOLDERS In this transition year, BGE's stock performed below our A Look at the Scorecard standards and my own expectations. To be candid, our In 1998, BGE earned $305.9 million, or $2.06 per stock performed in the lowest quartile among utilities in common share, on revenues of $3.4 billion.This compares our peer group. I attribute this to the following: with earnings in 1997 of $254.1 million, or earnings per
Flat earnings due to less energy demand caused by mild share of $1.72 on revenues of $3.3 billion.
weather in the fall and winter, and write-downs on Both 1998 and 1997 earnings reflect one-time cnarges, projects resulting from our decision to sell a real estate explained in the financial section of this report. Excluding investment and exit an energy services venture. the effect of the nonrecurring charges, earnings for 1998 e + Anticipated lower future revenues from 15 California "'ere $2.20 per share cornpared with $2.28 for 1997, power projects with power purchase agreemens. Dividends declared amounted to $1.67 per common share 5 Owned by our Constellation Power a5iliate, these in 1998 and $1.63 per common share in 1997. projects will have transitioned from fned to variable rates by the end of the year 2000. Our Utility Business Our utility business includes our = regulated electric and gas sales, production, and delivery
A rate reduction proposed by the hiaryland OS ;e services. Earnings from these businesses in 1998 were about of People's Counsel to the hiaryland Public Service the same as in 1997. Although we had higher electric sales, Commission (PSC) that could reduce BGE's we also had lower gas sales, along with higher operations, earnings potential.
maintenance, and depreciation expenses.
The regulatory and legislative process under way in During the year we added about 15,600 electric and 1
hiaryland to move to a competitive electric market. 12,000 gas customers. Total electric sales to customers ) Investors are uncertain about how key issues such as increased approximately 2.4%, mostly due to customer transition cost recovery and fair tax treatment for growth, increased demand during the hot summer, and utilities will be resolved. increased usage per customer. Electric sales to residential I assure you that your leadership team is acutely aware customers were up almost 1.5%, w hile sales to commercial of how these issues afTect the value ofyour stock. We are and industrial customers increased 2.9%. working hard on many fronts to resolve them and are Total gas sales to customers decreased 10.9% compared encouraged by our progress, with 1997, due to 1998's mild winter and fall weather and I am especially happy to report that legislation was lower usage per customer. Sales to residential customers passed and signed into hiaryland law early in 1999, decreased 11.6%, while sales to commercial and industrial removing a 1910 hiaryland statu.e that prevented BGE customers decreased 10.5%. from forming a holding company. You'll find more detail BCEpouvrplantshadanotherrecord-setringyrar. In on page 6, but I want you to know I was overwhelmed by 1998, our Calvert Cliffs Nuclear Power Plant (CCNPP) the strong show ofsupport from k> cal investors and our generated 13.3 million megawatt hours ofenergy, its employees, as well as commu nity and business leaders, on highest production level since it began operation 22 years the holding company issue. I thank each ofyou for your ago. Our fossil plants also set a new production record of help. It truly made a ditTerence. 19.1 million megawatt hours. j i
For the fourth year in a row, our BG E generation team ' ' ~ /Mding Company BillPasses After the close of the 1998 also distinguished itself as the lowest-cost electricity provider legislative session last April, we worked to achieve an among the eight utilities that are included in the PJM understanding with hf aryland's governor and legislative (Pennsylvania-New Jcrsey-Maryland) power pool. leaders on the importance of a holding company to BG E's In April 1998, BGE also became the first utility in the future. A 90-year-old law made our state the only one in the country to file with the Nuclear Regulatory Commission to nation prohibiting a utility fmm forming a holding company. extend the operating licenses ofCCNPP's two nuclear units. By June, we received commitments from Maryland's Since then, several other utilities have filed or plan to file for governor, senate president, and speaker of the house that this outdated law would be extensions in the near future.This changed early in the '99 session. process will help ensure a diverse l 7 q h' 1' V A4. ~ ~ - jQw
I am pleased to report that state l
fuel mix for our nation's energy A. ~ g " L A v 1.L - ! lawmakers voted overwhelmingly consumers, allowing our country ( and our state to meet stringent j to allow utilities incorporated in new domestic and international ! Maryland to form holding compa-f nies.The bill was signed into law air quality standards. L1 We are on target to be Year j g. j on Februa y 3,1999, j 2000(Y2K) ready. Our utility ? i. A,a4 { This puts BGE on equal footing j with other gas and electric utilities operations are on schedule to be se c completely Y2K-ready by mid [ i, Y
serving Manland customers but a
a 1999. We've made a significant h u
inc rp rated ut fstate.This also 8
I ~ investment and have been f gives us greater access to the c working with the PSC and other [
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markets and the financial flexibility l utilities to ensure system relia- ) ' g";ggfig3gt to build our businesses. g bility. Simply put, our customers - mis e,,a as n,a,,, The final steps will be receiving ~ j can expect the same high level of [ 4 approvals from the Nuclear service reliability during ar,.! after i To mutpoing/emand BCEpe=N.iV j Regulatory Commission and J, the millennium rollover as they i million m,g wstlan ofelnerrispin ise. Thi, ; , from shareholders at our annual experienced before it. y is 43.5% imemue owr ee md swserin1M7. : } meeting in April. e t S L L.ww.- mae,-.4 um n .4 Our Nonregulited flusinesses Moring Ibward Comprehensive Earnings from our nonregulated affiliates reflect solid I.egislationfor Electric Dengulation In December 1997, performance. Excluding the write-downs taken in 1998 and the PSC set July 1,2000 as the date when Maryland 1997, our nonregulated business operations produced $41.1 customers would begin to choose their electric suppliers. million in earnings ($.27 per share) in 1998 compared with State lawmakers then debated the issues surrounding dereg- $50.5 million ($.34 per share)in 1997. ulation in the '98 session. While no bill was introduced, the Write-downs for 1998 included investments in Church debates raised awareness of the complex and important Street Station-an entertainment complex in Florida-and issues needing resolution before deregulation begins. ( an energy services venture.The net result: Nonregulated Since that session, BG E and the other utilities serving earnings were $20.2 million in 1998 compared with Maryland have continued to work on proposed legislation. $4.5 million in 1997. Tbgether, the six utilities developed a series ofbills for consid-The major contributors to nonregulated earnings in eration by the Maryland General Assembly leadership. 1998 were Constellation Power, Inc. (CPI), our largest We have set out to achieve a broad consensus on the main j operating subsidiary, and Constellation Power Source, Inc. elements, taking into consideration the views of all stake-(CPS), our newest operating subsidiary. CPI contributed holders-customers, regulators, legislators, community $44.3 million ($.30 per share) to earnings compared with leaders, and shareholders. Our objective is to find the fairest $36.6 million ($.25 per share) in 1997. CPS weighed in and fastest way to open the state's energy market and resolve with a $7.5 million ($.05 per share) contribution in its first the uncertainties the transition has created. full operating year. All along, we've sensed a commitment to doing it right the first time to ensure an efficient and equitable market that A Brighter Outlook Ahead benefits customers and producers alike. We are continuing We have been working hard to resolve several issues that held to work with Maryland's electric industry leaders and state i us back in 1998 and to position your company to win in the lawmakers to pass comprehensive legislation in 1999. l competitive energy market. Here are some ofour successes:
e-Focusing A]pliate Businesses on Energy We have rearganized 'Become a Sigrupcant Generation and Energy Delivery and streamlined our subsidiary structure and focused Supplierin Latin America Constellation Power, our our activities on the business we know best-energy. independent power business, began expanding its expertise For our nonenergy-related businesses we are evaluating in generation.ad energy delivery beyond our borders three transitional strategies. years ago. It now has 15 projects in eight Latin American 'Ibward that end, our Constellation Real Estate Group countries. We intend to build on our winning track record (CREG) transferred most ofits operating properties to and increase our involvement in the government privatiza-Corporate Office PropertiesTrust (COIrr), a publicly traded tion process now under way in this geographic region. real estate investment trust based in Philadelphia. In exchange, CREG I ~ " ~ ~ [~~ ] Taking Our Best Sliots received a significant stock owner-l Ve' n' ': erat Oni i has two,eies that sem ug his ~ Ice hockeygreat Wayne Gretzky ship position in COPT, cash, and i relief from associated property debt, f 1 approach to the game. First,"I SiratSgIGs ( "j skate to where the puck is going to g be." Second,I says, "You miss for the Transition j
100 percent orche shots you never Our pre-eminent goal for the next j
j take."That is exactly how BGE { approaches the utility business. few years is to actively manage the l, se a a 9 m m. transition to a competitive electric j "- ) Being determined to win in 4e market. At the annual shareholders
the new energy world means se 4
++ taking the long view but focusing j meetingin April 1998,I announced j si "~ H the strategies for success going [ quickly. It means having the ~ ' *
forward. Since then, we've narrowed {
}4 hy"Qg " confidence to seize upon our focus and set our siglus on three l iumens ! Las ses e a well-considered risks. Most primary strategies.We go into more 1 ] importantly,it means playing the detail on pages 8-16, but here is a i Siact1954 BCE/wrlandingenemtionnuahy : z game on many levels by thinking briefoverview ofour game plan: ! lM *M"'aunhwr, BCEgrewy - ! locally, regionally, nationally, and 7 [ toon uur klosest-tutdameioyprowderm de : J j globally-because the energy g fjy,,,p y Ivoride Premier Utility Services L,j market af the next century is that _y to Maryland While hfanaging the broad and expansive. Transition to Competitive Energy Markets We've been In 1999, we'll continue to move quickly in response to serving Maryland customers for nearly two centuries, promising and profitable opportunities. We're building on a and we want to continue to have a strong corporate 182-year record of achievement, and we know what it takes presence here.Throughout most of this decade we've been to win. I look forward to telling you ofour progress this time preparing our operations for competition. We've improved next year. I reliability and service, lowered costs, and increased our I want to thank our employees for their tireless commit-j power plant production. As the retail energy markets open ment to assuring reliable and responsive services to our j in Maryland, we plan to remain the state's leader in energy customers.Their daily actions are representative of the kind delivtry services. of teamwork and dedication that will make BGE a winner in I the energy industry of the future. Finally, I thank you for Be a Leader in W%lesale Pouer Marketing and Generation sharing my confidence in BGE's (mancial success. In North America in less than two years, Constellation Power Source, our power marketing and trading business, has become one of the top 25 power marketers in the U.S. To build on this success, :ve realigned subsidiary operations to support ov.ierchant-generation and power-g marketing strategy. We have assembled the full spectrum of skills and services that will allow us to be a major player 674 SA in North America's emerging merchant electric industry. Within our family of nonregulated companies, we have Christian H. Poindexter the know-how to build, buy and operate power plants, Chairman of the Board, President trade the output on the open market, and manage the risk and Chief Executive Officer of fluctuating energy prices. February 11,1999 1
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e~ s L J he home team always has an advantage.That's ~ BGE Steps Q to the Plate to Preparefor Cwtomer l because they know the field, they know the fans, Choice With choice, virtually every customer transac-1 they know how to win on their own turf. tion we now do is subject to change. hiaking sure our BGE has had that edge for more than 180 years as systems are ready and our customers are educated for the Central hiaryland's hometown utility. As the biggest local changes ahead is a monumental task. Given the impact player, we've continually worked and evolved to help meet these changes have, it is a job that cannot be done in hiaryland's growing energy needs, giving customers and a vacuum. shareholders their money's worth every season. BGE has stepped up to the plate.We are a significant Now, ofcourse, the rules are all changing. It won't be long player in the process, participating in the numerous i before we're not the only game in town. hia ryland PSC roundtables and technical groups. We are l At BG E, we don't intend to now working through lose our hometown edge. the many regulatory We've developed some strate-j details necessary to draw a gies to help us keep th:t edge. [ blueprint for how customer We plan to: choice will work. + hiaintain our premier energy To meet the PSC's year-i = delivery service levels for our 2000 deadline, we're now j hiarvland customers; upgrading our infermation { Build on the reliable and systems necessary to support SAME PLAW customer choice. We're low-cost generation legacy OUCCUlfdlC-ier j s creating a new retail suppl. while helping to manage a
Focus on continuing as on Our Home-information system, and
j. bloodsin eng9Y Field Advanta e 9
smooth transition to - deliveryin (entrol we re extending the ability of customer cho. ice; Maryland. in Ma7 and l our customer information = = Remain a leader in the
Build on our poven system. Together they w.ll i
competitive retail energy ,g ) allow BGE to enroll $fRATE8Y: markets opening in jovgost e,9f mers and suppliers in Ondnuez g cust the region. poducwos 1 retail electric choice, keep ) Marylandtransmons pronier utility Our Premier Energy 2(ustmerdioice. . track of cummer/supph.er "'*"" N#7d"d-relationships, bill and collect I Delivery Service .levaage our expsionce while manap.ng revenues, as well as account Deregulan.on in the un.h.ty ond reputaten.e industry means that MayledWenuing & tratuidon to b aH energy used on our b ga ounemi .a competitive delivery system. customers will be able to enwgypodwtsand i choose where they buy their g,3 % marketplace. l energy. No matter which hwesting to improve Aaess andReliabilit-Before and company they buy from, customers will still depend after deregulation, we plan upon the utility to deliver that energy safely and reliably to to continue serving Central hiaryland as a recognized their homes and businesses.That's why we're concentrating leader in energy delivery. Toward that end, we continue to on our energy delivery systems in Central hiaryland. invest in our system of pipes and wires. l
This year ihe PSC approved a $ 16 milhon natural gas distribution rate increase to help us maintain our gas system. We continue to enlarge our gas distribution system to give even more customers the opportunity to choose gas for their homes and businesses. In 1998, we added 112 miles ofgas lines and ( about 12,000 new customers. .. v J BG E is technologically transforming our electric distribution substations to improve reliability and reduce costs. Our system control integration program has replaced older components with compact micro-processor-based relays, meters, and other control systems. The program is expected a to rcJuce costs in new substation l l construction and ongoing maintenance. l We've also continued to expand j the use ef% 0 en cin' "stribu-tion automat.. ated .j systcm designea to a.aers' interrupted power in mmates. Since 1994, 10 investments in such programs and other CONCENTRATE Ih'Ov4 ON OUR system. wide upgrades have helped reduce LOW-COST - the number of unplanned outages by.38% LEGACYIN POWER' and the duran.on of those outages by 20%. GENERATION Delitrring on Customer Satisfaction EH bas iewered Customer satisfaction is something IlG E has regularly Y2K conversion.The good news delivered to hiaryland. BGE's " excellent job" ratings with is many of our utility systems are i.., pg, y ,s. l residential customers rank us in the top quartile among Y2 K-ready. Where needed, the investor-owned utilities in the country. In recent years, team has begun repairing and we've concentrated on improving reliability and power testing. We are on target for our l I quality for our major customers.Just three years ago, our systems to be Y2K-ready by June 1999. large indust rial customer satisfaction score was good, but We've also been chetking on the Y2K-readiness stams of not good enough. So BG E account executives went to all ofour suppliers. Plus, we're working with industry work. Our results this year prove our efforts make a differ-groups such as the North American Electric Reliability ence. We improved by 17 percentage points. Council, Edison Electric Institute, Electric Power Research Institute, American Gas Association, and our We're Preparingfor the Icar 2000 and Beyond BG E partners in the PJhi power pool, to plan operations to began ratkling the Year 2000 (Y2K) challenge in 1996. allow for a smooth transition to the new century. Since then, experts throughout the company have been working to ensure our systems are ready for a smooth
Generating Winning Nurnbers Our Retail Energy Products i Maryland customers will soon have a choice in their and Services Role CONCENTRATE energy suppliers, which will change how our power BGE first opened its electric and ON EMERGING plants do business. In the meantime, we're working to gas appliance stores in the 1920s. COMPETITIVE ENERGY-REUJED provide a smooth transition so that w hen competition Several years ago, we transferred RETAIL MARKETS IN comes, our customers, shareholders, and our power plants this business to our BGE Home MARYLAND will be in a position to win. Pnxlucts & Services (BGE To compete in the new electric generation market, our HOM E) affiliate.'Ibday, BGE ~ power plants must be able to produce winning numbers-HOME has expanded its Neo of eeery prededs bw costs, high capacity factors, strong safety and environ-product lines to include not only and senhos, mental records, and consistendy reliable operations. all major brands of appliances, For the past meral years, BGE's power plants have but c!ectronic and entertainment been putting up i;ht numbers. In 1998, our combined products, plumbing and home improvement services, as fossil and nuclear energy generators posted the lowest well as heating and air conditioning systems. costs ar.mng the PJM power pool utilities for the (burth In fact,in 1998 BGE HOME was voted Ildtimou consecutive year. BG E plants have also increased their magazine's "Best of Baltimore" as the city's foremost appli-production levels every year in this decadc. ance and plumbing service source. j For the (burth year in a row, our nuclear facility was well within the top 10% for individual safety in the industry. rinner in the Gu Pilot gy,my7_q K Program A new role for Plus, the fbssil generation group again topped its own all-time low record Ihr OS H A recordable accidents, which also BGE HOME is as a l should place it in the top 10% ofits comparison companies. marketer and seller of 11 We've maintained a solid reliability record, too. Our natural gas. This predictive maintenance practices helped us achieve the summer BGE HOME lowest fbrced outage rate in thc PJM for the fourth consec-entered Maryland's utive year.That means our plants keep producing when a s residential Gas Options most profitable to do so. pilot program. A ) competitive success, BGE HOM E attracted the most BGE' Commitment to the Environment Remains Strong customers of any participant. s Since the Clean Air Act in 1970, BG E has invested hundreds of millions of dollars in cleaner air, and we A New Play with Constdlation Enery Source While continue to make significant reductions to our emissions. BGE HOME serves residential and small-commercial I I We are meeting or doing better than regulations require customers in Maryland, Constellation Energy Source is on our sulfur dioxide emissions by burning low-sulfur coal, concentrating on mid-sized industrial and commercial generating nearly halfour electricity using emissions-free customers. This year we have repositioned this business to nuclear fuel and hydroelectric power, retiring several older provide a wide range ofenergy products and senices to plants, and installing emissions-reducing equipment. meet the canplex energy needs of sophisticated customers ~Io comply with the 1990 Clean Air Act Amendments in the mid-Atlantic region. and reduce our nitrogen oxide emissions, we expect to spend about $126 million by 2003. We plan to continue 7he Gnne Goes On Maryland's energy picture is changing. to install new technology at our plants to further reduce Going forward, we intend to continue to be a corporate emissions to comply with new regulations. leader in Maryland. BGE is managing the game at hand and putting the plays in place to maintain our winning edge. a
l 1 T -~ aving the home-court ad eantage is one thing, but BGE's trading arm made money in 1998, a rare feat for ~ to succeed in the new wholesale power market, any newcomer, especially in a highly competitive business you've got to know how to go coast-to-coast. like this one. Competition might be opening slowly in the retail As evidenced by the volatile wholesale price swings this energy markets, but the wholesale power market opened summer that had electricity selling for as high as $7,000 in 1992. It's been on the fast track ever since. Emerging per megawatt hour, the market will continue to change. businesses such as power marketing and merchant genera-But it will reward those companies that best understand the tion have achieved tremendous growth and have shown no dynamics that are at work. We believe Constellation Power signs ofletting up. Source has what it takes to succeed. The held of competitors, of course, has become Gaining the hdmologica/6/gr From the new trading crowded quickly.Two years ago, BG E entered the race, too, Goor overlooking Baltimore's Inner Harbor, Constellation but we didn't come in to sit back in the pack. We came in Power Source's nearly 100 employees have a real knowing that to succeed, we'd need skill, instinct and agility. We'd also need the nerve to j take risks and the judgment to h E know when not to take them. ind most importantly, we j knew we'd need the power Wholesale Power Marketing l when the market wanted it. and Generation j In the past two years weie made some pretty good moves. i2 SAME PLAN: STRATEGY: On the wholesale s.de, we.ve i aligned our team and
Market and trade power in the national wholesale oreno.
8' d l'ader in wholesalepower marketing andgeneration in North America. positioned ourselves to go 4 Assemble o simnportfolio'd genemting assets, nationwide. And with the W dMk passage of the holding company billin Maryland, we will have the ability to Gnance this strategy. competitive advantage as they trade energy in North 1 America. That's because they have access to Grst-rate Constellation Power Source in the Running technology with appropriate risk-management in a strategic move to realize the benents ofderegulation, infrastructure in place. BGE added Constellation Power Source to its roster of Constellation Power Source has customi7ed for subsidiaries ;n 1997. With Goldman Sachs Power as its energy the same trading and risk-management system exclusive advisor, Constellation Power Source provides that Goldman Sachs uses to manage its worldwide power-marketing and risk-management services to whole-commodities business. The result is an unparalleled sale energy customers throughout North America. information resource that supplies real-time details on Pairing BGE's electric industry expertise with Goldman trade positions and associated risks. 1 Sachs' trading and risk-management expertise has its i advantages. In less than two years, the business went from a Orion Power Deals standing start to one of the top 25 power marketers in the Building on its power play, Constellation Power Source country. In 1998, trading volume increased nearly 12-fold and an afGliate of Goldman, Sachs & Co. formed Orion to 116 million megawatt hours versus 9 million in 1997. Power Holdings, Inc. this year to pursue buying existing
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]cCN ][p power plants in the United States and Canada. In 1998, ' ~'#""%n y, % gOlk., e,
Q Orion acquired the 105-megawatt Carr Street electric generating plant in upstate New York. It aho announced
-u the planned acquisition of New York State utihty D% N b b )fDy% Niagara Mohawk's 72 hydro generating facilities totaling 661 megawatts ofcapacity.
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c t d 'De u b- ] l I l 3,. -o l ~ PLANT PURCHASES TARGET POWER n Orles Powerlleidings a was formied tiils year 4e to perdiese, ewer u ,ieses is iht = leertti Asserlse. 4 - 7pWM@PF
w?
.a Our Orion investments provide M- -;s benefits on several fronts. First, c Orion's power plants will be operated E by our Constellation Operating Services-a move that j increases our power plant operating services business. And, (A g' ' 4 - Constellation Power Source has the exclusive right to market g-the output from Orion plants. - D..( 4 For example, Constellation Power Source entered into -A: 3;;/s 2 a five-year contract to purchase all of the capacity, energv, ,[ p[ p j and ancillary services generated by Orion's Carr Street -77 "gg ~ y y. A Generating Station I P Constellation Operating Services 4. iG will manage that plant. Growing Business Base Constellarion Power Source made its move this year to establish a base in New England, one of the first regions to go through the deregulation process. In 1998, Constellation Power Source entered into long-term contracts with Granite State Electric Company, Fitchburg Gas and Electric Company, and Eastern Utilities Associates.These contracts mean Constellation Power Source will provide wholesale electricity to these local utilities' customers who have not yet chosen a new electric supplier.
4 Q'M TARGET Constellation Power " k 7-MERCHANT PLANT Spearheads Merchant 7' CONSTRUCTION Plant Construction ~., wQ., While Orion concentrates on C has inere then buying existing power plants to bac k w 12 years eWla our trading business, Constellation d"*3*P *5 l ..s Power,s focus is now turning to $dj p pleets. develop, build and operate merchant qu power plants in strategic regions. The process to build a plant is a p long one--usually two years for permitting and two years fi>r construction. Ilut the fmal product is a large, highly ~h efEcient generation facility whose full capacity can be sold on the wholesale market. ~.. _ - J e, u~ ^ Seven Merchant Plant Site Approvals Under %y e y Constellation Power has more than 12 years of experience developing independent power plants. Its understanding l of the many project factors that need to be considered e is invaluable. 2 As of this writing, Constellation Power is pursuing l site approvals fi>r several domestic merchant plant ~ ~ l5
ggN development projects.They include two sites in Califi>rnia 5
^ suitable fiar 750 megawatts ofelectricity; two sites in Texas g;p D suitable fi>r 1.600 megawatts: two sites in Florida suitable liir 1,550 megawatts; and one in Massachusetts suitable for w. F -- 4 700 megawatts. What makes these sites so attractive is that they will be N developed to provide power during the times of highest E l( "y s demand. They are also strategically located relative to N A maior transmission systems, cooling water, and natural ,e 7 %j-gas supply. ,%g v Building on Our Strengths llerween our Constellation Power Source, Constellation TARGET ENERGY - ower, n onsa ation perating Services businesses, TRADING AND RISK
MANAGEMENT we have assembled a contender in the merchant generation and power-marketing business. We have the know-how to I"
g' build, buy and operate power plants, trade the output on seeree b e greers the open market, and manage the risk of fluctuating W ene of the W energy prices.
25 power omrhetersis the & .I he result? A new fiiture fi>r our company, our employees, and our shareholders-a future we're aggressively building on all fronts. 3 l
.j FOCUS ON CONTINUING TO ' GROW OUR LATIN AMERICAN POWER BUSINESS
SurPenems esquhallion serses us,see somers,j atin American utilities, once the domain of Generatingin Guatemala Similarly, Constellation Power governments, are being privatized in an effort to has plans to expand the generating capacity we purchased e
more efficiently serve the regions' growing in Guatemala. Again, the goal is to fulfill our supply demand for electricity.The governments have turned to agreements and have merchant power available to sell in foreign investors with energy experience, an invitation that the area as demand accelerates. We have already added has allowed us to expand our expertise beyond U.S. borders. 60 megawatts of new generation here and did so in record Currendy, through our Constellation Power affiliate, we time. We closed on the Guatemala acquisition in January have interests in 15 projects in eight latin American 1998 and by August-just seven months later-we had countries including Argentina, new capacity online. Bolivia, Brazil, Costa Rica, El 3 Salvador, Guatemala, Panama, i - Good Timing We arrived and Peru. l on the scene at a fortuitous ome, and our success so far i Elektra Noreste-/>anama has been gratifying. Over the Most recently, we acquired the ( ,,,g ,'we have bid controlling interest in Elektra on six major privatizations + Noreste, S.A., which serves the and won four of them.The eastern halfof Panama. It's our b compennon has been su.fL-biggest acquisition ever and the ften nv tving much larger GAME PLAN ' first time we have taken control. O mcernanonal corporations. . kquiregeneration G of a distribution company.The N.onetheless, we.meend to r second-largest electric distribu. and distribution assets. on Latin America build on our winning track tion company in Panama,
leverage our record and increase our Elektra Noreste serves 170,000 expetetxeand STRATEGY:.
involvement m the customers. We plan to improve r. exportisa,- privatization process c performance and service to { Be d Jignifcant. m the fu:ure. ~ [OrinSolid e these cussomers and grow th,s [ generation andenergy: t distribution company. .deln.ery supplierin I Latin America.
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3 1 o-o [d he home team always has an advantage.That's ^ BGE Steps Up to the Plate to PrepareJbr Customer because they know the field, they know the fans, Choice With choice, virtually every customer transac-j they know how to win on their own turf. tion we now do is subject to change. hiaking sure our BGE has had that edge for more than 180 years as systems are ready and our customers are educated for the Central hiaryland's hometown utility. As the biggest local changes ahead is a monumental task. Given the impact player, we've continually worked and evolved to help meet these changes have, it is a job that cannot be done in htaryland's growing energy needs, giving customers and a vacuum. shareholders their money's worth every season. BGE has stepped up to the plate. We are a significant Now, ofcourse, the rules are all changing. h won't be long player in the process, participating in the numerous before we're not the only game in town. hiaryland PSC roundtables and technical groups. We are At BGE, we don't intend to 7.ym , m.y yygg now working through lose our hometown edge. p f the many regularory s We've developed some strate-I' ~ details necessary to draw a gies to help us keep that edge. I . blueprint for how customer ^ We pl.tn to: {p choice will work. j To meet the PSC's year- (( ]j Maintain our premier energy j 2000 deadline, we're now j deliveryservicelevels for our Maryland customers: ] upgradingourinformation j
Build on the reliable and I
'Y#"" " *'* ** * 'Y ' '" P P '* m I SAGE PLAN:. S customer choice. We're e C' OncentdltCL d er low-cost generation legacy P while helping to manage a
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J. eating a new retail supph. a cr ( e l information system, and smooth transmon to g g g "*. Field Advantage? 1 i 9 j we re extending the abih.ty of deln'retyin(enitol s. . : Mar. lan, d c customer cho. ice; L in y 1 . our customer information P= =
Remain a leader in the
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~ competitive retail energy ,g allow BCE to enroll STRATESY:L markets opening in M#f 889V gj customers and suppliers in the region. L-
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Mayland tionsnons ptrmier unis.ty; 'IS"P.* Our Premier Energy b to cusemerdeice.1 ,,yj,,, gg,gf,g Delivery Service .Imange w aponence wh'ile managing ; .j revenues, as well as account r Deregulan.on in the utih.ty ond repukhnin. 3 customers will be able to [ .MeyledSantwing 't h d*Ition A g f r aH energy used on our industry means that e hga unahl a competitive! N d'IIVY SYS** F engy poductssul' l choose where they buy the. y, t marketplace. ir Im esting to improve Access ~' energy. No matter which [ y company they buy from, [ ay andReliability Beforeand
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customers will still depend after deregulation, we plan upon the utility to deliver that energy safely and reliably to to continue serving Central hiaryland as a recognized their homes and businesses.That's why we're concentrating leader in energy delivery.Toward that end, we continue to on our energy delivery systems in Central Maryland. invest in our system of pipes and wires.
'lhis year the PSC approved a $ 16 milhon natural gas distribution rate increase to help us maintain our gas system. We continue to enlarge our gas distribution system to give even more customers the opportunity to choose gas for their homes and businesses. In 1998, we added 112 miles ofgas lines and about 12,000 new customers. ElG E is technologically transforming our electric distribution substations to improve reliability and reduce co<rs. Our system control integration program has replaced older components with compact micro-processor-based relays, meters, and other control systems. The program is expected to reduce costs in new substation a [ construction and ongoing maintenance. l We've also continued to expand I the use ofour industry-recognized distribu-tion automation system, a sophisticated j system designed to restore customers' interrupted power in minutes. Since 1994, 10 investments in such programs and other ' CONCENTRATE i '\\ /
ON OUR -
system-wide upgrades have helped reduce y the number of unplanned outages by 38% LOW. COST ' LEGACYIN POWER ! and the duration of those outages by 20%. - GENERATION, Delivering on Customer Satisfaction net bes lowered Customer satisfaction is something 11G E has regularly Y2K conversion.The good news delivered to Maryland. IlG E's " excellent job" ratings with is many ofour utility systems are .i,gg,e years,- residential customers rank us in the top quartile among Y2K-ready. Where needed, the investor-owned utilities in the country. In recent years, team has hegun repairing and we've concentrated on improving reliability and power testing. We are on target for our quality for our major customers.Just three years ago, our systems to be Y2K-ready byJune 1999. large industrial customer satisfaction score was good, but We've also been checking on the Y2 K-readiness status of not good enough. So I1G E account executives went to all ofour suppliers. Plus, we're working with industry work. Our results this year prove our efTorts make a differ-groups such as the North American Electric Reliability ence. We improved by 17 percentage points. Council, Edison Electric Institute, Electric Power Research Institute, American Gas Association, and our WrePreparingforthe har2000andBeyond IlGE partners in the PJM power pool, to plan operations to began tackling the Year 2000 (Y2K) challenge in 1996. allow for a smooth transition to the new century. Since then, experts throughout the company have been working to ensure our systems are ready for a smooth
Generating Winning Numbers ' Our Retall Energy Products Maryland customers will soon have a choice in thei-und $ervices Role CONCENTRATE-energy supplie s, which will change how our power BGE first opened its electric and - ON EMERGING plants do business. In the meantime, wire working to gas appliance stores in the 1920s. , : COMPETITIVE - ENERGY.RELATED provide a smooth transition so that when competition Several years ago, we transferred RETAIL MARKETSIN comes, our customers, sharehoiders, and our power plants this business to our BGE Home MARWAND-will be in a position to win. Products & Services (BGE ..*dd*d To compete in the new electric generation market, our HOME) affiliate. Today, BGE power plants must be able to produce winning numbers-HOME has expanded its go. (es*'97Pedens low costs, high capacity factors, strong safety and environ-product lines to include not only
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mental records, and consistently reliable operations. all major brands of appliances, For the past several years, BG E's power plants have but electronic and entertainment been putting up the right numbers. In 1998, our combined products, plumbing and home improvement services, as fossil and nuclear energy generators posted the lowest well as heating and air conditioning systen s. costs among the PJM power pool utilities for the fourth in fact, in 1998 BGE HOME was voted Baltimarr consecutive year. BG E plants have also increased their magazine's "Best of Baltimore' as the city's foremost appli-production levels every year in this decade. ance and plumbing service source. j For the fourth year in a row, our nuclear facility was well { within the top 10% for individual safety in the industry. Winnerin the Gas Pilot g g g m 7'9 Plus, the fossil generation group again topped its own all. F Program A new role for 5 time low record for OSHA recordable accidents, which also BGE HOME is as a l should place it in the top 10% ofits comparison companies. marketer and seller of i1 We've maintained a solid reliability record, too. Our natural gas.This predictive maintenance practices helped us achieve the summer BGE HOME lowest forced outage rate in the PJM for the fourth consec-entered Maryland's utive year.That means our plants keep producing when it s residential Gas Options most profitable to do so. pilot program. A competitive success, BGE HOME attracted the most BGE' Commitment to the Environment Remains Strong customers of any participant. s Since the Clean Air Act in 1970, BGE has invested hundreds of millions ofdollars in cleaner air, and we A New Play with Constellation Energy Somre While continue to make significant reductions m our emissions. BGE HOME serves residential and small-commercial We are meeting or doing better than regulations require customers in Maryland, Constellation Energy Source is on our sulfur dioxide emissions by burning low-sulfur coal, concentrating on mid-sized industrial and commercial generating nearly halfour electricity using emissions-free customers.Thi., year we have repositioned this business to nuclear fuel and hydmelectric power, retiring several older provide a wide range ofenergy products and services to plants, and installing emissicas reducing equipment. meet the complex energy needs ofsophisticated customers To comply with the 1990 Clean Air Act Amendments in the mid-Atlantic region. and reduce our nitrogen oxide emissions, we expect to spend about $126 million by 2003. We plan to continue T/u Came Goes On Maryland's energy picture is changing. to install new techr. ology at our plants to further reduce Going forward, we intend to continue to be a corporate emissions to comply with new regulations. leader in Maryland. BG E is managing the game at hand and putting the plays in place to maintain our winning edge. c l
4 .I 1 ~ BGE's trading arm made money in 1998, a rare feat for avmg the home-court advantage is one thing, but ~ to succeed in the new wholesale power market, any newcomer, especially in a highly competitive business i. A you've got to know how to go coast-to-coast. like this one. Competit..an might be opening slowly in the retail As e,idenced by the volatile wholesale price swings this energy markets, but the wholesale power market opened summer that had elec zicity selling for as high as $7,000 in 1992. It's been on the fast track ever siace. Emerging per megawatt hour, the market will continue to change. businesses such as power marketing and merchant genera-But it will reward those companies that best understand the tion have achieved tremendous growth and have shown no dynamics that are at work. We believe Constellation Power signs ofletting up. Source has what it takes to succeed. The field ofcompetic,rs, of< ourse, has become Gaining the 7echnologica/ Edge From the new trading crowded quickly.Two years ago, BGE entered the race, too, floor overlooking Bahimore's Inner Harbor, Constellation but we didn't come in to sit back in the pack. We came in Power Source's nearly 100 employees have a real knowing that to succeed, we'd need skill, instinct and agility. p-"- ^ ~v + m We'd also need the nerve to g y take risks and the judgmen* to e know when not to take them. 4 And most importantly, we h v knew we'd need the power y}N}eSale Power Mhketing when the market wanted it. L - and Generation > In the past two years we've [ made some pretty good moves. b ~ GAME PLAll * ~ STRATEGY:- On the wholesale side, we,ve aligned our team and
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nationwide. And with the W dmA passage of the holding 7 company billin Maryland. [ + uw - we will have the ability to finance this strategy. competitive advantage as they trade energy in North America.That's because they have acce s to first-rate Crnstellation Power Source in the Running technology with appropriate risk-management In a strategic move to realize the benefits ofderegulation, infrastructure in pLce. BGE added Constellation Power Source to its roster of Constellation Power Source has customized for subsidiaries in 1997. Whh Goldman Sachs Power as its energy the same trading and risk-management system exclusive advisor, Constellation Power Source provides that Goldman Sachs user to manage ;ts worldwide povr marketing and risk-management services to whole-commodities business. The result is an unparalleled sale energy customers throughout North America. information resource that supplies real-time details on Pairing BG E's electric industry expertise with Goldman trade positions and associated risks. Sachs' trading and risk-management expertise has its advantages. In less than two years, the business went from a Orion Power Deals stan3.ng start to one of the top 25 power marketers in the Building on its power play, Constellation Power Source country. In 1998, trading volume increased nearly 12-fold and an affdiate of Goldman, Sachs & Co. formed Orion to 116 million megawatt hours versus 9 million in 1997. Power Holdings, Inc. this year to pursue buying existing
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power plants in the United States and Canada. In 1998, wmp g NQES: y A h N A#5 Orion acquired the 105-megawatt Carr Street electric generating plant in upstate New Wrk. It also announced g%, gu %w'^. NQ
%gg the planned acquisition of New Wrk State utility
$4s, Niagara Mohawk's 72 hydro generating facilities .3 [ Q w%, totaling 661 megawatts ofcapacity. M g y< ke ). 4* 1k JL., k$ TARGET POWER '
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= y.mi. ~ Our Orion investments provide y~ "1 .j benef:ts on several fronts. First, Orion's power plants will be operated i' E U by our Constellation Operating Senices-a move that [ increases our power plant operating services business. And, p. w O' Constellation Power Source has the exclusive right to market p. i' the output from Orion plants. hi M@ e For example, Constellation Power Source entered into g a tive-year contract to purchase all of the capacity, energy, and ancillary services generated by Orion's Carr Street 1 66 w Generating Station Ll! Constellation Operadag Services will manage that plant. Growing Business Base Constellation Power Source made its move this year to establish a base in New England, one of the first regions to go through the deregulation process. In 1998, Constellation Power Source entered into long-term contracts with Granite Stue Electric Company, Fitchburg Gas and Electric Company, and Eastern Utilities Associates.These contracts mean Constellation Power Source will provide wholesale electricity to these local utilities' customers who have not yet chosen a new electric supplier. l l
i O. TARGET; Constellation Power
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-MERCHANTPLANT Spearheads brabant
5. _ _..
. CONSTRUCTION Plant Construction s b While Orion concentrates on 3- . has more shee l. buying existing power plants to back 12 piers eWl' our trading business, Constellation sievelsping n Power,s focus is now turning to pleses. ' ~ develop, build and operate merchant power plants in strategic regions. The process to build a plant is a long one-usually two years for permitting and two years for construction. But the final product is a large, highly efBcient generation facility whose full capacity can be sold n on the wholesale market. Sewn Merchant Plant Site Approvals Under mzy e Constellation Power has more than 12 years ofexperic nce j developing independent power plants. Its understanding l "~ of the many project factors that need to be considered e is invaluable. As of this writing, Constellation Power is pursuing j N' site approvals for several domestic merchant plant s gg( development projects. They include two sites in California - 15 %I suitable for 750 megawatts ofelectricity; two sites in Texas suitable for 1,600 megawatts; two sites in Horida suitable m for 1.550 megawatts; and one in Massachusetts suitable for 700 megawatts. What makes these sites so attractive is that they will be ,. cy. 3 .gjbJ. sj4 A, 4 n developed to provide power during the times ofhighest w .e demand. They are also strategically located relative to D ?,,. 4 7,/,. E major transmission systems, cooling w.er, and natural ~ r ,i O?<,, p7, ~ ~., ~ Building on Our Strengths Berween our Constellation Power Source, Constellation > TARGET ENERGY. TRADING AND RISK nsteHan. n Operating b.ces Imsinenes, ower, an , : MANAGEMENT;' we have assembled a contender in the merchant generation and power-marketing business. We have the know-how to M build, huy end operate power plants, trade the output on ges,,e has g, us the open market, and manage the risk of fluctuating late see of the sep". energy prices. 25 power merheesesle bh .I.he result? A new future for our company, or employees, and our shareholders-a future we're aggressively building on all fronts. @
l'e, Rf, y, FOCUS ON CONTINUING TO GROW OUR LATIN AMERICAN POWER BUSINESS Our Peneum esgelsitlen serves 170,000 sestoneers. e \\ l aun Amencan utihties. on<c the donuin of Genci.uingin Gu.ucmala 3imilarly. Constellation l\\mcr gm ernments, are being privatized in an effort to has plans to expand the generating <apacity we pur<hased more ettiicntly serve the regions' grow ing in Guatonala. Again, the goalis to tuhill our supply demand for clearititv. I he gmcrnments have turned to agreements and base mcrthant power as.nlable to sell in toreign investors with energy experiente, an inutation that the area as ilemand aucleratet % hase already added ~ has allow ed us to expand our expertise beyond I ' s. borders. 60 megawatts ot new generanon here and did so in rciord ~ Currenth, through our Lonstellation Pow er afliliate. u e time. E tlosed on the Guatemala auiuisition in lanuary ha.e imerests in 15 proic<ts m cight 1.arin Ameri<an 1% and by August -just sescn months laict - we had countrics m<ludmg Argentma. new tapatity onhnc. 161n ia, lirant. Costa Rii a.1.1 Sah ador. ( suatemala. P. mama. Umu/ liming We an n ed on the stenc ai a tonunous and Peru. ilmc. Jnd tiur sut(cu un tar ihko i D rtvl',m.ona has been gr.uitiing ( her the Most ictently, we aujutred the last three scars we h.n e bid 6 ont rollint;intciest in i Ickt ra on sn major prnan/atnios Niire tc. s. A.. ulii< h senc the alid usin i illf til t hcNI..I he castern halt of Panama. h's our u nnpctilhin b h been silIi. biggest auluisnion eser and the "I" i"' "I""E '""' h l.n ge r GAME PLAN: '1 +nst time we has e taken ionnol -i C micrnanonal torporat ions. ot a dninbution sompany. I~he
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Leverage our rcund and m< rease out i Icktra Noreste senes 1 0.000 expeiience and STRATEGY:
"n"hcnnot"ithe t ustomers. L. plan io impim e exEertise-pris.Hi/atiim proscu pct tiinnant c and scrus c to he a signifcant
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l Utility Operating Statistics.._.es.a co,.,.osesu.s Compound 1998 1997 1996 1995 1994 Growth 5-Year 10-Year Eleseres Opereeles Sessissies Revenues (inMillions) Residential $ 948.6 $ 932.5 $ 958.7 $ 955.2 $ 931.7 036% 433% Commercial 912.9 892.6 861.3 879.4 853.0 0.97 3.82 Industrial - 211.5 211.9 207.6 208.5 205.6 1.23 1,77 System Sales 2,073.0 2,037.0 2,027.6 2,043.1 1,990.3 0.71 3.81 Interchange and Other Sales 120.8 132.7 155.9 167.0 118.0 5.71 10.65 Other 27.0 22.3 25.5 21.0 19.1 6.08 1.84 Total $2,220.8 $2,192.0 $2,209.0 $2,231.1 $2,127.4 1.01 4.06 Sales (in kwane)-uwn Residential 10,965 10,806 11,243 10,966 10,670 0.65 1.77 Commercial 13,219 12,718 12,591 12,635 12,351 130 2.20 Industrial 4.583 4,575 4.596 4,591 4,433 4.02 1.00 System Sales 28,767 28,099 28,430 28,192 27,454 1.45 1.84 Interchange and Other Sales 5,454 6,224 7,580 8,149 5,684 5.62 10.27 Total 34,221 34323 36,010 36,341 33,138 2.05 2.77 q Customers (In &wans) Residential 1,009.1 1,001.0 995.2 988.2 978.6 0.83 1,20 2 Commercial 106.5 105.9 104.5 103.4 101.9 1.11 1.41 s Industrial 4.6 4.5 43 4.1 4.0 3.90 5.87 Total 1,120.2 1.111.4 1,104.0 1,095.7 1,084.5 0.87 1.23 Average Use per Residential Customer-mt 10,866 10,794 11,297 11,097 10,903 (0.18) 0.57 s E Average Race per mi(System Sales)-t i Residential 8.65 8.63 8.53 8.71 8.73 (030) 2.51 Commercial 6.91 7.02 6.84 6.96 6.91 (032) 1.59 Industrial 4.62 4.63 4.52 4.54 4.64 (2.67) 0.77 o Peak load (One-Hour)-ww 6,045 5,980 5,955 5,947 6,038 0.57 1.17 Capability at Summer Peak-wr 6,422 6,741 6,800 6,731 6,722 (0.85) 0.80 _l.8_ System load Factor 57.4 % 56.9 % 57.5 % $7.2% 54.7 % 0.78 0.50 ensopeessess eeissenes s Reveuucs (InMilliom) i Residential -hduding Delivery Service $ 279.2 $ 321.7 $ 320.1 $ 248.3 $ 262.7 1.00 2.18 ) -Delivery Service 4.9 0.5 Commercial -Excluding Delivery Service 75.6 113.5 125.1 109.9 121.0 (9.10) 0.27) -Delivery Service 19.4 12.9 7.2 3.7 2.3 42.51 21.80 Industrial -hduding Delivery Service 8.0 11.4 17.1 16.7 20.2 (18.54) (10.29) -Delivery Service 16.0 17.2 14.6 163 9.6 4.40 (037) System Sales 405.1 477.2 484.1 394.9 415.8 (1.09) - 0.77 OESystem Sales 40.9 37.5 26.6 Other 7.2 6.9 6.6 5.6 5.4 (0.28) - (1.29) 'Ibral $ 451.2 $ 521.6 5 5173 $ 400.5 $ 421.2 0.82 1.69 Sales (In kwan&>..tms Residential -ExcludingDeliveryService 33,595 39,958 43,784 40,211 40,279 (3.44) (1,76) -Delivery Service 1,890 205 Commercial -ExcludingDeliveryService 11,775 18,435 22,698 23,612 23,712 (13.15) (637) -Delivery Service 16,633 12,964 8.755 6,982 6,490 17.50 12.72 'ndustrial -Exduding Delivery Service 1,412 2,016 2,887 4,102 4,410 (23.24) (13.21) -Delivery Service 34,798 38,791 36,201 35,925 33,837 2.08 (0.28) i System Sales 100,103 112369 114325 110,832 108,728 (1.50) (0.90) 0$ System Sales 16,724 14,759 9,968 Total 116,827 127,128 124,293 110,832 108,728 1.59 0.65 ) Customers (In & wand) Residential 532.5 524.5 516.5 506.8 498.2 1.63 1.00 Commercial 39.6 39.3 38.9 38.4 37.9 1.10 1.13 Industrial 1.3 13 13 1.3 1.3 'Ibral 573.4 565.1 556.7 546.5 537.4 1.59 1.01 Average Use per Residential Customer (Exduding Delivery Service)- Therms 631 762 848 794 809 (4.99) (2.74) Average Rate perTherm-$ Residential (Exduding Dehvery Service) .83 .81 .73 .62 .65 4.69 4.01 Commercial (Exduding Delivery Service) .M .62 .55 .47 .51 4.65 336 Industrial (Exduding Delivery Service) .57 .57 .59 .41 .46 630 335 Peak Day Sendour (In & wand)--om 658.4 765.0 709.0 706 3 761.9 0.02 (0.17) IYak Day Capability (In & wand)-tmt 833.0 870.0 870.0 847.0 847.0 (0.33) 0.49 Utility operating statistics do not reject the elimination ofintercompany transactions.
Selected Financial Data u,,, ,.c... oa.,,ac.,.,.moseue,. Compound - 1998 1997 1996 1995 1994 Growth (Dollaramounn in millions. exceptpersharramounts) 5-Year 10-Year sesmanery of operesiens Total Revenues $3,358.1 $3,307.6 $3,153.2 $2,934.8 $2,783.0 4.14 % 5.37 % Expenses otherThan Interest and lncome Taxes - 2,617.0 2,584.0 2,483.7 2,239.1 2,147.7 4.25 5.81 Income Frorn Operations 741.1 723.6 669.5 695.7 635.3 3.75 3.98 OtherIncome(Expense) 5.7 (52.8) 6.I 8.8 32.3 (22.43) (11.20) Income Before Interest and IncomeTaxes 746.8 670.8 675.6 704.5 667.6 3.24 3.68 Net Interest Expense 240.9 230.0 198.5 197.0 190.1 4.99 6.87 Income Before incomeTaxes 505.9 440.8 477.1 507.5 477.5 2.47 2.47 IncomeTaxes 178.2 158.0 166.3 169.5 153.9 5.23 6.71 Net income 327.7 282.8 310.8 338.0 323.6 1.13 0.77 Preferred and Preference Stock Dividends 21.8 28.7 38.5 40.6 39.9 (12.21) (2.95) Earnings Applicable to Common Stock $ 305.9 $ 254.1 $ 272.3 $ 297.4 $ 283.7 2.68 1.11 1 Earnings Per Share of Common Stock and j Earnings Per Share ofCommon Stock-m Assuming Dilution $ 2.06 $ 1.72 $ 1.85 $ 2.02 $ 1.93 2.17 (1.14) ) Dividends Declared PerShare of Common Stock $ 1.67 $ 1.63 $ 1.59 $ 1.55 $ 1.51 2.58 2.38 l 29 somunery of riammetal ceedlelen 'Ibtal Assets $9,195.0 $8,900.0 $8,678.2 $8,419.1 $8,145.3 2.86 6.02 i Capitalization Long-term debt $3,128.1 $2,988.9 $2,758.8 $2,598.2 $2,584.9 2.07 5.87 Preferred stock 59.2 59.2 Redeemable preference stock 90.0 134.5 242.0 279.5 Preference stock not subject to mandatory redemption 190.0 210.0 210.0 210.0 150.0 4.84 6.63 Common shareholders' equity 2,981.5 2,870.4 2,854.7 2,811.2 2,719.0 2.61 4.69 Total Capitalization $6,299.6 $6,159.3 $5,958.0 $5,920.6 $5,792.6 1.00 4.51 Messelal seselseles se veer med Ratio ofEarnings to Fixed Charges 2.94 2.78 3.10 3.21 3.14 l Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Stock Dividends 2.30 2.35 2.44 2.52 2.47 Book Valuel'er Share ofCommon Stock $ 19.98 $ 19.44 $ 19.33 $ 19.06 $ 18.43 Number ofCommon Shareholders (In &usands) 69.9 73.7 77.6 79.8 81.5 Certainprior-yearamounts haw been udassipedto conform with the currentyearspusentation.
i Management's Discussion and Analysis of Financial Condition and Results ofOperations Introduction The electric utility industry is undergoing rapid and sub-In Management's Discussion and Analysis, we explain the stantial change. Competition in the generation part ofour general financial condition and the results ofoperations for business is increasing.The regulatory environment (federal BGE' and its diversified business subsidiaries including: and state) is shifting toward customer choice. These matters . are discussed briefly in the " Competition and Response to
what factors afTect our businesses, Regulatory Change" section beginning on page 22.They

what our earnings and costs were m 1998 and 1997, are discussed in detail in our most recent Annual Report on a why earnings and costs changed from the year before, Form 10-K

whereourearningscamefrom,

how all of this affects our overall financial condition, In response to this change, we regularly reevaluate our

what our expenditures for capital projects were in 1996 strategies with two goals in mind: to improve our competitive through 1998, and what we expect them to be in 1999 Position, and to anticipate and adapt to regtdatory change.
through 2001,and These strategies might include one or more of the following-where we will get cash for future capi a expenditures. . the complete or partial separation ofour generation, j a As pu read Management's Discussion and Analysis, it may transmission, and distribution functions, he helpful to refer to our Consolidated Statements of
purchase or sale ofgeneration assets, income on page 37 which present the results ofour

mergers or acquisitions ofutility or non-utility businesses,

SP n-offor sale ofone or more businesses, and i
operations for 1998,1997, and 1996. In Management's Discussion and Analysis, we analyze and explain the annual
growth ofcamings from nonregulated businesses.
g changes in the specific line items in the Consolidated We cannot predict whether any of the strategies described Statements ofincome, above may actually occur, or what their effect on our fman. cial condition or competitive position might be. Please refer to the " Forward Looking Statements" section on page 35. E y ,-m nr.~ x-o <- - ~ s camingswwldhave y,,,jg, of Operations been higher except:
q. L w In this section, we dis-j
[<@ L AI senior-living facili-
ourrealestateand cuss our earnings and the factors affecting
( BTotal Eainings per Share l 1 ties business wrote them.We begin with a f down its invest- .v general overview, then [ 0ofCommon Stock a w men, ;,,,,,i separately discuss [ y
399,- j.3997T 1996 estate pmject, and earnings for the utility { g; g
. gg 93[g1.94: $1.96 - d we wmte off an a busmess and for diver-I JDiMfiedbiMsMN /. '.27 i <434 V N31 energy services sified businesses. [ 3btalearniny pershare fmm1 f 2.28 . 2.27 l ' i In 1998, utilityearn-investment. t [c
1 operations ;
u. 1 2.20' ms
Write-offof mengef cos's (see Note 2 e
inE romoperations l f Our 1996, total earn. ., on Page$g) c.u. H : * (.25), were about the same mgs mereased $51.8
Write-downs ofrealestate ;
v. e million, or $.34 per [ jinvestments(seeNote3 onpage_$2) ((.1:0) _.31) t [ g' '*dh fiy ( P z share, compared to f ss Disallomd replacement " + . mo eta 1997. Our total earn-h,L earmn . energy coats (see Note 10 on page 63) ; - l (.42) n ings increased mostly s[ Write-offofenergy servicss investment L. 3 'Y "*" .H ' "fss section begin-because 1997results
(sdNote2 on page 51) >
' (.04) c reflect our write-offor $niss@rshi Siets $1.72 L. $1.85{ ng n page 21. merger costs, and our In 1998, diversified real estate and senior-s m business camings from living facilities busi-operationsdecreased ness' write-down ofits investments in two real estate compared to 1997 mostly because ofk>wer earnings from our projects, as discussed in the 1997 section below. Our 1998 real estate and senior-living facilities and financial investments
i l businesses. However, we had higher carnings from our power In addition, we charge our electric customers separately for projects and power maaeting and trading businesses. We the fuel vee use to generate electricity (nuclear fuel, coal, gas, l discuss our diversified business carnings in more detail in the or oil) and for the net cost of purchases and sales of electric-l " Diversified Businesses" section beginning on page 26. icy (primarily with other utilities). We charge the actual cost WdiM 1 estate write-down in the "Other f these items to the customer with no profit to us. If these Diversified Busmesses secuon on page 28 and the write-off ue costs g up, the Maryland PSC permits us to increase of the energy services investment in the "Other Energy the fuel rate. If these costs go down our customers benefit from a reducu.on m the fuel race.The fuel rate is impacted Serv. ices section on page 28. most by the amount ofelectncity generated at our Calvert Cliffs Nuclear Power Plant (Calvert Cliffs) because the cost 1997 f nuclear fuel is cheaper than coal, gas, or oil. Our 1997 total earnings decreased $18.2 million, or 5.13 per shaie, compared to 1996. Our total earnings We discuss this in more detail in the " Electric Fuel Rate decreased because: Clause" section on page 24 and in Note 1 of the Notes to Consolidated Financial Statements on page 46. . we wrote ofTcosts associated with the terminated merger l with Potomac Electric Power Company, and Changes in the fuel rate normally do not affect earnings. + our real estate and senior-living facilities business wrote However, if the Maryland PSC disallows recovery of any down its investments in two real estate projects. part of the fuel costs, our earnings are reduced. In 1996, the Maryland PSC disa!! owed certain fuel costs as discussed in We discuss the wn.te-ofTof merger costs m the.Wn.te-Off the,Disa!Iowed Replacement Energy Costs section on of Merger Costs secuon on page 26, and the real estate page 24 and in Note 10 on page 63. wnte-downs.m the.Other Diversified Bus. messes secuon on page 28. We also charge our gas customeis separately for the natural gas they purchase from us.The price we charge for the nat-g l In 1997, utility earnings from operations decreased com-ur I gas is based on a market based rates incentive mecha-i pared to 1996 mostly because we sold less electricity and gas nism appr ved by the Maryland PSC. We discuss market due to milder weather. I based rates in more detail in the " Gas Cost Adjustments" In 1997, diversified business earnings from operations section on page 25 and in Note 1 on page 46. { increased compared to 1996 mostly because of higher From time to time, when necessary to cover increased costs, earnings from our power projects and financial invest-g we ask the Maryland PSC for base rate increases.The ments businesses. Maryland PSC holds hearings to determine whether to grant us all or a portion of the amount requested.The Utility Busineff Maryland PSC historically has allowed us to increase base llefore we go into the details of our electric and gas opera-rates to recover increased utility plant asset costs, plus a ) tions, we believe it is important to discuss factors that have a profit, beginning at the time of replacement. Generally, rate j strong influence on our utility business performance: regu-increases improve our utility earnings because they allow us lation, the weather, other factors including the condition of to collect more revenue. However, rate increases are nor-the economy in our service territory, and competition. mally granted based on historical data, ana those increases rray not always keep pace with increasing costs. j Regulation by the Maryland Public Service I Other parties may petition the Maryland PSC.to lower Commission (Maryland PSC) l our base rates. We discuss th..is m more detail m.the l The Maryland PSC determines the rates we can charge our ,Compeu.. tion and Response to Regulatory Change,, customers. Our races consist of a " base rate and a, fuel . " "" P'E' race." The base rate is the rate the Maryland PSC allows us to charge our customers for the cost of providing them ser-vice, plus a profit. We have both an electnc base rate and a Weather affects the demand for electncity and gas. Very hot l l gas base rate. Higher electnc base rates apply during the summers and very cold winters increase demand. Mild summer when the demand for electncity is the highest. weather reduces demand. Weather. impacts residenn. l sales a Gas base rates are not aff.ected by seasonal changes. more than commercial and industnal sales, which are The Maryland PSC allows us to include in base rates a com-mostly affected by business needs for electricity and gas. pornnt to recover money spent on conservation programs. eders effect using" degree days." A This component is called a conservation surcharge. degree day is the difference betw een the average daily Htr,vever, under th,is surchargc the Maryland PSC Imu. ts actual temperature and a baseline temperature of 65 what our profit can be. If, at the end of the year, we have degrees. o,ooling degree days result w. hen the average daily exceeded out allowed profit, we defer the excess.m that year actual temperature exceeds the 65 degree basdine. Heating and wduser the amount of future surcharges to our cus-degree days result when the average daily actual tempera-tomers to correct the amount ofoverage, plus interest.
ggg;;
J
During the cooling season, hotter weather is measured by On July 1,1998, BGE and all other Maryland investor-more cooling degree days and results in greater demand for owned electric utilities fded with the Maryland PSC their electricity to operate cooling systems. During the heating individual proposals for the transition from a regulated season, colder weather is measured by more heating degree electric supply system to one where generation is priced days and results in greater demand for electricity and gas to based on a competitive retail electric market. In our plan, operate heating systems. we proposed that: Effective March 1,1998, the Maryland PSC allowed us to all customers would be able to choose other suppliers or e implement a monthly adjustment to our gas business our service, revenues to climinate the efTect of abnormal weather we would guarantee our service at rates frozen until July + patterns. We discuss this further in the " Weather 2002. Prices would then be adjusted for inflation until Normalization" section on page 25. the transition is complete, but not beyond 2008, + cust mers who choose an alternate supplier would We show the number ofcooling and heating degree dayd receive a shopping credit. Dus creda would reduce their 1998 and 1997, the percentage changes in the number of degree days from the prior year, and the number ofdegree IlG E bill by the market value ofcapacity, energy, and ther services that we no longer provide those customers, days in a " normal" year as represented by the 30-year average in the following table. + we w uld attempt to reduce potentially stranded invest-ments by lowering operating costs and applying all 30-year carnings in excess ofour authorized rate of return to 1998 1997 average accelerr.: the recovery ofgeneration assets. This would Coolingdegree days 915 746 836 lower the generation asset book values toward their g Percentage change competitive market values thereby reducing any from prior year 22.7 % (5.1)% potentially stranded investment, Heating degree days 4,119 4,822 4,783 + market value ofgeneration assets would be determined l Percentage change by annual independent appraisals beginning in 2002 i from prior year (14.6)% (6.2)% and continuing through the transition period, + when the difference between the book value and market f Otk Tacters value ofgeneration assets is within 10%, the transition Other factors, aside from weather, impact the demand for period would end and a non-bypassable surcharge .12_ electricity and gas. These factors include the " number of would be applied to customers' bills to recover the customers" and " usage per customer" during a given period. remaining stranded investments over a two-to three-2 We use these re.as later in our discussions ofelectric and gas year period, and operations. In those sections, we discuss how these and other + net regulatory assets and nuclear decommissioning costs factors affected electric and gas sales during 1998 and 1997. would ccmtinue to be collected Irom customers through the regulated transmission and distribution business. The number of. customers m a pven perkid is affected by new home and apartment construction and by the number of On December 22,1998, other parties filed their positions businesses in our service territory. in response to our proposal.The counter-proposals contain provisions which, ifadopted by the Ma ytand PSC, could Usage per customer refers to all other items impactmg negatively impact our electric business.The Maryland PSC customer sales which cannot be measured separately.These will hold hearings to examine our electric restructuring factors mclude the strength of the economy in our service uansition proposal and the counter-proposals ofother territory. When the economy is heaichy and expanding, parties. In the meantime, settlement negotiations are ongo-customers tend to consume more electncuy and gas. ing. Absent settlement, the Maryland PSC is scheduled to Conversely, during an economic downtrend, our issue an order by October 1,1999. customers tend to consume less electricity and gas. On Sep: ember 3,1998, the Office of People's Counsel (OPC) Cesapetitlen and Response to Reyelatory Change filed a petition requesting the Maryland PSC to lower our Our electric and gas businesses are also affected by competi_ elearic base rates. At our request, the Maryland PSC agreed tion and regulatory changes. We discuss these items for to consolidate any such review ofour electric base rates with both ofour regulated businesses below. its review ofour electric restructuring transition proposal discussed above. We filed testimony and exhibits with Electric Business the Maryland PSC. supporting our position that our cur-Electnc utih., ties are facing competition on various fronts, rent electric base rates are justified. On February 5,1999, '" " "E other parties, including the OPC, filed testimonics to l + the construction ofgenerating units to meet increased lower our base rates by as much as $ 131 million. As a j demand for electricity, condition of the Maryland PSC's consolidation of these + the sale ofelectricity in bulk power markets, matters, we agreed to make our rates subject to refund + competing with alternative energy suppliers, and effectiveJuly 1,1999 should the Maryland PSC issue a + electric sales to retail customers. rate reduction order after that date.
We cannot predict the ultimate effect competition or The percentage changes in our electric system sales l regulatory change will have on our carnings. volumes, by type ofcustomer,in 1998 and 1997 c mpared to the respective prior year were: We discuss competition in our electric business in more detail in our most recent Annual Report on Form 10-K under the 1998 1997 heading " Electric Regulatory Matters and Competition." Residential 1.5% (3.9)% Commercial 3.9 1.0 Cas Businen Industrial 0.2 (0.4) Regulatory change in the natural gas industry is well I under way. We discuss competition in our gas business In 1998, we sold more electricity to residential customers l in more detailin our most recent Annual Report on mostly because: Form 10-K under the heading " Gas Regulatory Matters . the number ofcus-and Competition. Effective November { i. we bad hotter sum-1 y' =m7.ie e r 1,1998, the pj j mer weather, and l Maryland PSC L y> ,LA A . usage per customer l allowed us to begin I Y +L-increased. f
Bus..mest Earn..mgs per Shire collecting a Delivery Service Realignment k
iof Commbn Stock / ewould have sold T even more electncity to Charge to recover, ) Bectne bummens, $1.757.$1.77l ? $1.75 L m.pt we had milder I certam costs assoca- , ? 1N - residentialcustomers W 1998 1997-ated with the mtro-iGasbusiness... .18 -
17

.21. + winter weather.in 1998. ~ doction of ' T' otalutilityearniny pershare ' Wesold moreelectridtv competition in our { from operations a ' ?,. 1.93 L E l'94 1.96 to commercialcustomers il 1 gas business.This is c Write-offofmerger costs (see Note.2 mosdybecause usageper = not expected ro ' J onpnge51) =, (.25).- s customerincreased.We e o sigmficantlyimpact t Disallowed replacementi. ~ s t & same our carnings. i. . energycosts(seeNote10onpage63bf ' ' (.42) g %tducilityearninsipershaic - ~ $1.93 $1.69 - $1.54 ' amount ofelectricity to i mdustnalcustomers as 23 Utility Business L -2" a - wedidin 1991 +- Earningsper In 1997, we sold less electricity to residential customers Share ofCommon Stock mostl for two reasons: lower usage per customer and j f Our 1998 total utility earnings increased $36.1 million, or milder weather. We sold more electricity to commercial 1 5.24 per share, from 1997. Our 1997 total utility earnings customers mostly because usage per customer increased. increased $24.0 million, or $.15 per share, from 1996.We We would have sold even more electricity to commercial discuss the factors affecting utility earnings below. customers except for milder weather during the year. We sold about the same amount ofelectricity to industrial j cusmmers s we did in 1996. Electric Operation, Base Rates sleetek movenees in 1998, base rate revenues decreased compared to 1997. The changes in electric revenues in 1998 and 1997 Ahhough we sold more electncity m 1998, our base compared to the respective prior year were caused by: rate revenues decreased because oflower conservation 1998 1997 surcharge revenues. (In mdliom) in 1997, base rate revenues increased compared to 1996 Electric system sales volumes $50.8 $(15.5) because ofhigher conservation surcharge revenues. During Base rates (6.6) 29.2 g9 E,gg Fuel rates (8.1) (4.3) surcharge. As a result, we excluded $28.5 million ofour 1996 Total changein electric revenues surcharge billings from revenue.To correct the overage, we from electric system sales 36.1 9.4 lowered the surcharge on our customers' bills over a twelve-Interchange and other sales (13.2) (23.2) month period beginningJuly 1997 through June 1998. Other 4.6 (3.2) Total changein electric revenues $27.5 $(17.0) ElectricSystem Sales %lumes "Bectric system sales volumes" are sales to customers in our j l service territory at rates set by the Maryland PSC.These j sales do not ir.clude interchange sales and other sales. 4 l i
FuelRates ElectricFuelRate Clause in 1998, fuel rate revenues decreased compared to 1997. Under the electric fuel rate clause, we defer (include as an Although we sold more electricity, the fuel rate was lower asset or liability in our Consolidated Italance Sheets and mostly because we were able to use a less-cosdy mix of exclude from our Consolidated Statements ofIncome) the generating plams and electricity purchases. difTerence between our actual costs of fuel and energy and what we collect from customers under the fuel rate in a in 1997, fuel rate revenues decreased compared to 1996 given period. E,e e. her bill or refund our customers that n mosdy because we sold less electncity. difTerence in the future. We discuss the calculation of the IntnrhangeandOtherSales fuel rate in Note 1 on page 46. ' Interchange and other sales" are sales in the PJM (Pennsyh am.a-New Jersey-Maryland) In terconnection In 1998, our actual costs of fuel and energy were higher than the fuel rate revenues we collected from our customers. energy market and to others.The PJM is a regional power pool with members that include many wholesale market in 1997, our actual costs of fuel and energy were lower than participants, as well as IlG E and seven other utility compa-the fuel rate revenues we collected from our customers. nies. We sell energy to PJM members and to others after we have satisfied the den.and for electricity in our own system. DisallowedReplacanent E.nergy Costs In December 1996, we settled fuel rate proceeding almut in 1998 and 1997, interchange and other sales revenues extended outages that occurred at Calvert Cliffs from 1989 decreased compared to the respective prior year mosdy through 1991. We agreed not to bill our customers for because oflower sales volumes. $118 million ofelectric replacement energy costs associated with the outages. We wrote offa portion oithe costs in Electric Fuel and Purchased Energy Expenses 1990 and wrote off the remainder in 1996. We discuss this { 1998 1997 1996 further in Note 10 on page 63. Un mzhns) e-e Actual costs $514.7 $504.5 $539.2 Gas Operations i Net recovery (deferral) ofcosts under electric fuel Gas Revenues j rate clause (see Note 1 The changes in gas revenues in 1998 and 1997 compared to on page 46) (9.0) 15.2 8.2 the respective prior year were caused by: _21 Disallowed replacement energy 3993 g997 costs (including carrying g,,,,,,w charges) (see Note 10 on page 63) 95.4
8Y"#* ** **

Base rates 14.2 0.6 lbtal electric fuel and Weather normalization 10.1 purchased energy expenses $505.7 $519.7 $642.8 Cas cost adjustments (87.6)
(0.2) Actual Co,,, Total change in gas revenues In 1998, our actual costs of fuel to generate electricity from gas system sales (74.1) (6.9) (nuclear fuel, coal, gas, or oil) and electricity we bought Off-system sales 1.8 10.9 from others increased compared to 1997 mo= ly becausewe Other 0.1 0.3 setded a capacity contract with PECO Eneg ,mpany. Total change in gas revenues $(72.2) $ 4.3 In 1997, our actual costs decreased compared to 1996 Clas Syston S< des Volumes mostly for two reasons: we Emught less electricity from The percentage changes in our gas system sales volumes, others as a result ofbeing able to meer demand using the by type ofcustomer, in 1998 and 1997 compared to the electricity we generated, and we were able to use a less-costly respective prior year were: mix ofgenerating plants mosdy because we generated more elecincity at Calvert Cliffs. Residential (l 1.6)% (8.3)% Commercial (9.5) (0.2) Industrial (11.3) 4.4 I I J
T J 4 In 1998, we sold len gas to residential and commercial index (a measure of the market price of gas in a given customers mosdy for two reasons: milder weather and kiwer period).The difTerence between our actual cost and the usage per customer. We would have sold even less gas to market index is shared equally between shareholders and residential and commercial customers except the number of customers, and does not significantly impact earnings. We customers increased. We sold less gas to industrial customers also discuss this in Note 1 on page 46. mosdy because usage by Bethlehem Steel (our largest Delivery service customers, induding Bethlehem Steel, are not customer) and other industrial customers decreased. subject to the gas cost adjustment dauses because we are not in 1997, we sold less gas to residential customers mosdy for selling gas to them. We charge these customers fees to recover two reasons: lower usage per customer and milder weather. the fixed costs for the transportation service we provide.nese We sold about the same amount ofgas to commercial fees are essentially the same as the base rate charged for gas customers as we did in 1996. We soki more gas to industrial sales and are induded in gas system sales volumes. customers mosdy for two reasons: milder weather caused In 1998 and 1997, gas cost adjustment revenues decreased fewer service interruptions and Bethlehem Steel used more compared to the respective prior year mosdv because we gas Sometimes we need to interrupt service during periods sold !:ss gas, with the highest demand. Some industrial customers pay reduced rates in exchange for our right to interrupt their OfSystem Sales service during these periods. We would have sold even more Off-system gas sales are low-margin direct sales of gas to gas to industrial customers except gas usz :by industrial wholesale suppliers of natural gas outside our service customers other than Bethlehem Steel decreased. territory. Off-system gas sales, which occur after we have satisfied our customers' demand, are not subject to gas cost adjustments.The Maryland PSC approved an arrangement In 1998, base rate revenues mcreased compared to 1997. for part of the margin from off-system sales to benefit Although we sold less gas uuring 1998, our base rate revenues g,,g ,;gg = mcreased mosdy because the Maryland PSC authomed an retained by BG E (which benefits shareholders). Changes in increase in our base rates effecuve March 1,1998.The off-system sales do not signih. candy impact earmngs. change in rates will increase our base rate revenues over the twelve-month period from March 1998 through February in 1998, off-sysem gas sales revenues increased compared a 1999 by approximately $16 million. to 1997 mostly because we sold more gas off-system. 8 in 1997, base rate revenues increased compared to 1996. In 1997, off-sysrem gas sales revenues increased compared 1 Although we sold less gas in 1997, our base rate revenues to 1996 mosdy because we first began off-system sales ofgas increased because of higher conservation surcharge in February 1996. revenues during the last six mombs of the year. Oos Perdiesed for Rese's byenses TeatnerNormalizatwn EfTective March 1,1998, the Maryland PSC allowed us 1998 1997 1996 to implement a monthly adjustment to our gas base rate haunW revenues to diminate the effect of abnormal weather Actual costs $212.2 $291.6 $295.4 patterns on our gas system sales volumes.This means our Net recovery (deferral) c' monthly gas base rate revenues will be based on weather costs under gas adjr r that is considered " normal" for the month and, therefore, clauses (see Note 1. (3.6) 0.5 (11.0) will not be affected by actual weather conditions. Tbtal gas purchased for Cas CostAdjustment, resale expenses $208.6 $292.1 $284.4 We charge our gas customers for the natural gas they pur-gg chase from us using gas cost adjustment dauses set by the Actual costs indude the cost ofgas purchased for resale Maryland PSC.These dauses operate sumlar to the electnc to our customers and for off-system sales. Actual costs fuel rate dause descnbed m the Electnc Fuel Rate Clause,, do not include the cost of gas purchased by delivery section on page 24. However, effective October 1996, the Maryland PSC In 1998 and 1997, actual gas costs decreased compared to approved a modification of these gas dauses to provide a the respective prior year mosdy because we sold less gas. market based rates incentive mecham.sm. Under market based rates, our actual cost of gas is a mpared to a market
I I CarAdjmtment Clauses agreemenc. Accordingly, in 1997, we wrote off $57.9 million We charge customers for the cost ofgas sold through gas ofcosts related to the merger. nis write-offreduced after-tax adjustment clauses (determined by the Maryland PSC), earnings by $37.5 million, or $.25 per share. as discussed under " Gas Cost Adjustments" eadier in this section. saterest cheroes In 1998, actual gas costs were higher than the revenues we Intettst charges represent the in terest on our outstanding debt. collected from our customers. In 1998, interest charges increased $6.7 million compared In 1997, actual gas costs were lower than the revenues we to 1997 mostly because we had more debt outstanding. collected from our customers. Interest charges would have been higher except interest rates g Other Operating Expense, In 1997, interest charges increased $23.6 million compared to 1996 mostly for two reasons: we had more debt operations and hintemenee N r::: outstanding and interest rates were higher. In 1998, operations and maintenance expenses increased $34.8 million compared to 1997 mostly because of: ImeeeneTemos + higher nuclear costs, In 1998, income taxes increased $20.2 million compared to + higher employee benefit costs, and 1997 because we had higher taxable income from both our ut perat nsan ur d.ivendehusinenes. . a $6.0 million write-offofcontributions to a third party for a low-level radiation waste facility that was never In 1997, income taxes decreased $8.3 million compared to 8 completed. 1996 because we had lower taxable income from both our utility operations and our diversified businesses. In 1997, operations and ma.mtenance expenses were slightly lower than they were in 1996. e DiversifiedBusinesses 8, soproeletten and Assertization Expensee Our diversified businesses engage primarily in energy 7 We describe depreciation and amortization expenses in services. Our energy services businesses indude certain Note 1 on page 48. subsidiaries ofConstellation* Enterprises, Inc. and the a 26 In 1998, deprec.ianon and amortization expenses increased District Chilled Water General Partnership (ComfortLink'), ] $34.2 million compared to 1997 mostly because: a generalpartnership m which BGE.is a partner.Theyare: I . in October,1998, the Maryland PSC authorized us to . Constellation Power Source
Inc.--our wholesale implement new electnc depreciation rates retroactive t power markenng and trading business,
+ Constellation Power, Inc.and Subsidiaries-our January 1,1998, which mcreased depreciation expense by approximately $13.9 million, P **'P"5ects business,
Constellan.on Energy Source Inc.-our energy a we had more utility plant m service (as our level ofplant products and services business,
] m semce changes, the amount ofour depreciation and
BGE Home Products & Services,"Inc. and amortization expense changes), and

we reduced the amortization period for certam com-Subsidiaries-our home products, commercial building systems, and res.denn. l and small commercial gas retail i
a purer software beg.mnmg m the first quarter of1998 from five years to three years. marketmg business, and , ComfortLink-oi r cooling services business for In 1997, depreciation and amortization expenses increased commercial customers in Baltimore. $ 12.7 million compared to 1996 mostly because we had Constellan.on Enterprises,Inc.dso has two other more plant m semce. subsidiaries: OtherIncome andExpense, . ConstellationInvestments*Inc.-outfinancial investments business, and write-off of mroer costs
Constellation Real Estate Group," Inc.-our real estate in September 1995, we signed an agreement with Potomac and senior-living facilities business.
Electric Power Company to me rge together into a new We describe our diversified businesses in more detail in company, Constellanon Energo Corporation, after all necessary regulatory approvals were received. In December our most recent Annual Report on Form 10-K under item 1 Business-Diversified Businesses. 1997, both companies mutually terminated the merger 1
Diversi/ led Business Earningsper Share of be raterial. In 1998, assets and liabilities from energy Common Stock trading activities increased because ofgreater trading Our 1998 diversified business earnings increased activity compared to 1997. $15.7 million, or $.10 per share, compared to 1997. Our in March 1998, Constellation Power Source and Goldman, 1997 diversified business earnings decreased $42.2 million, Sachs Capital Partners 11 LP., an afIlliate ofGoldman, Sachs or $.28 per share, compared to 1996. & Co., formed Orion Power Holdings, Inc. (Orion) to We discuss factors affecting the earnings ofour diversified acquire electric generating plants in the United States and businesses below. Canada. Constellation Power Source has a commitment to fund its investment in Orion as discussed further in Note lo on page 61. EnergyServices p.w.,,,.g.c.a p.w.,m.,k.a., y x-m 1 and 7,eding 7 r In 1998, earnings from in 1998, earnings q our power projects busi- [ ness increased compared from our power c i j to 1997 mostly because marketing and I r B' i.usmess Earn..mgs per Share-t trading business [ Constellation Power increased compared I
of Common Stockj recorded a $10.4 million after-tax gain for its to 1997 mostly
( because ofincreased ! wa '1998 b 1997 1jd63 J share ofearnings in a ~ ' ' ' trading activities in f
Energyservices

'.
partnership.The part. cs.05; ;$.00 i nership recognized a @Awer marketingand tradingi 1998 which was 7
er Pmjects; 130 :
25 3
.18 ), } gain on the sale ofits E Constellation Power [ Source's first full [ Other ' (.01) ? ].05) - ~.02 : ownership interest in a Torahnergy serw,ces eamm.gs ? 9 power sales contract. year ofoperations. [ pershare from operanons :! 4 343 '20 c.20 ' ] j ... Other diversified businesses 4 In 1997, earnings a i Constellation Power Source uses the [ carnings per share from operations '(.07) .145 .111 increased compared to i 1996 mostly because of mark-to-market ? Total diversified business camings. improved performance 2 - _7_ method ofaccount- . Persharefmmoperations : S27f '.34 .31. ing forits trading [ a Write-downs of real estate inwstments :. ofvarious energy activities. We discuss l
(see Note 3 on page 52) E a (.10)f [*(.31)1 f-s projects. Also,1996 iWrite-offofenergy services investmentt (.04) '
^ earnings included the mark-to-market 'Ibralearningspershare. . $.13 $.03 - $.31 $14.6 million (after-method of account, r t l tax) for Constellation ing and Constella- ~' Power's percentage '"^ tion Power Source's trading activities in Note 1 on page 47. share c.f earnings in a partnership. The partnership recognized a gain on the sale As a result of the nature ofits tradm.g acuvmes, of a power purchase agreement.These increases were offset Constellanon Power Source s revenue and earn.mgs will by $16.2 million of after-tax write-offs ofinvestments in fluctuate. We cannot predict these fluctuations, but the certain power projects. effect on our revenues and earnings could be material.The primary factors that cause these fluctuations are: We describe our earnings in the partnerships and the write-offs further in Note 3 on page 52.
the number and s.ize ofnew transactions,

the magnitude and volatility ofchanges in commodity California Pouer Purchase Agn>cments Constellation Power and subsidiaries and Constellation prices and interest rates, and

the number and size ofopen commodity and derivative Investments have $310.6 million invested in 15 projects positions Constellation Power Source holds or sells.
that sell electricity in California under power purchase agree-ments called " Interim Standard Offer No. 4" agreements. In Constellan.on Power Source's management uses its best esti-1998, earnings from these projects were $41.3 million, or mates to determme the fair value of commodity and deriva- $.28 per share. tive positions it holds and sells.These estimates consider various factors including closing exchange and over-the-Under these agreements, the electricity rates change from counter price quotations, time value, volatility factors, and fixed rates to variable rates beginning in 1996 and continu-credit exposure. However, it is possible that future market ing through 2000.The pmjects which already have had rate prices could vary from those used in recording assets and changes have lower revenues under variable rates than they liabilities from trading activities, and such variations could did under fixed rates. When the remaining projects transi-tion to variable rates, we expect their revenues aho to be lower than they are under fixed rates.
Our power projects business is pursuing alternatives for estate and senior-living facilities business decreased compared some of these projects including: to 1997 mostly due to: repowering th projects to reduce operating costs, a $15.4 million after-tax write-down ofits invesunent + a changing fu. 'o reduce operating costs, in Church Street Station-an entertainment, dining, + renegotiating the power purchase agreements to and retail complex in Orlando, Florida, j improve the terms, lower earnings from various real estate and senior-living + restructuring financing to improve existing terms, and facilities projects, and + selling its ownership interests in the projects. . a $4 million after-tax gain on the sale of two senior-a .Ihe California projects that make the highest revenues will living facilities projects reflected in 1997 results. transition in 1999 and 2000.The projects which transition in addition, in 1998, our real estate and senior-living facili-in 1999 contributed $10.7 million, or $.07 per share to ries business exchanged certain assets and liabilities in return i 1998 earnings, while those changing over in 2000 con-for a 41.9% equity interest in Corporate Office Properties tributed $24.0 million, or $.16 per share to 1998 earnings. Trust (COPT), a real estate investment trust. We expect earnings to ultimately decrease by similar Earnings from our financial investments business decreased amounts begm.mng m 1999 as these projects transition. compared to 1997 mostly because of: We describe these projects in more detail in Note 10 on + better market performance for our investments in I E* 1997,and InternationalProjuts a $6 million after-tax gain on the sale ofstock held by a At December 31,1998, Constellation Power had invested financiallimited partnership reflected in 1997 results. E about $183.4 million in 15 power projects in latin America n In 1997, earnings from our other diversified businesses compared to $23.5 m.lh.i on mvested in bu. Amen.ca m e 1997.These.mvestments include: mcreased compared to 1996 mostly because of m. creased ~ cammgs m our financ. l investments business from ia l
the purchase ofa 51% interest in a Panamanian electric better earnings in trading securities and increased gains distribution company for approximately $90 million in from marketable securities. Earnings would have been j
1998 by an investment group in which subsidiaries of higher except we had a decrease in earnings from our real Constellation Power hold an 80% interest, and estate and senior-living facilities business mostly due to: approximately $98 million for the purchase ofexisting 28 + a $ 14.1 million after-tax wnte-down of the investment electric generation facih..nes and the construction ofan m Church Street Station, and electric generation facility in Guatemala. e* a $31.9 million after-tax write-down of the investment in In the future, Constellation Power expects to expand its Piney Orchard-a mixed-use, planned-unit development. power projects business further in both domestic and international projects. We discuss our real estate projects, the wn.te-downs of our real estate projects, the COPT transaction, and our financial investments further in Note 3 on page 52. ohr snergy services In 1998, earnings from our remaining energy services busi-We consider market demand, interest rates, the availability nesses increased compared to 1997 due to improved results of financing, and the strength of the economy in general from our energy products and services business. Earnings when making decisions about our real estate projects. Ifwe would have been higher except we recorded a $5.5 million were to decide to sell our real estate projects, we could have after-tax, or 5.04 per share, writc-offofour investment in, write-downs. In addition, if we were to sell our real estate and certain ofour product inventory from, an automated projects in the current market, we would have losses which electric distribution equipment company. We recorded this could be material, although the amount of the losses is hard write-off because of that company's inability to raise capital to predict. Depending on market conditions, we could also and sellits products. have materiallosses on any future sales. In 1997, earnings from our remaining energy services busi-Management's current real estate strategy is to hold each real nesses decreaed compared to 1996 mostly because oflower estate project until we can realize a reasonable value for it earnings from our energy products and services busine:3. except for Church Street Station which we intend to sell. Management evaluates strategies for all its businesses, including real estate, on an ongoing basis. We anticipate Other Divernf. ledBun.neses that competing demands for our financial resources and In 1998, earnings from our other diversified businesses changes in the utility industry will cause us to evaluate decreased compared to 1997 mostly for two reasons: lower thoroughly all diversified business strategies on a regular earnings from our real estate and senior-living facilities and basis so we use capital and other resources in a manner that financial investments businesses. Earnings from our real is most beneficial. {
FinancialCondition In 1998, cash used in financing activities increased compared I* to 1997 mosdy because of the repayment of short-term borrowings that matured, smlung fimd requirements, and Cash provided by (used in): cady redemption ofhigher cost securities. Net cash used OperatingActivities $820.8 $726.0 $701.9 would have been higher except we issued more long-term Investing Activities (625.0) (520.8) (567.0) debt and common stock in 1998 compared to 1997. Financing Activities (184.7) (109.3) (91.6) In 1997, cash used in financing activities increased f.om in 1998 and 1997, cash provided by operations increased 1996 mostly because of the repayment oflong-term debt compared to the respective prior year mostly because of and short-term borrowings that mamred, sinking fund changes in working capital requirements. requirements, and early redemptions of higher cost securities. In 1998, net cash used in investing activities increased com_ Net cash used would have been higher except we issued more pared to 1997 mosdy because ofthe additional investment I "S-term debtin 1997 compared to 1996. in international power projects. Cash used in investing would have been higher except for a $33.8 million dec ease s w W lass in utility construction expenditures. Independent credit-rating agencies rate our fixed-income securities.The ratings indicate the agencies' assessment of In 1997, net cash used in investing activities decreased our ability to pay interest, distributions, dividends, and mostly because of the $79.5 million cash inflow from the principal on these securities.These ratings affect how much sale of real estate properties and the increase in loans it will cost us to sell these securities.The better the rating, collected from real estate projects compared to 1996. Cash the lower the cost of the securities to us when we sell them. 3 used in investing activities would have been lower except for Our securities ratings at the date of this report are shown in a $12.7 million increase in utility construction expenditures, the following table. and $46.5 million increase for our investments in power . mite Standard Moody's Duff & Phelps' a projects and financial h.. d partnerships. l g gy,,,, Invesmes credit Total utility construction expenditures, including the Racing Gmup Service Racing Co. allowance for funds used during construction, were Mortgage Bonds AA-Al AA- $339.4 million in 1998 as compared to $373.2 million Unsecuced Debt A A2 A+ _21 in 1997 and $360.5 million in 1996. Trust Originated Preferred Securities & Preference Stock A "a2" A CapitalResources Our business requires a gre.t deal ofcapital. Our actual
regulation, legislation, and competition, capital requirements for the years 1996 through 1998,

load growth, along with estimated annual amounts for the years 1999

environmental protection standards, through 2001, are shown in the table on page 30. For the

the type and number ofprojects selected for year ended December 31,1998, our ratio of earnings to development, fixni charges was 2.94 and our ratio of earnings to com-

the effect of market conditions on those projects, bined fixed charges and preferred and preference dividend

the cost and availability of capital, and requirements was 2.60.

the availability ofcash from operations.
Investment requirements for 1999 through 2001 include Our estimates are also subject to additional factors. Please estimates of funding for existing and anticipated projects, see " Forward Looking Statements" on page 35. We continuously review and modify those estimates. Actual investment requirements may vary from the estimates . icluded in the table on page 30 because of a number of factors including:
1996 1997 1998 1999 2000 2001 (In milliom) utsmy Be see copates negoireiseets Construction expenditures (excluding AFC) Electric $219 $ 238 $ 239 $ 285 $ 269 $ 290 Gas 84 89 55 74 70 69 Common 46 38 35 25 20 18 Total construction expenditures 349 365 329 384 359 377 AFC 10 8 10 11 13 19 Nuclear fuel (uranium purchases and processing charges) 47 44 50 50 50 48 Deferred conservation expenditures 31 27 16 1 Retirement oflong-term debt and redemption ofpreference stock 184 243 222 341 253 195 Total utility business capital requirements 621 687 627 787 675 639 Diversibd Besleees Capitel tegelressents: Investment requirements 118 156 325 423 480 500 Retirement oflong-term debt 52 188 232 200 273 363 Total diversified business capital requirements 170 344 557 623 753 863 s Total capital requirements $791 $1.031 $1,184 $1.410 $1,428 $1,502 m Capitel Regelreements of Ove Utility Be=8eess We discuss the NOx regulations further in Note 10 l Our estimates of future electric construction expenditures do ori page 61. not include 1sts to build more generating units. Electric = constructio-menditures mclude improvements to generat-Our utility operations provided about 108% in 1998, I 105% in 1997, and 96% in 1996 of the cash needed to ing plants o our transmission and distribunon facihnes. ut c8P tal requirements, excluding cash needed to i meet ~ Theyalso ni ade estimated costs for replacing the steam gen. 30 crators aim tending the operating licenses at Calvert Cliffs. retire debt and redeem preference stock. j The operatn'.glicenses expire in 2014 for Unit I and in 2016 We will continue to have cash requirements for: for Unit 2. We estimate these Calvert Cliffs costs to be:
work.ing capital needs m.cluding the payments
$34 million in 1999, ofinterest, distributions, and dividends, l $44 million in 2000,and . capitalexpenditures,and $58 million in 2001. . the retirement ofdebt and redemption of { We estimate that during the two-year period 2002 through Preference stock. 2003, we will spend an additional $ 151 millic ii to complete During the three years from 1999 through 2001, we npect the replacement ofthe steam generators and extend the utility operations to provide about 115 % of the cash needed l operating licenses at Calvert Cliffs. We discuss the license to meet our capital requirements, excluding cash needed to ] extension process further in the "Calvert Cliffs License retire debt and redeem preference stock. Extension" section on page 33. When we cannot meet our uuh.ty capital requirements Ifwe do not replace the steam generators, we estimate that internally, we sell debt and equity securities. We also sell Calvert Cliffs could not operate for the full term ofits cur-securities when market conditions permit us to refinance rent operating licenses. We expect the steam generator existing debt or preference stock at a lower cost.The replacements to occur during the 2002 refueling outage for amount.of cash we need and market conditions determine Unit I and during the 2003 refuelingoutage for Unit 2. when and how much we sell. Additionally, our estimates of future electric construction Future funding for capital expenditures, the retirement of expenditures include the costs ofcomplying with Environ-debt, redemption ofpreference steck, and payments of mental Protection Agency (EPA) and State ofMaryland interest and dividends is expected to be provided by inter-65% nitrogen oxides emissions (NOx) reduction regula-nally generated funds, commercial paper issuances, avail-tions as follows: able capacity under credit facilities, and/or the issuance of $29 million in 1999, 1 ng-term debt, trust securities, or equity. a + $28 million in 2000, = $33 million in 2001,and $14 miUion in 2002. i a
At December 31,1998, we have the authority from the cash needed to meet capital requirements in the future Federal Energy Regulatory Commission to issue up to through these same methods. BGE Home Products & $700 million of short-term borrowings. In addition, we Services may also meet capital requirements through sales maintain $113 million in committed bank lines ofcredit ofreceivables. and we have $ 100 million in bank revolving credit agreements to support the commercial paper program Ifwe can get a reasonable value for our real estate as discussedin Note 6 on page 57. ddibhsbMs@ dig real estate projects.The ability to sell or h.qu'date assets will depend on market conditions, and we cannot give capitel a egelreements of oor elversnhd sesinesses Certam ofour d.iversified businesses expect to expand their assurances that these sales or hquidations could be made. We discuss the real estate business and market m the businesses which will require add..inonalinvestments.These .Other D.iversified Bus. messes secuan on page 28 and mvestment requirements mclude funding for: in the Notes to Consolidated Financial Statements . growing our power marketing and trading business, beginning on page 45. . the development and acquisition ofpower projects, as well as loans to project entities, Our diversified businesses also have revolving credit . investments in financiallimited partnersh.ips, and agreements totaling $270 million to provide additional . ftmding for construction ofcooling system projects. liquidity for short-term financial needs, including the issuance of up to $135 million ofletters of credit. The investment requirements exclude BG E's commitment In 1998, a subsidiary of Constellan. d on on Enterprises, Inc. to contribute up to $ i 15 m. lion in equity to Constellan. Power Source, Inc. to ftmd its investment in Orion Power !ssued $157 milh.on of two-and three-year notes to several Holdings,Inc. m5utuu nalinvest r5 in a Private P acement ffering-l In 1997, ur diversified businesses issued $289 mien of = Our diversified businesses have met their capital require. three-and four-year notes. ments in the past through borrow.mg, cash from their operations, and from time to time equity contributions We discuss our short-term borrowings in Note 6 on page 57 E from BGE. Our diversified businesses plan to raise the and long-term debt in Note 7 on page 57. a .ll MarketRisk We are exposed to market risk, including changes in interest lakr*d mete nisk rates, certain commodity prices, equity prices, and foreign We are exposed a changes in interest rates as a result of currency. To manage our market risk, we may enter into financing througl our issuance of variable-rate debt, fixed-various derivative instruments including swaps, forward rate debt, and pre irred and preference securities.The contracts, futures contracts, and options. Please refer to the following table provides information about our obligations " Forward looking Statements'section on page 35. We that are sensitive to interest rate changes, discuss our market risk and the related use ofderivative instruments in this section. Principal Payunents and laterest Rete Detall by Centracteel Meterity Date Fair value at 1999 2000 2001 2002 2003 There fter Total Dec. 31,1998 (In m&m) Long-term debt Variable-rate debt $306.5 $ 40.9 $ 75.0 $ 0.9 $ 6.6 $ 278.3 $ 708.2 $ 708.2 Average interest rate 5.59 % 5.97 % 5.92 % 7.79 % 6.89 % 4.20 % 5.11 % Fixed-rate debt $228.2 $485.1 $482.8 $154.6 $286.6 $1,329.7 $2,967.0 $3,076.6 Average interest rate 7.85 % 7.16 % 7.08 % 7.31 % 6.51% 6.72 % 6.95 % PnfmnceStock Fixed-rate preference stock $ 7.0 5 - 7.0 7.2 Average interest rate 7.85 % 7.85 %
Commeellty Price Risk of their value. Additionally, Constellation Power Source We are exposed to the impact of market fluctuations in the estimates variances and correlation using historical market price and transportation costs of natural gas, electricity, movements over the most recent rolling three-month period. and other trading commodities. Currently, our gas business and energy services businesses use derivative instruments to The value at nsk amount represents the potential loss.m the fa.r value ofassets and liabih..ues from trading activities over manage changes m. their respective commodity prices. a one-day holding period with a 99.6% confidence level. Cas Businar Using this confidence level, Constellation Power Source Our gas business may enter into gas futures, options, would expect a one-day change in fair value greater than or and swaps to hedge its price risk under our market based equal to the daily value at risk at least once per year. As of rates incentive mechanism and our off-system gas sales December 31,1998, Constellation Power Source's value at program. We discuss this further in Note 1 on page 46. At risk was $6.0 million. December 31,1998, our exposure to commodity price risk Constellan,on Power Source,s calculan.on includes all assets for our gas bus. mess was not matenal. and liabih..nes from tradm.g acavmes, mcluding energy Energy Scrrices Businesses commodities and derh atives that do not require cash settle-With respect to our energy services businesses, Constell-ments. We believe that this rcpresents a more complete ation Power Source manages its commodity price risk calculation ofour value at risk from energy trading activities. inherent in its energy trading activities on a portfolio basis, subject to established tradinj;and nsk management policies. De to the mlathe immamnry of the mmpenthe maAet I I''icity and related derivatives and the seasonah,rv of Commodity price risk arises from the potential for changes in the value ofenergy co.nmodities and related derivatives changes.m market prices, the value at nsk calculation may due to: changes in commodity prices, volatility of com-n t reflect the full extent ofour commodity pnce nsk I modity prices, and fluctuations in interest rates. A number exp sure. Addm nally, actual changes m the value of l of factors asuciated with the structure and operation of the pti ns may differ from the value at nsk calculated using a electricity market significantly influence the level and Unear appmemati n inherent m our calculanon method. j volatility ofprices for electricity and related derivative We discuss Constellation Power Source's trading business in products.These factors include: the " Power Marketing and Trading" section on page 27 and
seasonal changes in the demand for electricity, in Note 1 on page 47.

hourly fluctuations in demand due to weather The commodity price risk for our remaining energy services 32 conditions, businesses was not material.
"o available generation resources, a transmission availability and reliability within and Egelty Price Risk + between regions, and We are exposed to price fluctuations in equity markets procedures used to maintain the integrity of the primarily through our financial investments business and e physical electricity system during extreme conditions. our nuclear decommissioning trust fund. We are required These factors can afTect energy commodity and den.. by the Nuclear Regulatory Commission (NRC) to maintain vanve a trust to fund the costs ofdecomm..issionmg Calvert Cliff. s. prices in different ways and to dicierent degrees.These effects may vary throughout the country and result from At December 31,1998, equity price risk was not material. We discuss our nuclear decommissioning trust fund.m regional differences.m: more detail in Note 1 on page 49. We also describe our weather conditions, financial investments in more detail in Note 3 on page 52. a market liquidity, l a capability and reliability of the physical electricity Foreign currency Risk system, and We are exposed to foreign currency risk primarily through the natm e and extent ofelectricity deregulation. our power projects business. Our power projects business Constellation Power Source uses various methods, including has $183.4 million invested in 15 international power a value at risk model, to measure its exposure to market risk generation and distribution projects as of December 31,1998. I from energy trading activities. Value at risk is a statistical I """"B" "*P"""
I I " '.mency risk, the S
model that attempts to predict risk ofloss based on historical m j rity f ur mntracts are denommated m or mdexed to market price and volatility data. Constellation Power Source the U.S. dollar. At December 31,1998, foreign currency ] calculates value at risk using a variance /covariance technique risk was not material. We discuss our, ternational projects m that models option positions using a linear approximation in the " Power Projects" section on page 28. j
OtherMatters Of these creas, digital systems have the most impact on our ability to provide electric and gas service. Telecommunications, major suppliers, and certain in 1998,we fded an apph. canon for a 20-year h. cense exten' information technology applications also impact our son for Calvert Cliffs with the NRC to extend its license ability to provide electric and gas service. beyond 2014 for Unit I and 2016 for Unit 2. License renewal evaluations focus on age-related issues in long-lived Year 2000PmjectPhases passive components (passive components include buildings, Our year 2000 project is divided into two phases: the reactor vessel, piping, ventilation ducts, electric cables, . Phase I-initial assessment and detailed analysis, and etc.). We must demonstrate that we can ensure that these , PhaseII-test ng,remediation, certification,and passive components will continue to perform their mtended contingency planning. functions through the renewal period.The NRC will also consider the impact of the 20-year license extension on Phase I involves conducting an inventory of all systems and the environment. identifying appropriate resources. We have identific following appropriate resources for each system or We began the license extension process in 1998 because the equipment: NRC may not rule on our application until 2002 or 2003 If the NRC denies our application, we rrust have adequate
BGE employees familiar with each system or time to begin replacement power source planning. We piece ofequipment, cannot predict the timing of, or impact, if any, of the NRC's

specializedcontractors,and decision on our financial results. Ifour app'ication is denied,

specificvendors.
it could have a material effect on our financial results. Phase I also includes developing action plans to ensure that the key areas identified above are year 2000 ready.The severenameses ameners = d action plans for each sysicm or piece ofequipment mclude: a T,ou w. l find details ofour environmental matters m Note 10 on page 61 and in our most recent Annual Report
our budget, on Form 10-K underitem 1. Business-Environmental
. schedulesforPhase1and11,and Matters. These details include financial information. Some e our remediation approach-repair, upgrade, replace a of the information is about environmental costs that may be or retire. E material to our financial results. In evaluating our risks and estimating our costs, we utilized X employees with expertise in each line ofbusiness to perform ' "' " **8**** h We activities under Phase 1. We believe our employees are the We have not experienced any significcnt year 2000 problems most familiar with their systems or equipment and therefore to date and we do not expect any significant problems t will provide a reliable estimate afour risks and costs, impair our operations as we transition to the new century. However, due to the magnitude and complexity of the year Phase 11 includes converting and testing all ofour systems. 2000 issue, even the most conscientious efforts cannot Each system will be tested by those employees used in guarantee that every problem will be found and corrected Phase I following formal guidelints developed by the prior to January 1,2000. We are focusing on cridcal PMO. Each system or piece ofequipment will then be operating and business systems and expect to have certified by a rester and the PMO, following testing contingency plans in place to deal with any problems, guidelines developed with the help ofoutside consultants. if they should occur. Please refer to Forward Looking We are currently evaluating whether we will have our Statements" on page 35. year 2000 testing independently certified. Phase 11 also includes identifying our major suppliers and developing Wlh Busine" contingency plans. We have identified our maior suppliers We established a year 2000 Program Management Oflice and are currently assessing their year 2000 readiness (PMO). Based on a work plan developed by the PMO, we through surveys. We plan to follow-up with our major have targeted the following six key areas: suppliers via interviews in early 1999. . digital systems (devie:s with embedded microprocessors Contingemy Planning such as power instrumentation, controls, and meters), Year 2000 operational contingency planning is underway. . telecommunicationssystems, Stafling and initial planning was completed in 1998. i major suppliers, Contingency plans are expected to be completed, including e . information technology applications (our customer, company-wide training, by September 1999. We are business, and human resources information systems), developing contingency plans using the contingency . computer hardware and software infrastructure, and guidelines issued by the Nuclear Energy Institute (which . contingencyplans. are endorsed by the NRC), the contingency guidelines issued by the North American Electric Reliability Council (NERC), and guidance from consultants. I l
We are also addressing the impact ofelectric power grid Costs problems that may occur outside ofour own electric system. In the following table, we show the breakdown ofour total We have staned year 2000 electric power grid impact costs between normal system replacements that will be planning through our various electric nterconnection capitalized (included in the Consolidated Balance Sheets) affiliations.The PJM interconnection has drafted year 2000 and the costs that will be expensed (included in our operational preparedness plans and restoration scenarios and Consolidated Statements ofIncome) through operations will continue to develop these plans during the first halfof and maintenance (O&M) cost. M aiso rhow the breakdown 1999 in cooperation with NERC.The NERC has started ofnon-incremental (previously included in our information monthly assessments of the electric utility industry to technology budget) and incremental O&M cost: communicate the readiness of the national electric grid for Actual Estimated year 2000.The NERC has scheduled two industry-wide cost costs Total tests for 1999. 19 % 1997 1998 1999 2000 Costs (k mdlwm) Through the Electric Power Research Institute (EPRI), an Total Cost $0.1 $1.7 $18.9 $19.5 $2.0 $42.2 industry-wide effort has been established to deal with year 2000 problems affecting digital systems and equipment Less: Capital c st 7.3 5.7 13.0 used by the nation's electric power companies. Under this O&M cost 0.1 1.7 11.6 13.8 2.0 29.2 effort, participating utilities are working together to assess Ec58: " "' specific vendors' system problems and test plans.The incremental assessment will be shared by the industry as a whole to O&M cost 0.1 1.7 4.6 7.0 1.0 14.4 facilitate year 2000 problem solving. Incremental a i BG E has joined the American Gas Association (AGA) O&M cost $- $ 7.0 $ 6.8 $1.0 $14.8 in an initiative similar to the one with EPRI to facilitate year e 2000 problem solving among gas utilities.The AGA has The costs incurred in 1996 and 1997 were for Phase I. initiated quarterly assessments of the gas utility industry to The costs incurred in 1998 were for Phases I and II. communicate the readiness ofits members for the year 2000. Costs incurred in 1999 and 2000 will be for Phases I and II. 8 li Current Srarm In 1998 and 1999, we had and expect to have the equivalent The most reasonably likely worst case scenario faced by our of approximately 110 full-time employees assigned to our 34 utility business is any interruption in providing electric and year 2000 pmject. gas service to our customers. We cannot predict the impact DismifedBusinesses of any interruption on our results ofoperanons, but the e g,mj,, impact could be material.The following table shows our Our diversified businesses have established year 2000 task esumate as of the date of this report of the percentage forces to address their year 2000 issues and are completing completed for Phases I and 11 and our expected year 2000 their initial assessments. As the initial assessments are readiness target dates for the six key areas: completed, the businesses have developed, and will be Year 2000 developing, action plans to prepare their systems for the readiness year 2000. Outside consultants have been retained by several Phase 1 Phase 11 target date ofour diversified businesses to help complete the initial Idtt = " " * **PM assessment and detailed analysis phase, and to assist in the Digital systems 98 % 50 % June 1999 resting, remediation, and certification phase of their year Telecommunications 2000 projects. The action plans developed are similar to those systems 100 % 90 % March 1999 used by our utility business, including a test certificadon Major suppliers 95 % 85 % June 1999 process. All systems are expected to be certified by December Information technology 1999. Our diversified businesses are evaluating whether they ) applications 100 % 55 % June 1999 will have their year 2000 testing independently certified. Computer hardware In evaluating their risks and estimating their costs, our diversified busine::ses utilized employees with expertise in and software infrastructure 100 % 80 % March 1999 each line ofbusiness to perform initial assessments. We Contingency plans 20% September 1999 believe our diversified businesses' employees are the most { The completion percentages listed above are reviewed by f miliar with their systems or equipment and therefore will our PMO in monthly status meetings with the personnel Provide a reliable estimate ofour risks and costs. responsible for each project and their supervision. Monthly progress is also mc,nitored by senior BG E management. J
I The progrrss ofour diversi6ed businesses' year 2000 businesses have two internet service providers and are projects are reviewed by their year 2000 task forces in contracting with a third provider for alternate routing to monthly stams meetings with the personnel responsible for critical Internet sites necessary to perform day-to-day each project and their supervision. Monthly progress is also business ftmetions. Both are currently assessing their monitored by senior management for each business and year 2000 issues. periodic updates are provided to BGE senior management. For our home products and commercial building systems Contingency Planning business, the most reasonably likely worst case scenarios Each ofour diversified businesses will develop contingency would be any interruption in billing customers or renewing plans, which are expected to be completed by December 1999. maintenance contracts.This business has substantially g completed the assessment and detailed analysis phase and The most reasonably likely worst case scenarios faced by has started the testing, remedianon, and certificanon phase our energy services businesses and our other diversified fits year 2000 project. businesses are discussed below. However, if any of these Other Diversified Businesses scenarios actually occurred, the impact is not expected to The most reasonably likely worst case scenarios for our be material to our consolidated financial resuhs, financial investments business would be a breakdown in the Enercy Services systems f the brokers or safekeeping banks which it uses to The most reasonablylikely worst case scenarios for any one trade, or the failure ofits investment managers' computer ofour power projects would be: programs that set investment strategy.This business is currently surveying and monitoring the year 2000 readiness shutdown Ohe plant's systems (most ofw hich can be ofits banks, brokers, and investment managers. manually overridden,, For our real estate and senior-h..vmg facih..nes business, the mability of the purchas. mg utdity to take the plant s = most reasonably likely worst case scenario is a failure of the n ohfuel. systerns that support the health, safety, and welfare ofresidents fl m the senior-Imng facihues. Personnel at each facihty are Personnel at each plant are currently assessing their involved in assessing their particular year 2000 issues. particular year 2000 issues and certain plants have started l g the testing, remediation, and certification phase of their year 2000 pmject. We estimate our total year 2000 costs for our power 1 projects business to be approximately $4.2 million, of A For our power marketing and trading business and our which 51.2 million is related to our year 2000 efforts for energy products and services business, the most reasonably our Panamanian electric distribution company.The tota! likely worst case scenario would be encountering any estimated year 2000 costs for our remaining diversified Internet access problems with trading partners, transmission businesses are approximately $2.8 million. service providers, independent operators, power exchanges, and various electronic bulletin boards. dach of these Amanting Standards issued and Adopted We discuss recently issued and adopted accounting standards in Note 1 on page 49. Forward Looking Statements We make statements in this report that are considered
availability, terms, and use ofcapital, forward looking statements within the mearsing of the nuclear and environmental issues, a
Securities Exchange Act of 1934. Sometimes these state-
weather, ments will contain words such as " believes," " expects,"
+ industry restructuring and cost recovery (including the " intends," " plans," and other similar words. These state-potential effect of stranded investments), ments are not guarantees ofour future performance and are
commodity price risk, and subject to risks, uncertainties, and other important factors

year 2000 readiness.
that could cause our actual performance or achievements to be materially different from those we project.These n. ks, Given these uncertainties, you should not place undue s reliance on these forward looking statements. Please see the uncertainties, and factors mclude, but are not h.. d to: mite other sections of this report and our other periodic reports
general economic, business, and regulatory conditions, filed with the SEC for more information on these factors.

energysupplyand demand, These ferward looking statements represent our estimates competition, and assumptions only as of the date of this report.
a
federal and state regulations,
Report of Management The management of the Company is responsible for the The Audit Committee of the Board of Directors, which consists information and representations in the Company's financial of five outside Directors, meets periodically with management, statements.The Company prepares the financial statements in internal auditors, and PricewaterhouseCoopers 1.LP to review accordance with generally accepted accounting principles based the activities ofeach in discharging their responsibilities. The upon available facts and circumstances and management's best internal audit staff and PricewaterhouseCoopers LLP have free estimates and judgments of known conditions. access to the Audit Committee. The Company maintains an accounting system and related system ofinternal controls designed to provide reasonable assurance that the financial records are accurate and that the Company's assets are protected. The Company's staffofinternal 1 auditors, which reports directly to the Chairman of the Board, f conducts periodic reviews to maintain the efTectiveness of g (j. internal control procedures. PricewaterhouseCoopers LLP, independent accountants, audit the financial statements and Christian H. Poindexter David A. Brune express their opinion on them.They perform their audit in Gainnan, Ibident GirfFinancialofca accordance with generally accepted auditing standards, andG,<f&uurin opcn s; e
a x
. Report ofIndependent Accountants To theShareholders of Baltimore Gas andElectric Com;>any We have audited the accompany ing consolidated balance sheets significant estimates made by management, as well as evaluating and statements ofcapitalization of Baltimore Gas and Electric the overall financial statement presentation. We believe that our Company and Subsidiaries as of December 31,1998 and 1997, audits provide a reasonable basis for our opinion. and the related consolidated statements ofincome, comprehensive In our opinion, the financial statements referred to above present income, cash flows, common shareholders, equity, and income I" Y' * *" **ter al respects, the consolidated financ. l position ia taxes foi each of the three years in the period ended December 31, of Baltimore G,as and Electnc Company and Subsidianes as of 1998.These financial statements are the responsibih.ty of the December 31,1998 and 1997, and the consolidated results of C,ompany's management. Our responsibiliry is to express an opinion on these financial statements based on our audits. jheir opeiations and the.ir cash flows for each of the three years in the period ended December 31,1998 m conformity with We conducted our audits in accordance with generally accepted generally accepted accounting principles. auditing standards. Those standards require that we plan and perform dye audit to obtain reasonable assurance about whether gg[ the financial statements are free of material misstatement. An i audit includes examining, on a test basis, evidence supporting PricewaterhouseCoopers LLP the amounts and disclosures in the financial statements. An Baltimore, Maryland audit also includes assessing the accour ting principles used and . January 15,1999
1 O e Consolidated Statements ofIncome eo,,_ecoso,onec,ec_oo,o,45 sio.o,ies lear EndedDecember31, 1998 1997 1996 i (In millions, exceptpershareamounts) Revenues Electric $2,219.2 $2,191.7 $2,208.7 Gas 449.4 521.6 517.3 Diversified businesses 689.5 594.3 427.2 Total revenues 3,358.1 3,307.6 3,153.2 Expenses Otteer fleen Interest end Ineeme Taxes Electric fuel and purchased energy 505.7 519.7 547.4 Disallowed replacement energy costs (see Note 10) 95.4 Gas purchased for resale 208.6 292.1 284.4 Operations 554.1 518.3 526.4 Maintenance 177.5 178.5 174.1 Diversified businesses-selling, general, and administrative 550.9 444.9 311.1 Write-downs of real estate investments (see Note 3) 23.7 70.8 Depreciation and amortization 377.1 342.9 330.2 Taxes other than income taxes 219.4 216.8 214.7 Total expenses other than interest and income taxes 2,617.0 2,584.0 2,483.7 Incense frene op. ix 741.1 723.6 669.5 3 Other insense (Empense) Trite-offofmerger costs (see Note 2) (57.9) l Allowance for equity funds used during construction 6.3 5.3 6.5 Equity in earnings of Safe Harbor Water Power Corporation 5.0 5.0 4.6 Net other expense (5.6) (5.2) (5.0) Total other income (expense) 5.7 (52.8) 6.1 Insense sofere laterest and Incense Tnmes 746.8 670.8 675.6 Interest Expense Interest charges 247.9 241.2 217.6 I Capitalized interest (3.6) (8.4) (15.6) Allowance for borrowed fimds used during construction (3.4) (2.8) (3.5) Net interest expense 240.9 230.0 198.5 Ine.me sofereInsemefames 505.9 440.8 477.1 Ineeme Taxes 178.2 158.0 166.3 Net Incense 327.7 282.8 310.8 Preferred and Preference Steek Dividends 21.8 28.7 38.5 Earnings Applicable to Comemon Stock $ 305.9 $ 254.1 $ 272.3 Average Shores of Commen Stock Oatstanding 148.5 147.7 147.6 Earnings Per Comaeon Shere end Earnings Per Commem Sleare-Assenslag Dilotlea $2.06 $1.72 $1.85 Consolidated Statements ofComprehensive Income Baltimore Gos and Electric Company and Subsidiaries I?arEndedDecember31, 1998 1997 1996 (In millions) Not Income $ 327.7 $ 282.8 $ 310.8 Other comprehensive gain /(loss), net of taxes 1.2 (0.8) 1.7 Comepreinensive Insense $ 328.9 $ 282.0 $ 312.5 See Notes to Consolidated FinancialStatements. Certainprior-year amounts haw been reclassifiedto conform u ith the currentyearspresentation.
Consolidated Balance Sheets u, ..o... ae-c.,. ,. oses.;4;,;.. At December 31. I998 1997 ([n millions) l Assets ca eass.es Cash and cash equivalents $ 173.7 $ 162.6 Accounts receivable (net ofallowance for uncollectibles of$20.3 and $24.1 respectively) 401.8 419.8 Trading securities 119.7 119.7 Fuelstocks 85.4 87.6 Materials and supplies 145.1 164.2 Prepaid taxes other than income taxes 68.8 65.2 Assets from energy trading activities 160.2 9.4 Other 21.4 27.4 Total current assets 1,176.1 1,055.9 Inveshments med Other Assets Real estate projects and investments 353.9 446.8 Power projects 656.8 451.7 a i Financialinvestments 198.0 196.5 l Nuclear decommissioning trust fund 181.4 145.3 Net pension asser 108.0 113.0 e Safe HarborWater Power Corporation 34.4 34.4 5 Senior-living facilities 93.5 62.2 3 Other 115.4 98.7 Totalinvestments and other assets 1,741.4 1.548.6 Utility Plant 3 Plant in service Electric 6,890.3 6,725.6 Gas 921.3 846.9 Common 552.8 554.1 Total plant in service 8,364.4 8,126.6 Accumulated depreciation (3,087.5) (2.843.4) Net plant in service 5,276.9 5,283.2 Construction work in progress 223.0 215.2 Nuclear fuel (net ofamortization) 132.5 127.9 Plant held for future use 24.3 25.2 Net utility plant 5,656.7 5.651.5 Defereed Charges Regulatory assets (net) 565.7 597.3 Other 55.1 46.7 ) Total deferred charges 620.8 644.0 Total Assets $9,195.0 $8,900.0 SeeNotes to ConsolidatedFinancialStatemenn. Certainprior-year amounn have been reclassifedto conprm with the currentyearspresentation. i J
Consolidated Balance Sheets u,,_.c... o ,,mc.,.,. asu.,,.. At December 31. 1998 1997 " " ~ Liabilitiesand Capitalization Ce m et uehalleles Short-term borrowings $ 316.1 Current portions oflong-term debt and preference stock 541.7 271.9 Accounts payable 249.6 203.0 Customer deposia 35.5 30.1 Accrued taxes 6.5 5.5 Acuuedinterest 58.6 58.4 Dividends declared 66.1 66.3 Accrued vacation costs 34.7 36.2 Liabilities from energy trading activities 126.2 8.6 Other 45.3 44.3 j Totalcurrent liabilities 1,164.2 1,040.4 Deferred Credles and other uebilities Deferred income taxes 1,309.1 1,294.9 = Postretirement uid postemployment benefi. s 217.0 185.5 I Deferred investment tax credits 118.0 126.6 Decommissioning of federal uranium enrichment facilities 30.8 34.9 8 Other 56.3 58.4 Total deferred credits and other liabilities 1,731.2 1,700.3 y I Capitalisation long-term debt 3,128.1 2,988.9 Redeemable preference stock 90.0 Preference stock not subject to mandatory redemption 190.0 210.0 Common shareholders' equity 2,981.5 2,870.4 Total capitalization 6,299.6 6,159.3 Communlennemis, Overentees, med Centlegencies-See Note le Total Liabilities and Capitalization 59,195.0 $8.900.0 See Notes to ConsolidatedFinancialStatements. Certainprior-year amounts han ban reclassifiedto conform with the wrrentyearspnsentation 4
Consolidated Statements of Cash Flows -_.m.. w-ec.-,.,om u., Dar EndedDecember31, 1998 1997 1996 (in mi ' ions) Cash Mews press operetles Activlties Net income $ 327.7 $ 282.8 $ 310.8 Adjustments to reconcile to net cash provided by operating activities i Depreciation and amortization 429.4 396.8 383.1 Deferredincome taxes 17.5 7.4 26.0 { Investment tax credit adjustments (8.8) (7.5) (7.6) Deferred fuelcosts (8.3) 18.3 0.5 Deferred conservation revenues 28.5 Disallowed replacement energy costs 95.4 Accrued pension and postemploymem benefits 41.6 (18.0) (13.8) Write-offofmerger costs 57.9 Write-downs of real estate investments 23.7 70.8 Allowance for equity funds used during construction (6.3) (5.3) (6.5) Equity in carnings of affiliates and joint ventures (net) (54.5) (42.5) (48.3) Changes in assets from energy trading activities (150.8) (9.4) Changes in liabilities from energy trading activities 117.6 8.6 Changes in other current assets 39.2 (54.7) (88.0) Changes in other current liabilities 56.1 42.6 (4.9) Other (3.3) (21.8) 26.7 Net caA pro ~ided by operating activities 820.8 726.0 701.9 2 Casti Mews Frome Investleg Activities Utility construction expenditures (including AFC) (339.4) (373.a (360.5) 8 Allowance for equity funds used during onstruction 6.3 5.L 6.5 7 Nuclear fuel expenditures (50.5) (43.6) (46.8) E Deferred conservation expenditures (16.2) (27.1) (31.4) Contributions to nuclear decommissioning trust fund (17.6) (17.6) (25.5) 40 Merger costs (20.9) (28.5) Purchases of marketable equity securities (33.3) (23.0) (32.7) I Sales of marketable equity securities 32.8 46.5 39.7 Other fmancialinvestments 14.6 (0.4) 7.1 Real estate projects and investments 21.5 24.2 (55.3) Power projects (l66.2) (44.3) (5.3) Other (77.0) (46.7) (34.3) Net cash used in investing activities (625.0) (520.8) (567.'I)) Cesis News Freas Monsing A-ttvleles Proceedsf w issuance of Short,e..worrowings 1,962.2 2,719.0 3,970.8 long-term debt 831.3 622.0 383.2 Common stock 51.8 3.7 Repayment ofshort-term borrowings (2,278.3) (2,736.1) (3,916.9) ) Reacquisition oflong-term debt (355.2) (343.3) (158.5) Redemption ofpreference stock (127.9) (104.5) (112.6) Common stock dividends paid (246.0) (239.2) (233.1) Preferred and preference stock dividends paid (21.0) (29.7) (37.0) Other (1.6) d.8 Net cash used in financing activities (l84.7) (109.3) (91.6) Not leeresse la Cash med Cesis Epivelents 11.1 95.9 43.3 Cash end Cash Epiveleets et Beginning of Year 162.6 66.7 23.4 _ Cash end Cash Egelveleets et End of Year $ 173.7 $ 162.6 $ 66.7 other Cash Mew leformeettee Cash paid during theyear for: Interest (net ofamounts capitalized) $ 236.7 $ 224.2 $ 193.6 income taxes $ 164.) $ 171.2 $ 160.1 Nessesh lowestleg med Meamslag Activities In 1998, Corporate Office PropertiesTrust (COPT) assumed approximately $62 million of Constellation Real Estate Group's (CREQ debt and issued to CREG 7.0 million common shares and 985,000 convertible preferred shares. In exchange, COIrr received 14 1 operating properties and two properties under development from CREG. SeeNotes to CoruolidatedFinancialStatemenn. Certainprior-yearamounn have been uclasufedto conform with thecurrentyearsprer tation. J
r Consolidated Statements ofCommon Shareholders' Equity Baltimore Gas and Electric Company and Subsidiories Accumulated Other Common Stock Retained Comprehensive 1btal han EndedDaember31,1998,1997, and1996 5 hares Amount Earnings Ineome Amount (Dollar amounts in millions, number ofshares in thousands) sehseee et Deseanber 31,1995 147,527 $1,425.8 $1,381 A 94.0 $2,811.2 Net income 310.8 310.8 Dividends declared Preferred and preference stock (38.5) (38.5) Common stock ($1.59 per share) (234.6) (234.6) Co.amon stock issued 140 3.7 3.7 Other 0.4 0.4 Net unrealized gain on sec::rities 2.6 2.6 Dekrred taxes on net unrealized gain on securities (0.9) (0.9) selease et Deeeenber 31,1994 147,667 1,429.9 1,419.1 5.7 2,854.7 = l Net income 282.8 282.8 E Dividends declared j Preference stock (28.7) (28.7) Common stock ($1.63 per share) (240.7) (240.7) e Other 3.1 3.1 8 Net unrealized loss on securities (1.2) (1.2) Deferred taxes on net unrealized loss en securities 0.4 0.4 g solemee et Deeeanber 31,1997 147,667 1,433.0 1,432.5 4.9 2,870.4 Net income 3277/ 327.7 Dividends declared Preference stock (21.8) (21.8) Common stock ($1.67 per share) (248.1) (248.1) Common stock issued 1,579 51.8 51.8 Other 0.3 0.3 Net unrealized gain on securities 1.8 1.8 Deferred taxes on net unrealized gain on securities (0.6) (0.6) solemee st Deeeenber 31,1993 149,246 $1,485.1 $1,490.3 $6.1 $2,981.5 Su Notes to ConsolidatedFina>nalStatemenn. Certainprior-year amounts have ban mia.,nfedta conform with the cunentyearsyresentation. I l 1 t
q Consolidated Statements of Capitalization --.m... .ec.-,. me..;.. At December 31, 1998 1997 (in millions) Leme senn sehe First Refunding Mongage Bonds ofBGE Floating rate series, due April 15,1999 $ 125.0 $ 125.0 8.40% Series, due October 15,1999 91.1 91.1 5%% Series,dueJuly 15,2000 125.0 125.0 8%% Series, due August 15,2001 122.3 122.3 7%% Series,dueJuly 1,2002 124.5 124.5 50% Installment Series, dueJuly 15,2002 9.1 9.8 6%% Series,due February 15,2003 124.8 124.8 6%% Series, dueJuly 1,2003 - 124.9 124.9 5%% Series,due April 15,2004 125.0 125.0 Remarketed floating rate series, due September l 2006 125.0 125.0 7W% Series, dueJanuary 15,2007 123.5 123.5 6%% Series,dueMarch 15,2008 124.9 124.9 7%% Series,due March 1,2023 125.0 125.0 7%% Series,due April 15,2023 84.1 100.0 'Ibral First Refunding Mortgage Bonds of BGE 1,554.2 1,570.8 i Otherlong-term debt of BGE e Medium-term notes, Series B 60.0 100.0 l Medium-term notes, Series C 116.0 143.0 3 Medium-term notes, Series D 215.0 225.0 i Medium-term notes, Series E 200.0 183.5 Medium-term notes, Series G 140.0 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, dueJuly 1, 2014 20.0 20.0 42 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 Variable rate pollution control loan, due June I,2027 8.8 8.8 Total otherlong-term debt ofBGE 1,000.8 921.3 Company obligated mandatorily redeemabb trust preferred securities ofsubsidiary trust holding solely 7.16% deferrable interest s bordinated debentures of the Company due June 30,2038 250.0 I eng-term debt ofdiversified businesses loans under revolving credit agreements 74.0 22.0 Mortgage and construction loans 8.69% mongage note, dueJanuary 28,1998 28.4 7.90% mortgage note, due September 12,2000 8.3 8.6 8.00% mortgage note, duejuly 31,2001 0.1 0.1 8.00% mortgage note, due October 30,2003 1.8 1.6 7.50% mongage note, due October 9,2005 9.7 I Variable rate mortgage notes and construction loans, due through 2004 149.5 93.5 7.357% mortgage note, due March 15,2009 5.1 5.5 9.65% n ortgage note, due February 1,2028 9.6 9.7 8.00% mortgage note,due November 1,2033 5.5 1.2 Unsecured notes 616.0 579.1 Tctal long-term debt ofdiversified businesses 870.2 759.4 Unamortized discount and premium (12.4) (13.7) Current portion oflong-term debt (534.7) (248.9) .l Tont long-term debt $3,128.1 $2,988.9 See &tes to ConsolidatedFinancialStatemena. continuedonpage43 Certainprior-yearamounts have been reclasss)edto confonn with the currentyearsprese itation. l
r I Consolidated Statements of Capitalization.,,; ,.e... oei.<,,;.c._,,,,,,es s.;e;.,1., At December 31, 1998 1997 (in millions) Prof.come. Seesk Cumulative, $ 100 par value,6,500,000 shares authorized Redeemable preference stock 7.50%,1986 Series,335,000 shares redeemed at $102.50 per share on July 17,1998; 30,000 sham redeemed at par on October 1,1998 $ 36.5 6.75%,1987 Series,30,000 shan s redeemed at par on April 1,1998; 395,000 shares redeemed at $ 102.25 on July 17,1998 42.5 8.625%,1990 Series,130,000 shares redeemed at par on July 1,1998 13.0 7.85%,1991 Series,70,000 shares outstanding and 140,000 shares redeemed at par onJuly 1,1998 7.0 21.0 Current portion ofredeemable preference stock (7.0) (23.0) Total redeemable preference stock 90.0 Preference stock not subject to mandatory redemption 7.78%,1973 Series,200,000 shares redeemed at $ 101 per share on July 17,1998 '0.0 7.125%,1993 Series,400,000 shares outstanding, not callable prior to July 1,2003 40.0 40.0 6.97%,1993 Series,500,000 shares outstanding, not callable prior to October 1,2003 50.0 50.0 6.70%,1993 Series,400,000 shares outstanding, not callable prior to January 1,2004 40.0 40.0 j 6.99%,1995 Series,600,000 shares outstanding, not callable prior to October 1,2005 60.0 60.0 m l Total preference stock not subject to mandatorv redemption 190.0 210.0 c.eu esher.h.id 'Eg=Mr Common stock without par value,175,000,000 shares authorized; I49,245.641 and a 147,667,114 shares issued and outstanding at December 31,1998 and I 1997, respectively. (At December 31,1998,166,893 shares were reserved 43 for the Employee Savings Plan and 2,372,531 shares were reserved for the ShareholderInvestment Plan.) 1,485.I 1,433.0 Retained earnings 1,490 3 1,432.5 Accumulated other comprehensive income 6.1 4.9 Total common shareholders' equity 2,981.5 2,870.4 feesi Capitallsselee $6,299.6 $6,159.3 See Notes to ConsolidatedFinancialStatements. Certainprior-yearamounts have been reclassifedto conform with the current yearspreserstation. l l
Consolidated Statements ofIncome Taxes. .,.o... o. c.-,.asa. ~., Mar EndedDecember31, 1998 1997 1996 (Dollaramountsin millions) lasease Temos Current $169.5 $158.1 $147.9 Deferred Change in tax effect of temporary difTerences 14.2 (1.0) 22.0 Change in income taxes recoverable through future rates 3.9 8.0 4.9 Deferred taxes credited (charged).o shareholders' equity (0.6) 0.4 (0.9) Deferred taxes charged to expense 17.5 7.4 26.0 Investment tax credit adjustments (8.8) (7.5) (7.6) Income taxes per Consolidated Statements ofIncome $178.2 $158.0 $166.3 Rosenellietlem of Isisease Tumes t=, _: d at 2:_:_ci Federal Rate to Totalineoane Temos income before income taxes $505.9 $440.8 $477.1 Statutory federal income tax rate 35% 35 % 35% Income taxes computed at ste.tutory federal rate 177.1 154.3 167.0 f Increases (decreases) in income taxes due to [ Depreciation differences not no:malized on regulated activities 13.6 13.9 12.6 Allowance for equity funds used during construction (2.2) (1.9) (2.3) { Amortization ofdeferred investment tax crulits (8.8) (7.5) (7.7) Tax credits flowed through t. tcome (0.3) (0.5) (0.5) Amortization ofdeferred tax rate difTerential on regulated activities (2.3) (2.3) (1.9) State income taxes 9.8 6.2 4.1 Other (8.7) (4.2) (5.0) .il Totalincome taxes $178.2 $158.0 $166.3 Effective federalincome tax rate 35.2 % 35.8 % 34.9 % At December 31, 1998 1997 (In millions) Deferred lesense Temoe Deferred tax liabilities Accelerated depreciation $1,009.9 $ 953.5 Allowance for futais used during construction 204.5 206.7 Income taxes recoverable through future rates 88.4 89.8 Deferred termination and postemployment costs 32.3 41.1 Deferred fuel costs 4.5 1.5 Leveraged leases 22.6 25.2 Percentage repair allowance 36.8 38.7 Conservation expenditures 18.9 24.5 Energy trading activities 44.0 2.4 Other 182.6 187.7 ) Total deferred tax liabilities 1,644.5 1,571,.,1 Deferred tax assets Accrued pension and postemployment benefit costs 54.3 37.6 Deferred investment tax credits 41.3 44.3 i Capitalized interest and overhead 46.6 44.5 Contributions in aid of construction 45.6 39.7 Nuclear decommissioningliability 22.8 20.8 Energy tradingactivities 30.9 1.4 Other 93.9 87.9 Total deferred tax assets 335.4 276.2 Deferred tax liability, net $ 1.309.1 $1,294.9 See Notes to ConsolidatedFinancialStatements. Certainyn'or-year amounts have been reclassifedto anform with ahe currentyearspresentation.
e I Otes <e cem eiiaetea rimemcieiste<ememt, Baltimore Gos and Uectric Company and Subsid.ories Noto. Significant Accounting Policies notece et oee Seeleone The CostMethod Baltimore Gas and Electric Company (BGE) is the parent We usually use the cost method ifwe hold less than a 20% company and conducts our primary business---the electric voting interest in an investment. Under the cost method, we and gas utility business.That business serves Baltimore report our investment at cost in our Consolidated Balance City and all or part of 10 Central Maryland counties. We Sheets.The only time we do not use this method is when we also conduct various diversified businesses in subsidiary can exerci e significant influena over the operations and companies. We describe our operating segments in Note 2 policies of the company. Ifwe have significant influence, on page 50. accounting rules require us to use the equity method. Ceasellaletlen Pelley Regeletles of Utility Besleese We use three different accounting methods to report our The Maryland Public Service Commission (Maryland PSC) investments in our subsidiaries or other companies: regulates our utility business. Generally, we use the same consolidation, the equity method, and the cost method. accounting policies and practices used by nonregulated gg companies for fmancial reporting under generally accepted We use consolidation when we own a majority of the voting acc untinS Principles. However, sometimes the Maryland stock of the subsidiary. This means the accounts ofour PSC orders an accounting treatrnent different from that subsidiaries are combined with our accounts. We eliminate used by nonregulated companies to determme the rates we intercompany balances and transactions when we charge our customers. When this happens, we must defer consolidate these accounts. Our consolidated financial certain utility expemes and income in our Consolidated statements include the accounts of: Balance Sheets as regulatory assets and liabihn,es. We have recorded these regulatory assets and liabihnes m our . BGE, Consolidated Balance Sheets in accordance with Statement . Constellation Enterprises, Inc. and Subsidiaries, of Financial Accounting Standards (SFAS) No. 71 j . District Chilled Water General Partnership AccountingfortheEfectsofCertain TypesofRegulation. We (ComfortLink), and summarize and discuss our regulatory assets and liabilities . BGE CapitalTrust 1 (See Note 7 on page 58). furtherin Note 4 on page 53. TheEquityMethod In 1997, the Financial Accounting Standards Board (FASB) We usually use the equity method to report investments, through :ts Emerging Issues Task Force (EITF) issued EITF corporate joint ventures, partnerships, and afliliated 97 4, Deregulation ofthe PricingofElectricity-hsues companies (including power projects) where we hold a Relatedio th< Application ofEASB Statements No. 71 and 20% to 50% voting intemst. Under the equity method, 101.The EITF concluded that a company should cease to we report: apply SFAS No. 71 when either legislation is passed or a our interest in the entity as an investment in our regulamry body issues an order that contains sufficient Consolidated Balance Sheets beginning on page 38, and detail to determme how the transition plan w 11 affect + our percentage share of the earnings from the entity in the deregulad portion of the busmess. Addmonally, a our Consolidated Statements of tncome on page 37 ' *P*"Y.w u ntime m rec gn eg are mesat,d liabihnes m the Consolidated Balance Sheets to the extent The only time we do not use this method is ifwe can that the transition plan provides for their recovery. exercise controi over the operations and policies of the company. If we have control, accounting rules require us At December 31,1998, we met the requirements ofSFAS No. 71. We discuss our transition proposal for electnc to use consolidan.on. unlity competition filed with the Maryland PSC m.the We report our investment in Safe Harbor Water Power " Competition and Response to Regulatory Change
Corporation (Safe Harbor) under the equity method. Safe section ofManagement's Discussion and Analysis Harboris a producer ofhydroelectric power. BGE owns on page 22.
two-thirds of Safe Harbor's total capital stock, including one-halfof the voting stock, an6 a two-thirds interest in its retained earnings.
i ) venhy movenees We also report two other items as " Electric fuel and pur-We record utility revenues in our Consolidated Statements chased energy" in our Consolidated Statements ofIncome: ofIncome when we provide service to customers. + amortization ofnudear fuel (described under" Utility Plant" later in this note). We amortize nudear fuel based on the energy produced over the life of the fuel. We pay Weincur costs for: quarterly fees to the Department of Energy for the future + the fuelwe use to generate electricity, disposal of spent nudear fuel, and accrue these fees based . purchases ofelectricity from others, and on the kilowatt-hours ofelectricity sold. We bill our . natural gas that we resell. customers for nudear fuel as described earlier in this n te, and These costs are shown in our Consolidated Statements ofIncome as " Electric fuel and purchased energy" and . am rtizati n fdeferred costsofdecomm,ss,on, gand i m " Gas purchased for ruale? We discuss each of these decontammanng the Department of Energy s uramum ennchment facihnes. We discuss these costs further m adybd a s Note 4 on page 54. Fuel Used to Generare Electricity andPurchases of E.xtended outages at Calvert Cliffs increase fuel costs and E h 'n' @ d t h s may msuk in fuel rate proceedings before the h!aryland Under the electric fuel rate clause set by the hiaryland PSC, we charge our electric customers for. PSC. In these proceedings, the hiaryland PSC would consider whether any poruon of the extra fuel costs should . the fuel we use to generate electricity (nudear fuel, be paid by BGE instead of passed on to customers. We coal, gas, or oil), and discuss the financial impact of past extended outages in
the na cost ofpurchases and sales ofelectricity Note 10 on page 63.
(primarily with other utilities). NaturalGas We charge the actual costs of these items to customers We charge our gas customers for the natural gas they purchase j with no profit to us.To do this, we must keep track of from us using " gas cost adjustment dauses" set by the what we spend and what we collect from customers under hiaryland PSC.These dauses operate similarly to the electric = ll the fuel rate in a given period. Usually these two amounts fuel rate dause described earlier in this note. However, are not the same because there is a difference between the effective October 1996, the hiaryland PSC approved a 16 time we spend the money and the time we collect it from modification of the gas cost adjustment dauses to pmvide a our customers. market based rates incentive mechanism. Under market based Under the electric fuel rate dause, we defer (indude as an f asi8 c mPared m a marketindex rates uractu Ic st S asset or liability in our Consolidated Balance Sheets and (a measum fthe market price ofgas m a given penod).The difference between our actual cost and the market mdex ts exdude from our Consolidated Statements ofIncome) the difference between our actual costs of fuel and energy and shared equally between shareholders and customers. what we collect from customers under the fuel rate in a given period. We either bill or refund our customers that differerce in the future. We discuss this further in Note 4 e engage m nsk management acuvmes m our gas business on page 54. and in our diversified businesses. We separately desenbe these activities for each business below. We calculate the electric fuel rate using three factors: Gas Business the mix ofgenerating plants we used over the last We use basis swaps in the winter months (November 24 months, through hiarch) to hedge our price risk associated with
the latest three-month average fuel cost for each natural ga: purchases under our market based rates generating tmit, and incentive mechanism. We also use fixed-to-floating and the net cost of purchases and sales ofelectricity over floating-to-fixed swaps to hedge our price risk associated a
the last 24 months. with our off-system gas sales.The fixed portion represents We may change the fuel rate only if the calculated rate is a Specific dollar amount that we will pay or receive and the more than 5% above or below the rate in effect.The fuel rate N ating Portion rep sent a fluctuating amount based on is affected most by the amount ofelectricity generated at our a Published index that we will receive or pay. Calvert Cliffs Nudear Power Plant (Calvert Cliffs) because the cost ofnuclear fuel is cheaper than coal, gas, or oil.
e Our gas business internal guidelines do not permit the Inwstment Tax Cn dits use ofswap agreements for any other purpose than to We have deferred the investment tax credit associated with hedge price risk. our regulated utility business in our Consolidated Balance We defer, as unrealized gams or losses, the net amount we Sheets.The investment tax credit is amortized evenly to are due (unrealized gains) or owe (unrealized losses) under income over the life ofeach property. We reduce income tax the swap agreements m our Consolidated Balance Sheets. expense in our Consolidated Statements ofIncome for the investment tax credit and other tax credits associated with When amounts are paid under the agreements, we report our diversified businesses, other than leveraged leases, the payments as gas costs in our Consolidated Statements ofincome. DefemdIncome Ta Assets andLiabilities We must report some ofour revenues and expenses differ-DiursigedBusinesses endy for our financial stateraents than we do for income tax Our subsidiary, Constellation Power Source, engages in purpoes. The tax effects of the -lifferer ces in these items are power marketing activities, which include trading electricity, reported as deferred income tax assets or liabilities in our other energy commodities, and related derivatives (such as Consolidated Balance Sheets. We measure the assets and futures, forwards, options, and swaps). Constellation Power liabilities using income tax races that are currently in effect. Source uses the mark-to-market method of accounting for its tradm. A portion ofour total deferred income tax liability relates to g actmues. our utility business, but has not been reflected m.the rates Under the mark-to-market method ofaccounting, we report: we charge our customers. We refer to this portion ofthe commodity positions and derivatives at fa.ir value as liability as " Income taxes recoverable or payable through future rates. We have recorded that portion of the net " Asset., from energy tradm.gacuvmes or,,Liabih..nes from energy tradm.gactmues mourConsolidated liability as a regulatory asset in our Consolidated Balance ..~ Balance Sheets, and Sheets. We discuss this further in Note 4 on page 54. 8 changes in fair value as components of" Diversified a Francloise Taxes busm.ess revenues m our Consolidated Statements e ofIncome. We pay Maryland pubik ervice company franchise tax instead ofstate income tax on our utility revenue from o Taxes sales in mao land. We include the franchise tax in " Taxes I We summarize our income taxes in our Consolidated other than income taxes" in our Consolidated Sta:ements 47 ofincome' Statements of f ncomeTaxes on page 44. As you read this section, it may be helpful to refer to those statements. Inventory Income TaxExpense We report the majority ofour fuel stocks and materials and We have two catepries ofincome taxes in our Consolidated supplies at average cost. Statements ofIncome--curre nt and deferred. We describe each of these below. no.1 astet. Projects anal investaients Our current income tax expenst consists solely of regular in Note 3 on page 52, we summarize the real estate projects tax less applicable tax credits. Our 1996 current income tax and investments that are in our Consolidated Balance expense amouat includes alternative reinimum tax credits Sheets.The projects and investments consist of: of $30 million.The alternative minimuro tax can be carried
land under develop ment in the Baltimore-forward indefinitely and used as tax credits in years when Washington corridor, our regular tax liability exceeds the alternative minimum

an entertainment, dininr and retail complex in tax liability. We do not have any remaining alternative Orlando, Florida, minimum tax credits.

a mixed-use planned-unit development, Our deferred income tax expense is equal to the changes senior-living facilities, and

begm.nmg m 1998, a 41.9% equity interest in m the net deferred income tax liability, excluding amounts charged or credited to common shareholders, Corporate Oflice Propern.es Trust, a real estate investment trust.
equity. Our deferred.mcome tax expense :s increased or reduced for changes to the net regulatory asset (described The costs incured to acquire and develop properties are later in this note) during the yar. included as part of the cost of the properties. n
i Evelemtion of Assets for leapelrment Utility Ment, Deptmletten, Ameertisetles, 5FAS No.121, AucuntingfortheImpairmentofLong-Litrd end ne<emmineleniog Assets andfor Long-LitedAssets to Be Disposed Of applles Utility Plant particular requirements to some ofour assets that have long Utility plant is the term we use to describe our utility lives. (Some examples are utility property and equipment business property and equipment that is in use, being held and real estate.) We determine if those assets are impaired for future use, or under construction. We summnize utility by comparing their undiscounted expected future cash plant in our Consolidated Balance Sheets. We report our flows to their carrying amount in our accounting records. utility plant at its original cost, which includes: We recognize an impairment loss if the undiscounted + matenal and labor, expected future cash 90ws are less than the carry.mg amount + contractor costs, + construction overhead costs (where applicable), and + an allowance for funds used during construction Finenelal Investaients and Trading Securities i (descn. bed later m th.is note). In Note 3 on page 52, we summarize the Gnancial invest-ments that are in our Consolidated Balance Sheets. We charge retired or otherwise-disposed-of utility plant to accumulated depreciation. S EAS No. I 15, Aucuntingfor Certain Imystments in Debt andEquity Suurities, applies particular requirements to We ow n an undivided interest in the Keystone and some ofour investments in debt and equity securities. We Conemaugh electric generating plants in Western report those investments at fair value, and we use specifc Pennsylvania, as well as in the transmission line that identification to determine their cost for computing transports the plants' output to the joint owners' service realized gains or losses. We classify these investments as territories. Our ownership interests in these plants are e either trading securities or available-for-sale securities, 20.99% in Keystone and 10.56% in Cc,nemaugh.These 8 which we describe separately below. We report investments ownership interests represented a net investment of that are not covered by SFAS No. I 15 at their cost. $152 million at December 31,1998 and 1997. We report these properties in the same accounts we use for our other a kda.ng suunties unh.ty plant (descn. bed above). =: Our d.iversified businesses classify some of the..ir mvestments in marketable equity securities and fmanciallimited Deprulation Erpense partnerships as trading securities. We include any Generally, we compute depreciation by applying composite, --48 unrealized gains or losses on these securities in straight-line rates (approved by the Maryland PSC) to the " Diversified business revenues" in our Consolidated average investment in clases of depreciable property. We 3 Statements ofincome, depreciate vehicles based on their estimated useful lives. Available-for-Sale Securities Amortization Erpense We classify our investments in the nuclear decommissioning Amortization is an accounting process ofreducing an trust fund as available-for-sale securities. We include any amount in our Consolidated Balance Sheets evenly over a unrealized pins or losses on the trust assets as a change in period of time. When we reduce amounts in our the decommissioning reserve. We describe the near Consolidated Balance Sheets, we increase amortization decommissioning trust and the reserve under the heading expense in our Consolidated Statements ofIncome. An " Decommissioning Costs" later in this note. amount is considered fidly amortized when it has been reduced to zero. in addition, our diversi6ed businesses classify some of their investments in marketable equiry securities as available-for-Duommissioning Costs I sale securities. We include any unrealized gains or losses on We must accumulate a reserve for the costs that we expect to these securities in " Accumulated other comprehensive incur in the future to decommission the radioactive portion income" in our Consolidated Statements ofCommon of Calvert Cliffs. We do this based on a sinking fund Shareholders' Equity on page 41 and in the Consolidated methodology.The Maryland PSC authorized us to record Statements of Capitalization on page 43. We aho include decommissioning expense based on a facility-speci6c cost our diversified businesses
portion of unrealized gains or estimate so we can accumulate a decommissioning reseive of losses on securities ofequity-method (described earlier in
$521.0 million in 1993 dollars by the end ofCalvert Clifts' this note) investees in our Consolidated Statements of service life in 2016, adjusted to reflect expected inflation. We Common Shareholders' Equity. have reported the decommissioning reserve in " Accumulated depreciation"in our Consolidated Balance Sheets.The total reserve was $244.0 million at December 31,1998 and $201.6 millior at December 31,1997. l
To fund the costs we expect to incur to decommission the Use of Asseenfing EWlaseks plant, we established an external decommissioning trust in Management makes estimates and assumptions when accordance with Nuclear Regulatory Commission (NRC) preparing fmancial statements under generally accepted regulations. We report the assets in the trust in " Nuclear accounting principles.These estimates and assumptions decommissioning trust fund"in our Consol dated Balance affect various matters, including: Sheets.The NRC requires utilities to provide financial assurance that they will accumulate sufficient funds :
our reported amounts ofassets and liabilities in our Consolidated Balance Sheets at the dares of the financial pay for the cost of nuclear decomrmssiomng based upon statements, either a generic NRC formula or a facility-specific decomrmssionmg cost esumate. W e use the facility-specific
, our disclosure ofcontingent assets and liabilities at the dates of the financial statements, and cost estimate for funding these costs and providing the required financial assurance, + our reported amounts of revenues and expenses in our Consolidated Statements of f ncome during the reporting periods. Allowenes for Feeds Used Dering Constreetloa and Capitellsed Interest These estimates involve judgments with respect to, among AllowanceforFunds UsedDuring Construction (AFC) other things, future economic factors that are diflicult to We fmance construction projects with borrowed funds and predict and are beyond management's control. As a result, equity funds. We are allowed by the Maryland PSC to record actual amounts could difTer from these estimates. the costs of these funds as part of the cost ofconstruction projects in our Consolidated Balance Sheets. We do this Reeleasifleetless through the AFC, which we calculate using a rate authorized We have reclassified certain prior-year amounts for by the Maryland PSC. We bill our customer for the AFC comparative purposes.These reclassifications did not plus a return after the utility plant is placed in service, affect consolidated net income for the years presented. j The AFC rates are 9.04% for gas plant,9.36% for common plant, and 9.40% for electnc plant. We compound AFC annually. We adopted SFAS No.130, Reporting Comprdunsive a Income, effecu.veJanuary 1,1998. Comprehensh c income a Capitalized /nterest includes net income plus all changes in shareholders' equity E Our diversified businesses capitalize interest costs incurred for the period, excluding shareholder transactions (some to finance real estate developed for internal use and certain examples are stock issuances and dividend payments). Ouc power projects. comprehensive income includes net income plus the effect of unrealized gains or losses on available-for-sale securities. Long Terms Delet We have presented comprehensive income in the We defer (include as an asser or liability in our Consolidated Consolidated Statements of Comprehensive Income, and Balance Sheets and exclude from our Consolidated accumulated other comprehensive income in the Statements ofIncome) all costs related to the issuance Consolidated Statements ofCommon Shareholders' Fxtuity oflong-term debt.These costs include underwriters' and in the Consolidated Statements ofCapitalization. s commissions, discounts or premiums, and other costs such as legal, accounting and regulatory fees, and printing costs, We adopted S FAS No.131, Disclosures about Segments We amortize these costs over the life of the debt. ofan Enterprise and RelatedInformation, effective January 1,1998. SFA No.131 establishes standards When we incur gains or losses on debt that we retire prior for the way that we report information about operating to maturity, we amortize those gains or losses over the segments in annual financial statements and requires remaining originallife of the debt that we report selected information about operating seg-ments in interim financial reports. SFAS No.131 also Casle Flows establishes standards for related disclosures about prod. For the purpo e of reporting our cash flows, we define cash ucts and services, geographic areas, and major customers. equivalents as highly liquid investments that mature in The adoption of this statement did not affect results of three months or less. operations or financial position, but did affect the disclosure of segment information. See Note 2 on page 50. s c
~ ) We adopted SFAS No.132, Employers' Disclosures about We do not expect the adoption of these statements to have a Pensions and Other /bstretirrment Benefts, efTective material impact on our financial results. January 1,1998. SFAS No.132 establishes standards for In June 1998, the FASB issued SEAS No.133, Accountingpr the way that we report our pension and postretirement Derivative Instruments andHedging Activities. SFAS No.133 benefits as well as requiring addinonal information on establishes the accounting and disclosure standards for changes m.the benefit obligations and fair values ofplan den.vative Gnancialinstruments and hedg.mg acavmes.. assets.The adopu.on of this statement did not affect results We must adopt the requirements of th.is standard beg.mnmg ofoperations or fmanc. l position, but did affect the ia with our financ. l statements for the quarter ending ia disclosure ofpens. ion and postretirement benefits March 31,2000. We have not determined the effects of information. See Note 5 on page 55. SFAS No.133 on our financial results. Aueenting Standards issued In November 1998, the EITF reached a consensus on EITF In March 1998, the American Institute of Certified Public 98-10, Anounting%rEnergy TradingandRiskManagement Accountants (AICPA) issued Statement of Position (SOP) Activities, requiring that energy trading activities be 98-1, Accountingprthe Costs ofComputerSoftwarr accounted for on a mark-to-market basis. We must Deulspedor Obtainedfor Internal (Ac. SOP 98-1 adopt the requirements of this consensus in our financial establishes the accounting for the costs ofcomputer statements for the year ending L)ecember 31,1999. We software developed or obtained for internal use. We must do not expect the adoption of this conansus to have a adopt the requirements of this statement in our fmancial material impact on our financial results. ) statements for the year ending December 31,1999. In April 1998, the AICPA issued SOP 98-5, Reportingon the Costs ofStart-up Activities. 50P 98-5 establishes the accounting for the costs ofstart-up activities. We must adopt the requirements of this statement in our fu.ancial statements for the year ending December 31,1999.
e 10 3
u.e. 2 Information by OperatingSegment We have three reportable operating segments: Electric, Gas, Our remaining diversified businesses: and Energy Services: + engagein financialinvestments,and + our Electnc business generates, purchases, and + develop, own, and manage real estate and senior-h..ymg facih..ues. sells electricity, + our Gas business purchases, transports, and sells natural These reportable segments are strategic businesses based gas, and principally upon regulations, products, and services that + our Energy Services businesses consist ofcertain require different technology and marketing strategies. diversified businesses that: The segments have the same accounting policies as those - engage in power projects, described in the summary of significant accounting policies - provide marketing and risk management services, in Note 1. We evaluate the performance of these segments - sell natural gas through mass marketing efforts, sell based on net income. We acco9nt for intersegment and service electric and gas appliances, heating and revenues using market prices. { air conditioning systems, and e.igage in home j improvements, and A summary ofinformation by operating segment is shown - provide cooling services to commercial customers on page 51. in Baltimore. ) 1
r Energy Other Unalkxated Electric Gas Services Diversi6ed Corporate Business Business Businesses Busineues items '> Ilindnations Consolidga f (In nillions) 1998 Unaffiliated revenues $2,219.2 $449.4 5 524.1 $165.4 5 - $3,358.1 Intersegment revenues 1.6 1.7 12.0 0.5 (15.8) Totai revenues 2,220.8 451.1 536.1 165.9 (15.8) 3,358.1 Depreciation and amortization 313.0 45.4 9.2 9.3 0.2 377.1 Equity in earnings ofequity-method investees
5.0 5.0 Net interest expense 164.9 23.6 16.0 38.6 (l.9)
(0.3) 240.9 Income tax expense (benefit) 146.6 13.4 34.1 (15.8) (0.1) 178.2 Net income (loss)(r> 278.7 28.8 43.4 (24.2) (0.1) 1.1 327.7 Segment assets 6,342.8 934.6 1,235.0 811.6 (14.0) (115.0) 9,195.0 Utility construction expenditures 279.0 60.4 339.4 1997 Unaflitiated revenues $2,191.7 $521.6 5 399.4 $194.9 $3,307.6 Intersegment revenues 0.3 0.6 9.7 (10.6) Total revenues 2,192.0 521.6 400.0 204.6 (106) 3,307.6 Depreciation and amortization 286.5 39.3 6.9 9.9 0.3 342.9 { Equity in earnings of equity-method investees f'> 5.0 5.0 Net interest expeue 160.7 20.3 10.1 32.5 6.4 230.0 I Income tax cxpense (benefit) 135.7 13.9 23.8 (13.5) (1.9) 158.0 l Net income (loss) f4 249.6 28.8 27.4 (21.1) (3.6) 1.7 282.8 Segment assets 6,404.4 907.7 700.9 885.4 10.7 (9.1) 8,900.0 l ~ Utility construction expenditures 278.7 94.5 373.2 1.L 1996 Unafliliated revenues $2,208.7 $517.3 $ 313.3 $113.9 5 $3,153.2 Intersegment revenues 0.3 1.0 5.8 (7.1) Total revenues 2,209.0 517.3 314.3 119.7 (7.1) 3,I53.2 Depreciation and amortization 279.3 37.8 3.2 9.6 0.3 330.2 Equity in earnings ofequity-method investees* 4.6 4.6 Net interest expense 150.6 17.5 7.2 24.4 (1.2) 198.5 Income tax expense (benefit) 121.7 16.0 23.8 8.9 (4.1) 166.3 Ner income (loss)M 230.9 33.9 30.6 16.8 (1.7) 0.3 310.8 Segment assets 6,466.5 8V.8 485.5 901.4 11.0 (l3.0) 8,578.2 Utility construction expenditures 262.5 98.0 360.5 (a) A Iwiding companypr our durrufed bwineun don not allocate ik itemspwsentedin sk sable ro our !ney %n and Oekr Domujedbwmesus. (b)Our Enery Servun andour Otkr Dnernfedbwineun mvedskar eqwry in es nings ofegwty-methodinmeres in their anaflaatedmenues. (c) Our Erwry %n bwineues mvrded$10.4 millionfor in sharr ofrarning in apartnership as dmwedin Mee3 anda $ 5.5 mdlwn wnu-ofofan ency uns n inmtment a ducussedin the "Orkr Enery % n'uctwot efAlarwgement) Dmwien andAn.dnis onpage 28. In addition. our Orkr Durnifedbwsnesses meJeda $15.4 mdlwn unse-down ofa oralestaseymject as dwuswd in Mu 3. (d Our Electric busineu orcordda $J7.5 mdlwn write-oforlaudto she serminaud meger wah Ibrom.u Eletnclbuer Company a discuedint tk ~n'nte Ofofhierger Cosa *wctwn ofAfanagement) Ducuuien andAnalyniu onpage 26 In addmen. our Other Durruf dbwineues wconteda $M 0 mdlwn wrste-</twn oftwo realnsate ynjeca a duswedin Mu3. (e) Our Elworic bwinen orcordeda $62.1 mdlwn wrise.ofofelatru wplacement erwry cosa as ducwsedin Moe 10. In addmon. eur Energy %n hwineues morded $I46 mdlwnpr in shaw ofearnings in apartnmhop and$I62 mdtwe ofuriu-of ofwsendpourrprojecn as ducuedan Mte 3. t m
s .t. 3 investments meet asteve Projects anel Investments Power Projects Real estate projects and investments held by Constellation Power projects held by our diversi6ed businesses consist of Real Estate Group (CREG), consist of the following: the following: Ai /Jentw 31. 1998 1997 As hmlw 3J. 1998 1997 (In mdliamI (in milliom) f i Properties under development $210.6 $220.8 Domestic Rental and operating properties East $ 39.8 $ 41.3 (net of accumulated depreciation) 38.9 225.6 West 426.2 377.7 li uity interest in real estate International l l investment trust 104.0 South America 21.6 18.3 Other real estate ventures 0.4 0.4 Central America 161 8 5.2 Total real estate p ojects Other 7.4 9.2 and investmen s $353.9 $446.8 Total power projects $656.8 $45] In 1998, CREG rec 3rded a $15.4 million after-tax wr;te-Our Domestic-West power projects include investments of down of the investment in Church Street Station-an $310.6 million in 1998 and $261.4 million in 1997 that entertainment, dining, and retail complex in Orlando, sell electricity in California under power purchase agree-a 1 lorida-which occurred because the fair value of the ments called " Interim Standard OJer No. 4" agreements. project has declined based upon recent competitive bids. We discuss these projects further in Note 10 on page 63. 8 CREG is attempting to sell this complex during 1999. In 1998, our power projects business recorded a $ 10.4 million in 1998, CREG entered into an agreement with Corporate after-tax gain for :ts share ofcarnings in a partnership.The i, Office PropertiesTrust (COIT), a real estate investment partnership recognized a gain on the sale ofits ownership r trust based in Philadelphia. interest in a power sales contract. Under the terms of the agreement, COPT assumed In 1996, our power projects bus: ness recorded a $14.6 million J2 approximately $62 million ofCREG's outstanding debt, after-tax gain for its share ofearnings in a partnership.The paid CREG approximately $22.8 million in cash, and partnership recognized a gain on the sale ofa power purchase 3 issued to CREG approximately 7.0 million common shares, agreement. In addition, our power projects business had the representing a 41.9% equity interest in COIT, and following write-offs: 985,000 convertible preferred shares. Each convertible a $7.0 million after-tax write-offoran investment in a preferred share y. lds 5.5%, per year, and is convertible after ie
S*
** wholente power grenerating projects two years into 1.8748 common shares. that sell electncity under California power purchase in exchange, COPT received 14 operating properties and agreements.These projects were written off because the two properties under development from CREG as well as expected future cash flow from the projects were less certain other assets, options, and first refusal rights. These than the investments in the projects, a $3.0 million after-tax write-offofdevelopment costs options and first
efusal rights are related to approximately a
91 acres ofidentified poperties which are adjacent to oper-for a coal-fired power project when development efforts ating properties being acquired by COIT.These options on the project were terminated, and a $6.2 million after-tax write-offof a portion of and first refusal rights have terms that range from 2-5 years. an invcStment in 8 8 I r Power project to reflect a IlyJuly 1999, COPT is expected to acquire one retail settlement with the project s lender. property from CREG for approximately $3.5 m. hon in d cash, unless that propeny is sold to another party prior to Financlel investments that time. Financial investments consist of the following: In 1997, CREG recorded the following write-downs ofreal As hm/w31. 1998 1997 estate projects: an malwm> a $ 14.1 million after-tax write-down of the investment Insurancec mp ny $102.5 5 88.8 a in Church Street Station-which occurred because Marketable equity securities 25.3 33.3 CREG decided to sell rather than keep the project, and Financiallimited partnerships 41.9 43.6 a $31.9 million after-tax write-down of the investment trver gedleases 28.3 30.8 { Tmal financial investments 5198.0 $196.5 in Piney Orchard-a mixed-use, planned-unit development-which occurred because the expected fumre cash flow from the project was less than CREG's investment in the project.
i 4 lovestments Closelflod as Avellaisle for Sele These tables induJ e $23.9 million in 1998 and $10.0 million We classify aur investments in the nudear decommissioning in 1997 ofunrealind net gains associated with the nudcar trust fund as available-for-sale. In addition, we dassify some decommissioning trust fund which are reflected as a change in ofour diversified businesses' marketable equity securities as the nudear decommissioning trust fund on the Consolidated available-for-sale.This means we do not expect to hold them Balance Sheets. to maturity and we do not consider them trading securities. Gross and net realized gains andlo ses on available-for-sale We show the fair values, gross unrealized gains and losses, securities were as follows: and amortized cost bases for all ofour available-for-sale securities, exdusive of$6.2 million in 1998 and $3.5 million Iwa Iw7 1w6 in 1997 ofunrealized net gains on securities ofequity-method (in mi&om) investees,in the following tables: Gross realized gains $ 4.2 $ 9.3 $ 4.3 Gross realized losses (0.7) (0.6) (0.2) Anwnuci Unnalual Unrealim) Fair Net realized gains $3.5 $ 8.7 $ 4.1 Ailbm/vr3/,199# Con his Gains tms %lue (In mi&om) Marketable Equity The U.S. Government agency obligations and state Securities $ 82.9 $24.2 $(0.4) $106.7 municipal bonds mature on the following schedule: U.S. Government agency 12.7 0.4 13.1 State mumcipal bonds 64.8 2.7 67.5 = Totals $160.4 $27.3 $(0.4) $187.3 (In m>&om) = Less than 1 year 1-5 years 33.5 Anwnim! Unnalimi Unrealimi Fair A t w lyr3/ 1997 con his cains t-s wlue 5-10 years 39.9 e g,3g More than 10 years 17.2 Marketable Equity 'I t I m turities fdebt securities $80.6 Securities $ / /.3 $12.0 $(0.5) $ 88.8 U.S. Covernment agency 14.9 0.2 15.1 A State municipal bonds 65.5 2.2 67.7 Totals $157.7 $14.4 $(0.5) $171.6 [ e4 Regtdatory Assets (net) As discussed in Note 1 on page 45, the Maryland PSC We summarize our regulatory assets and liabilities in the regulates our utility business. Generally, we use the same following table, and we discuss each of them separatJy accounting policies and pracuces used by nonregulated on page 54. companies for financial reporting under generally accepted accounting principles. However, sometimes the Maryland g, PSC orders an accounting treatment different from that y 3,g used by nonregulated companies to determine the rates we Inwme taxes rec verable charge our customers. When this happens, we must defer thmugh future rates (net) $252.6 $2563 certain utility expenses and incomc in our Consolidated Defened postretirement and balance Sheets as regulatory assets and liabilities. We then Postempk>yment benefit costs 90.0 96.4 record them in our Consolidated Statements ofIncome Deferred nudear expenditures 73.3 77.7 (using amortization) when we include them in the ra:es we Deferred conserva ;on expenditures 53.4 55.8 charge our customers. Deferred costs ofdecommissioning federal uranium enrichment facilities 38.5 42.4 Deferred environmental costs 33.4 38.8 Deferred fuelcosts (net) 12.7 4.4 Deferred termination benefit costs 2.2 21.0 l Other(net) 9.6 4.3 Total regulatory assets (net) $565.7 $597.3
Imem. Tews awevershi. Threeph reeere antes (net) During 1996, we exceeded our profit limit under the con-As described in Note 1 on page 47, incorne taxes recoverable servation surcharge. As a result, we deferred $28.5 million through future rates are the portion oi our net deferred ofour 1996 revenue from surcharge billings as a regulatory income tax liability that is applicaNe to our utility business, liability 1b correct the overage, we lowered the surcharge ~ but has not been reflected in the rates we charge our on our customers' bills over a 12-month period bs nning customers.These incomc taxes represent the tax effect of July 1997 through June 1998. temporary difTerences in depreciation and the illowance for equity funds used during constrt.ction, offset by differences Deferred Costs of Decomminioning Federal in deferred tax rates and deferred taxes on deferred inwstment Uranlem Enclehment Fallities tax credits. We amoitize these amounts as the temporary Deferred costs ofdecommissioning federal uranium I differences reverse. enrichment facilities are the unamortized portion ofour recuired contributions to a ftmd for decommissioning and l Deferred Pestretirement and Postemployment decontaminating the Department of Energy's uranium Penefit Costs enrichment facilities. We are required, along with other Deferred postretirement and postemployment benefit domestic utilities, by the Energy Policy Act of 1992 to make costs are the costs we recorded under SFAS No.106 contributions to the fund.The contributions are generally (for postretirement benefits) and SFAS No. I 12 (for payable over 15 years with escalation for inflation and are I postemployment benefits) in excess of the costs we included based upon the proportionate amount ofuranium enriched in the rates we charge our customers. We began amortizing by the Department of Energy for each utility. We are these costs over a 15-year period in 1998. We discuss these amortizing these costs over the contribution period as a costs funher in Note 5 on page 55. cost of fuel. We also discuss this in Note 1 on page 46. i e Deferred Neeieer Expenditures Deferred Environmental Costs l Deferred nuclear expenditures are the net unamortized Deferred environmental costs are the estimated costs of balance ofcertain operations and main enance costs at investigating and cleaning up contaminated sites we own. ej Calvert Clifts.These expenditures consist of: We discuss this further in Note 10 on page 62. We are j am rtizing $21.6 million of these costs (the amount we had l + costs incurred fmm 1979 through 1982 for inspecting incurred through October 1995) over a 10-year period m e and repairing seismic pipe supports, accordance w. h the Maryland PSC's November 1995 order. it
expenditures incurred from 1989 through 1994 54 associated with nonrecurring phases ofcertain nuclear Deferred reel Cats operat ons projects, and As described in Note 1 on page 46, deferred fuel costs are ea
+ expenditures incurred during 1990 for.mvestigating the difTerence between our actual costs of electnc fuel, net leaks in the pressurizer heater sleeves. purchases and sales ofelectncity, and natural gas and our We are amortizing these costs over the remF.ig life of the fuel rate revenues collected from customers. We reduce j plant in accordance with the Maryland P: -. orders. deferred fuel costs as we collect them from or refund them to our customers. J Deferred Conserveelen suponditeres 1 We show our deferred fuel costs m the following table: Deferred conservation expenditures include two components: Ar thember31. 1998 1997 operations costs (labor, materials, and indirect costs) associated with conservation programs approved by the Electric over-recovered fuel costs 5(11.5) $(19.0) Maryland PSC, which we are amortizing over periods Gas deferred fuel costs 202 23.4 of four to five years in accordance with the Maryland PSC's orders, and Deferred fuel costs (ner) 5 12.7 $ 4.4 + revenues we collected from customers in 1996 in excess Deferred Termination senefits 1 ofour prdit h..mit under the conservation surcharge. Deferred termination benefit costs are the net unai nortized The Maryland PSC allows us to collect from customers balance of the cost ofcertain termination benefits c ffered to money spent on conservation programs under a employees ofour regulated utility operations in 1962 and " conservation surcharge." However, under this surcharge 1993. We are amortizing these costs over a five-ye r period the Maryland PSC limits what our profit can be. If, at the in accordance with the Maryland PSC's ordm. end of the year, we have exceeded our allowed profit, we defer the excess in that year and we lower the amount of future surcharges to our customers to correct the amount ofoverage, plus interest.
u to 5 Pension, Postretirement, OtherPostemploynent, andEmployeeSavingPlan Benefts We offer pension, postretirement, other postemployment, For our diversified businesses, we expense all postretirement and employee savings plan benefits. We describe each of benefit costs. For our utility business, we accounted for the these separardy below. increase in annual postretirement benefit costs under two Maryland P5C rate orders: Pensten sements We sponsor several defined benefit pension plans for our
in an April 1993 rate order, the Maryland PSC employees. A defined benefit plan specifies the amount of allowed us to expense one-half and defer, as a regulatory benefits a plan participant is to receive using information asset (see Note 4 on page 54), the other halfof the g
about the participant. Our hrgest plan covers nearly all BGE employees and certain employees ofour subsid.. to our electnc and gas businesses, and ianes. Our other plans, which are not material in amount,
in a November 1995 rate order, the Maryland PSC provide supplemental benefits to certain key employees, allowed us to expense all of the increase in annual Our employees do not contribute to these plans.
postretirement benefit costs related to our gas business. Generally, we calculate the benefits under these plans Beginning in 1998, the Maryland PSC authorized us to: based on age, years of service, and pay. g ;,g g Sometimes we amend the plans retroactively.The: retro-benefit costs related to our electric business, and active plan amendments require us to recalculate benefits
amortize the regulatory asset for postretirement benefit I,
related to participants'past service. We amortize the change costs related to our electric and gas businesses over in the benefit costs from these plan amendments on a 15 years. straight-line basis over the average remaining service period { ofactive employees. OWigettees, Assets, and Poet'ed States We fund the plans by contributing at least the minimum We show the change in the benefit obligations, plan assets, a amount required under Internal Revenue Service regulations. and funded status of the pension and postretirement benefit We calculate the amount of funding using an actuarial plans.m the following table: method called the projected unit credit cost method.The Neretirement assets in all of the plans at December 31,1998 were mostly IVnsion Benefits Benefits marketable equity and fixed income recurities, and group 1998 1997 1998 1997 annmty contracts. Changein benefit obligation Pestretireesent fements iknefit obligation at We sponsor defined benefit postretirement health care and January 1, $ 902.0 $846.3 $320.3 $311.0 life insurance plans which cover nearly all BGE employees Servicecost 21.6 16.8 6.6 5.4 and certain employees of our subsidiaries. Generally, we Interest cost 63.0 61.3 23.4 21.8 calculate the benefits under these plans based on age, years Plan participants' ofservice, and pension benefit levels. We do not fund contributions 2.0 2.0 these plans. Actuarialloss (gain) 102.9 35.5 48.9 (2.1) I.'or nearly all of the health care plans, retirees make conin-Benefits paid (58.2) (57.9) (18.1) (17.8) butions to cover a portion of the plan costs. Con:n.but ons Benefit obligation at for employees who retire afterJune 30,1992 are calculated December 31, $ 1,031.3 $902.0 $383.1 $320.3 based on age and years ofservice. The amount of retiree Change in plan assets contributions increases based on expected increases in Fair value ofplan assets medical costs. For the life insurance plan, retirees do not at January 1, $912.3 $795.4 $ -$ make contributions to cover a portion of the plan costs. Actual return on plan Effective January 1,1993, we adopted SFAS No.106, assets 116.9 130.0 l Employers'AccountingforIbstn rirement Benefts Other Than Employet contribution 14.5 44.8 16.1 15.8 l Pensions.The adoption of that statement caused: Plan participants' contributions 2.0 2.0
a transition obligation, which we are amortizing over Benefits paid (58.2)
(57.9) (18.1) (17.8) 20 years, and Fair value of plan assets
an increase in annual postretirement benefit costs.
at December 31, $985.5 $912.3 $ -$ l
i lbstretirement Assemptions Pemion Benefits Iknc6ts We made the assumptions below to calculate our pension 1998 1997 1998 1997 and postretirement benefit cost and obligations: (In millwm) lbstretirement Fnnded status I emion Ikne6a P,enefits Funded status at a,,g,,,,,, 3993 3997 g993 i997 December 31, 5(45.8) $ 10.3 $(383.1) $(320.3) Discount rate 6.50%. 7.25 % 6.50 % 7.25 % ""*S***d " Expected return on actuarialloss 137.6 84.2 59.7 10.9 plan assets 9.00 9.00 N/A N/A Unrewgnned prior semce cost 16.9 19.4 Rate ofcompensation i increase 4.00 4.00 4.00 4.00 Unrecognized transmon We assumed the heal h care inflation rates to be: obligation - 159.3 170.6 t
in 1998,6.0% for both Medicare-eligible retirees and from adopnon of retirees not covered by Medicare, and SFAS No. 87 (0.7)
(0.9) + in 1999,7.5% for M:dicare-eligible retirees and 9.0% #****" ' ' *
Y
' * * ^ ben ft $108.0 $113.0 $(IM.1) $(138.8) After 1999, we assumed both inflation rates will decrease by Not Periodle Benem Cod 0.5% annually to a rate of 5.5% in the years 2003 and 2006. We show the components of net periodic pension benefit A 1% increase in the health care inflation rate from the cost in the following table: 8 assumed rates would increase the accumulated postretirement We EndedthrulvrJ1 1998 1997 __1996 benefit obligation by kpproximately $52.8 million as of (la ""l/i"*> December 31,1998 and would increase the combined l Components of net periodic service and interest costs of the postretirement benefit cost pension benefit cost by approximately $4.5 million annually. j Service cost $21.6 $16.8 $16.1 gg g g Interest cost 63.0 61.3 59.9 assumed rates would decrease the accumulated postretirement 56 Expected return on plan assets (72.1) (66.9) (62.8) benefit obh.ganon by approximately $41.7 million as of Amom.zat on of transition asset (0.2) (0.2) (0.2) December 31,1998 and would decrease the combined Amoruzation ofprior service cost 2.5 2.5 2.5 e e Pmtretinmen&ne& mt Recognized net actuarialloss 5.6 4.6 4.9 by approximately $3.5 mu, lion annually. Amount capitalized as construction cost (3.8) (2.5) (2.4) We Prov.de the following postemployment ben fits: be e c $16.6 $15.6 $18.0 . health and life insurance benefits to our employees and We show the components of net periodic postretirement certain employees ofour subsidiaries who are found to benefit cost in the following table: be disabled under our Disability Insurance Plan, and
income replacement payments for employees found to Nr End<dlkem/vr3/,
1998 1997 1996 be disabled before November 1995. (l'ayments for (In ad/ws) employees found to be disabled after that date are paid by Components of net periodic an insurance company, and the cost is paid by employees.) Postntinment benefit cat The liability for these benefits totaled $52.9 million Service cost $ 6.6 . $ 5.4 55.5 as of December 31,1998 and $45.4 million as of Interest cost 23.4 21.8 21.9 December 31,1997. Amortization of transition obligation i 1.4 11.4 11.4 Effective December 31,1993, we adopted SFAS No. I 12, j Recognized net actuarialloss 0.2 0.1 0.2 Employers'Aaountingfor Postemployment Benefts. We Amount capitalized as deferred, as a regulatory asset (see Note 4 on page 54), the construction cost (8.1) (7.6) (6.2) postemployment benefit liability attributable to our utility Amount deferred (7.2) (7.4) business as of December 31,1993, consistent with the Net periodic postretirement benefit cost $33.5 $23.9 $25.4
Maryland PSC's orders for postretirement benefits Esaploye. Senrings Plan Benefits (described earlier in this note). We began to amortize the We also sponsor a defmed contribution savings plan that is regulatory asset over 15 years beginning in 1998. The offered to all eligible BGE employees and certain employees Maryland PSC authorized us to reflect this change in our ofour subsidiaries. In a defmed contribution plan, the current electric and gas base rates to recover the higher costs benefits a participant is to receive result from regular in 1998. contributions to a participant account. Under this plan, we make matching contributions to participant accounts. W,e assumed the discount rate for other postemployment We made matching contributions to this plan of: benefits to be 4.5% m 1998 and 6.0% in 1997.
$10.1 million in 1998,

$8,5 million in 1997, and

$9.4 million in 1996.
ete 6 Short-7hrm Borrowings Sosnesary of Steert Tersen Borrowlmgs do not include unused revolving credit agreements of Our short-term borrowings may indude bank loans, $100 million at December 31,1998 and 1997 that are commercial paper notes, and bank lines ofcredit. Short. discussed in Note 7 on page 58. term borrowings mature within one year from the date of the financial statements. We pay commitmei.c fees to banks Constellation Enterprises, Inc. has a $135 million unsecured for providing us lines ofcredit. When we borrow under the revolving credit agreemer.t that matures December 20,1999, pmvide h.quidity for general corporate purposes mduding t lines ofcredit, we pay market interest races. financing requirements ofsubsidianes and to provide for the As of December 31,1998, we had no short-term issuance ofletters ofcredit to meet subsidiary business borrowings outstanding. As of December 31,1997, requirements. At December 31,1998, letters ofcredit we had $316.1 million outstanding consisting entirely totaling $2.3 million were issued under this credit facility, g of BGE commercial paper notes. I We had unused bank lines ofcredit supporting our com-mercial paper note: of 5113 million at December 31,1998 "' **'E '*#"E# # # and $231 million at December 31,1997,These amounts c mmercial paper n tes was 5.65% for the year ended December 31,1998 and 5.66% fcr 1997. n.w7 /^ Long-lbrm Debt long-term debt matures more than one year from the date BGE is required to make an annual sinking fund payment of the financial statements. We summarize our long-term each August I to the mortgage trustee.The amount of the debt in the Consolidated Statements ofCapitalization. payment is equal to 1 % of the highest principal amount of As you read this section, it may be helpful to refer to bonds outstanding during the preceding 12 months.The those statements. We discuss BGE's and our diversified trustee uses these funds to retire bonds from any series businesses'long-term debt separately below, through repurchases or calls for early redemption. liowever, the trustee cannot call the following bonds BSE's Long. Terme Delpt for early redemption: BGEs First RefundingMortgage Bonds
5 % Installment Series,

64% Series, due 2003 BGE's first refunding mortgage bonds are secured by a due2002

64% Series, due 2003 mortgage lien on nearly all of us assets, mcluding all utih.ty

8.40% Series, due 1999

SM% Series, due 2004 propernes and franchises and as subsidiary capital stock.
, 5 % Series,due 2000
7M% Se:ies, due 2007 BGE s subsidiary capital stock pledged under the mortgage

84% Series,due2001

64% Series, due 2008 is that of Safe liarbor Water Power Corporanon and

74% Series, due 2002 Constellanon Enterprises, Inc.
l
Hoklers of the Remarketed Floating Rate Series Due The interest paid on the Debentures, which the'liust will September 1,2006 have the option to require BG E to use to make distributions on tbcTOPrS, is included in repurchase their bonds at face value on September 1 of each " Interest Expense" in the Consolidated Statements of year. BGE is required to repurchase and retire at par any Income and is deductible for income tax purposes. bonds that are not remarketed or purchased by the remarketing agent. BG E also has the option to redeem monally guarantees the T.OPrS based BGE fully and uncond.. or its various obligations relating to the trust agreement, all or some of these bonds at fate value each September 1. . dentures, Debentures, and the preferred security m BGE' Other Long-Ierm Debt guarantee agreement. s We show the weighted-average interest rates and maturity Fhe Debentures are the only assets of thel. rust. I.he'l. rust is dates for BGE's fixed-rate medium-term notes outstanding l wholly owned by BG E because we own all the common I at December 31,1998 m the follow.mg table: /. secunnes of theliust that have general voting power. l i Weighted Average on l F.or the payment ofdividends and m.the event of h.qu dan. Ser.es luterest Race Maturity Dates " " #8 "'# '*" "'
I # '#"'# '
B 8.1090 2000-2006 C 7.34 1999-2003 D 6.66 2001-2006 m~~ ~' --- = { E 6.66 200620u "I G 6.08 ~008 A subsidiary ofConstellation Enterprises. Inc. has a Some of the medium-term notes include a "put option." $75 million unsecured revolving credit agreement that { These put options allow the holders to sell their notes back matures December 9,1999, to provide liquidity for general to BGE on the put option dates at a price equal to 100% of corporate purposes. Our diversified businesses pay a com-o [ the principal amount.The following is a summary of mitment fee based on the daily average of the unbormw ed j I medium-term notes with put options: portion of the commitment. At December 31,1998, our diversified businesses had $45.0 million outstanding under ( a Series E Notes Principal Put Option Dates this agreement. tln,m k m) l 6.75% due 2012 $60.0 June 2002 and 2007 Constellation Energy Source has a $10 million revolving 6.75%, due 2012 25.0 June 2001 and 2007 credit agreement that matures February 1,2000. At 53 6.73%, due 2012 25.0 June 2004 and 2007 December 31,1998, Constellation Energy Source had no outstanding borrowings under this agreement. BGE has $ 100 million of revolving cred.it agreements Constellan.on Energy Source pays a facility fee based on I wuh several banks that are available throubh 2000 to the tota.1 amount of the comm.innent. f 2001. At December 31,1998, BGE had no outstanding borrowings under these agreements.These banks charge ComfortUnk has a $50 million unsecured revolving credit us commitment fees based on the daily average of the agreement that matures September 26 2001. Under the unborrowed amount, and we pay market interest rates on terms of the agreement, ComfortLink ha., the option to any borrowings.These agreements also support BGE's obtain loans at various rates for terms up to nine months. commercial paper notes, as described in Note 6 on page 57. ComfortLink pays a facility fee on the total amount of the commitment. At December 31,1998. Comfortl. ink had Company ObligatedMandatord Redeemable Trust $29 million outstanding under this agreement. y PreferredSecuru..tses On June 15,1998, BG E Capitalliust I (Tiust), a Delaware Mortgage and Construction Loans business trust established by BG E, issued 10,000,000 Trust Our diversified businesses' mortgage and construcuon i Originated Preferred Securities (TOPrS) for $250 million loans have varying terms. The following mortgage notes ($25 liquidation amount per preferred security) with a require monthly principal and interest payments: l distribution rate of 7.16%.
7.90%, due.m 2000

7.357%, due m.2009 The Tiust used the net proceeds from the issuance of

8.00%,duein 2001

9.65%, due in 2028 common securities and the preferred securities to purchase The 8.00% mortgage note due in 2003 requires interest a series of 7.16% Defcnable Interest Subordinated payments until maturity.The variable rate mortgage notes Debentures dueJune 30,2038 (Debentures) from BG E in and construction loans require periodic payment ofprincipa2 the aggregate principal amount of $257.7 million with the and interest.The 8.00% mortgage note due in 2033, requires same terms as ihe TOPrS. TheTrust must redeem the interest payments initially then monthly principal and TOPrS at $25 per preferred security plus accrued but interest payments.
unpaid distributions when the Debentures are paid at maturity or upon any earlier redemption. BGE has the option to redeem the Debentures at any time on or after June 15, 2003 or at any time when certain tax or other events occur.
o l Unsec.nydNues At December 31,1998 BGEhadlong-termloans totaling l The umecured notes mature on the following schedule: $255.0 million that mature after 2002 (including $ 110 miuion 1 ofmedium-term notes discussed in this r.,te under "BGE's Other long 'Ibrm Debt) that lenden coud potentially ~ require us to repay early. Of this amount, $ 145.0 million could 7.30%,due April 22,1999 $ 90.0 potentially be repaid in 1999, $60.0 million in 2002, and 8.73%, due October 15,1999 15.0 $50.0 million thereafter. We have the abdity and intent to 7.125%, due hiarch I3,2000 15.0 refmance such dat by issuing medium-term notes or by 7.55%, due April 22,2000 35.0 borrowing under our revolving credit agreements, ifnecessary. 7.50%, due May 5,2000 139.0 7.43%,due September 9,2000 30.0 Weighted Average Interest Retes for 5.43%, due October 15,2000 5.0 verlebte note Debt 7.66%, due May 5,2001 135.0 Our weighted-average interest rates for variable rate debt 5.67%, due May 5,2001 152.0 ,,,c lbral unsecured notes at December 31,1998 $616.0 Dar /14d Durm/vr3/. 1998 1997 Meteeltles of Long-Terne Debt BGE All ofour long-term borrowings mature on the following Floating ratwries mortgage bonds 5.90 % 6.11% schedule (includes sinking fund requirements): Remarketed floating rate series m ngage bonds 5.70 5.75 DimiM Mar BGE Businesses Medium-term notes, Series D 5.74 5.78 a,,,,s,.; Pollution controlloan 3.48 3.63 1999 $ 334.5 $200.2 Port facilities loan 3.61 3.71 j 2000 252.6 273.4 Adjustable rate pollution controlloan 3.75 3.90 s 2001 195.2 362.6 Economic development loan 3.59 3.69 2002 154.0 1.5 Variable rate pollution controlloan 3.45 3.73 2003 284.3 8.9 DiwrsifedBusinesses Thereafter 1,584.4 23.6 loans under credit agreement 6.02 6.04 Totallong-term debt at Mortgage and construction loans 8.17 8.10 December 31.1998 $2,805.0 $870.2 2 ..to 8 Redeemable Preference Stock Priority For the payment ofdividends and in the event ofliquida-The redemptions were a combination of mandatory and tion of BG E, preference stock is ranked prior to common optional sinking fund redemptions and early redemptions. stock. All preference stock are ranked equally. The remaining 70,000 shares of the 7.85%,1991 series will be redeemed on July 1,1999 under mandatory sinking During 1998, BG E redeemed all remaining shares of the fund provisions. foUowing:
the 7.50%,1986 series,
+ the 6.75%,1987 series, and + the 8.625%,1990 series.
s .sese 9 'i Leases nere are two types ofleases-operating and capital. owegeles i. ease paymemes Capital leases qualify as sales or purchases ofproperty and We, as lessee, lease some facilities and equipment used in { are reported in the Condidated Balance Sheets. All our businesses.The lease agreements expire on various t other leases are operating leases and are reported in dates and have various renewal options. We expense all lease { the Consolidated Statements ofIncome. We present payments associated with our regulated utility operations. information about our operating leases below. Lease expense was: lesomlag 8,eese asetels
$10.5 million in 1998,
{ Some ofour diversified businesses, as landlords, lease retail
$9.5 million in 1997, and j
space to others.These operating leases expire over periods
$11.6 million in 1996.
ranging from one to 20 years, and have options to renew. At December 31,1998, we owed future minimum payments l At December 31,1998, our diversified businesses had for long-term, noncancelable, operating leases as follows: l property under operating leases w. h a net book value of it $32.4 million. At December 31.1998, tenants owed our Er diversified businesses future minimum rentals under gn= & m) operatingleases as follows: 1999 $ 6.7 2000 5.4 a 2001 4.1
l s
2002 3.4 1999 3 34 e 2003 2.2 2000 3.3 e 2001 3.1 g Total future minimum lease payments $27.3 g 2003 2.7 I ~ Thereafter 24.3 Total future minimum lease rentals $39.5 .fi 3 .see.10 Comminnents, Guarantees, and Contingencies ceammaeswees w, We have made substantial commitments in connection
g.,,us=>
with our utility construction program for future years. 1999 $ 61.9 In addition, our electric business has entered into two 2000 63.1 long-term contracts for the purchase ofelectric generating 2001 33.4 capacity and energy. The contracts expire in 2001 and 2002 12.3 2e13. We made payments under these contracts of: 2003 12.3 Thereafter 128.3
$70.7 million in 1998,

$65.6 million in 1997, and Total estimated future payments for

$64.1 million in 1996.
capacity and energy under long-term contracts $311.3 At December 31,1998, we estimate our future payments Some ofour diversified businesses have committed to con-for capacity and energy that we are obligated to buy under tribute additional capital and to make additional loans to these contracts to be: some affiliates, joint ventures, and partnerships in which they have an interest. At December 31,1998, the total amount ofinvestment requirements committed to by our diversified businesses was $19.9 million.
1 4 in March 1998, our power marketing and trading business, ply with this phase. We expect to meet the compliance Constellation Power Source, Inc. and Goldman, Sachs requirements through some combination ofinstalling flue Capital Partners 11 LP., an affiliate of Goldman, Sachs & gas desulfurization systems (scrubbers), switching fuels, Co., formed Orion Power Holdings, Inc. (Orion) to acqui e retiring some units, or allowance trading. electric generating plants in the United States and Canada. Constellanon Power Source owns a minority interest Title I addresses emissions of NOx.The hiaryland Department of the Environment (hide) issued NOx m Orion, and BGE has committed to contribute up t regulations which took effect June 1,1998. The h1DE $ 115 million in equity to Constellanon Power Source to regulations require major NOx sources to reduce NOx fund its investment in On.on. emissions up to 65% by hiay,1999. While we are already BGE and BGE Home Products & Services have agreements taking steps to control NOx emissions at our generating to sell on an ongoing basis an undivided interest in a desig-plants, we communicated to hide that we could not install nated pool ofcustomer receivables. Under the agreements, the required technology at our Brandon Shores plant in BGE can sell up to a total of $40 million, and BGE Home time to meet the hide's hiay,1999 deadline. On Products & Services can sell up to a total of $50 million. June 19,1998, we filed a lawsuit against hide in Under the terms of the agreements, the buyer of the receiv-Baltimore challenging these regulations. On ables has limited recourse against BGE and has no recourse February 9,1999, the Baltimore City Circuit Court against BGE Home Products & Services. BGE and BGE ordered the hide to reissue the regulations with a new Home Products & Services have recorded a reserve for compliance date, indicating it was impossible for utilities to credit losses. At December 31,1998, BGE had sold meet the Niay,1999 deadline. We do not anticipate that $33.6 million and BGE Home Products & Services had hide will appeal the court's decision. sold $45.3 million ofreceivables under these agreements. The EPA issued a final rule in September,1998 that f requires the reduction of NOx emissions up to 85% by BGE guarantees two-thirds ofcertam debt ofSafe Harbor 22 states (including hiaryland and Pennsylvania).The 22 states must subm.it plans to the EPA by September 1999 Water Power Corporation.The maximum amount ofour
Y *'" **** ' "#* '#9" # *#"
guarantee is $23 million. At December 31,1998, Safe
E Harbor Water Power Corporation had outstanding debt of Based on the hide and EPA regulations, we currently l
$23.6 million, ofwhich $ 15.7 million is guaranteed by BGE. estimate that the additional controls needed at our BG E has issued guarantees in an amount up to $ 162 million generating plants t meet the 65% NOx emission reduc-6_1_ related to credit facilities and contractual performance of ti n requirements willcost appr ximately $126 milhon.
S#"' *PP' *i"#lY certain ofits diversified subsidiaries. At December 31,1998, letters ofcredit totaling $2.3 million were issued under one
$21.5 million to meet the 65% reducuan requirements. imate the cost for the 85%. reduction require-ments at th. . of the credit facilities. is ame; however, these costs could be material. At December 31,1998, our diversified businesses had guar-anteed outstanding loans and letters ofcredit ofceitain power InJuly 1997, the EPA published National Ambient Air projects and real estate projects totaling $59.7 million. Our Quality Standards for very fine particulates and revised diversified businesses aho guarantee certain other borrowings standards for ozone attainment.These standards may ofurious power projects and real estate projects. require increased controls at our fossil generating plants m the future. We cannot estimate the cost of these.mcreased We assess the risk of material loss from these guarantees to controls at this time because the states, including hiaryland, be minimal. still need to determine what reductions, if any, in pollutants will be necessary to meet the federal standards. Environneentel Metters WieDu.posal 3,
'*' **# *E*"# #'
The Clean Air Act of 1990 contains two tides designed to reduce emissions ofsulfur dioxides and nitrogen oxides are c nsidered a potentially responsible party with respect to c eanup fcertain envir nmentallyc ntammated sites t (?!Ox) from electric generating stations-nle IV and Tidd' wned and operated by others. We cannot estimate the cleanup costs for all of these sites. We can, however, estimate Lle IV addresses emissions ofsulfur dioxides. Compliance that our current 15.42% share of the reasonably possible is required in two phases: cleanup costs at one of these sites, hietal Bank of America (a metal reclaimer in Philadelphia), could be as much as
PhaseIbecameeffecu.ve January 1,1995. We met the
$4.9 million higher than amounts we have recorded as a requirements of th.is phase by.mstalling flue gas desul-liability on our Consolidated Balance Sheets. This estimate furization systems (scrubbers), swn. hm.g fuels, and c is based on a Record of Decision issued by the EPA.The reunng some umts. cleanup costs for some of the remaining sites could be
Phase II must be implemented byJanuary 1,2000. We are significant, but we do not expect them to have a material currendy examining what actions we should take to com-effect on our financial position or results ofoperations.
i Also, we are coordinating investigation of several sites provided by an industry mutual insurance company.This where gas was manufactured in the past.The investigation amount can be reduced by up to $98.8 million per unit if of these sites includes reviewing possible actions to remove an outage at both units of the plant is caused by a single coal tar. In late December 1996, we signed a consent order insured physical damage loss. If accidents at any insured with the MDE that requires us to implement rem-dial plants cause a shortfall of funds at the industry mutual action plans for contamination at and around the Spring insurance company, all policyholders could be assessed, Gardens site, h>cated in Baltimore, Maryland. We with our share being up to $23.2 million. submitted the required remedial action plans and they have been approved by the MDE. Based on the in addition we, as well as others, could be charged for a remedial action plans, the costs we consider to be poruon or any third party daims associated with a nudear probable to remedy the contamination are estimated t mcident at any commercial nudear puver plant m the total $47 milhon m nommal dollars (includmg mflanon). country. At the date of this repon, the limit for third party claims from a nudear.mcident is $9.71 bilh.on under the We have recorded these costs as a liability on our provisions of the Pn.ce Anderson Act. If third pany daims Consolidated Balance Sheets and have deferred these costs, net of accumulated amortization and amounts we exceed $200 million (the amount of pn. mary msurance), recovered from insurance companies, as a regulatory asset. our share of the total liability for third pany daims could be up to $176.2 million per incident.That amount would be We discuss this funher m Note 4 on page 54.Through Payable at a rate of $20 million per year. l December 31,1998, we have spent approximately l $32 million for remediation at this site. Insurancefor WorkerRadiation Claims We are also required by accounting rules to disclose addi. A8 an Perator of a commercial nudear power plant in the ( Umted States, we are required to purchase msurance to tional ccsts we consider to be less likely than probable c ver rad anon mjury claims ofcertam nudcar workers. On costs, but still " reasonably possible" of being incurred at I these sites. Because of the results ofstudies at these sites, January 1,1998, a new insurance policy became effecuve it is reasonably possible that these additional costs could r au Perators requiring coverage for current operations. Waivmg the n,ght to make addmonal claims undet the old a exceed the arnount we recognized by approximately E p licywas a c ndm..on for acceptance under the new policy. [ $14 million in nominal dollars ($7 million in current We descnbe both the old and new pohcies below. dollars, plus the impact ofinflation at 3.1% over a period ofup to 36 years). + BGE nudear worker claims reported on or after 62, January 1,1998 are covered by a new insurance policy Nesleer 8-with an annualindustry aggregate limit of $200 million If there were an accident or an extended outage at either for radiation injury claims against all those insured by unit of the Calvert Cliffs Nuclear Power Plant (Calvert this policy. Cliffs), it could have a substantial adverse financial effect
All nudcar worker daims reponed prior toJanuary 1,1998 on BGE.The primary contingencies that would result are still covered by the old insurance policies. Insureds from an incident at Calvert Cliffs could indude:
under the old policies, with no current operations, are not + physical damage to the plant. required to purchase the new policy described above, and maystillmake da.ims against the old poh.. for the next cies + recoverabih.ty ofreplacement power costs, and nineyears.Ifrad..iauon mjury claims under these old poh.. tability to third parties for property damage and +o i old M & I "N"* assessed, with our share being up to $6.3 million. We have insurance policies that cover these contingencies, but the policies have certain exclusions. Furthermore, the ifclaims under these polices exceed the coverage h..mits, the costs that could result from a covered major accident or a Provisions ofthe Pnce Anderson Act (discussed above) covered extended outage at either of the Calvert Cliffs un.ts W uld 2PP Y-l could exceed our insurance coverage limits. Insurancefor Calvert Clifs and ThiniParty Claims By law, we are allowed to recover our cost of electric fuel as { For physical damage to Calven Cliffs, we have $2.75 billion long as the Maryland PSC finds that, among other things, of property insurance from an industry mutual insurance we have kept the productive capacity ofour generating company. Ifan outage at either of the two units at Calven plants at a reasonable level.To d a this, the Maryland PSC Cliffs is caused by an insured physical damage loss and lasts will perform an evaluation ofeach outage (other than more than 17 weeks, we have insurance coverage for regular maintenance outages) at our generating plants. j replacement power costs up to $494.2 million per unit, The evaluation will determine ifwe used all reasonable j and cost-effective maintenance and operating control l procedures to try to prevent the outage. q
I I %e hiaryland PSC, under the Generating Unit Ibrforrmnce invested in 15 pmjects that sell electrichy in Califo-Program, measures annually whether we have maintained the under power purchase agreements called "Interin. miard l productive capacity ofour generating plants at reasonable Offer No. 4" agreements. In 1998, carnings from these levels.'Ib do this, the program uses a system-wide generating projects were $41.3 million, or $.28 per share. l t performance target and an individual perfbrmance target for l Under these agreements, the projects supply electncuy to each base load generating unit. In fuel rate hearings, actual . 'I '*" P '" #' "' generating performance adjusted for plarmed outages will be compared first to the system-wide target. . a fixed rate for capacity and energy for the first to if that target is met, it should mean that the requirements years of the agreements, and of hiaryland law have been met. If the system-wide target is
a fixed rate for capacity plus a variable rate for energy based on the uu.h...ues avoided cost for the remanung I
not met, each um.,t s adj.usted actual generating performance term of the agreements. l wdl be compared to us mdividual performance target to determine if the requirements of hiaryland law have been Generally, a " capacity rate"is paid to a power plant for its met and, if not, to determine the basis for possibly imposing availability to supply electricity, and an " energy rate" is paid l a penalry on BG E. Even if we meet these targets, parties to for the electricity actually generated. " Avoided cost" I fuel race hearings may still question whether we used all generally is the cost of a utility's cheapest next-available l reasonable and cost. effective procedures to try to prevent an source afgeneration to service the demands on its system. outage. If the hiaryland PSC decides we were deficient in We use the term transition period to descn.be the time some way, the hiaryland PSC, m ty not allow us to recover frame when the 10-year periods for fixed energy rates the cost of replacement energy. expire for these 15 power generation projects and they The two units at Calvert Cliffs use the cheapest fuel. As a begin supplying electricity at variable rates. The transition resuh, the costs of replacement energy associated with period for some of the projects began in 1996 and will outages at these units can be significant. We cannot estimate continue for the remaining projects through 2000. At the the amount of replacement energy costs that could be date of this report, eight projects had already transitioned challenged or disallowed in future fuel rate proceedings, to variable rates and seven other projects will transition in but such amounts could be material. 1999 and 2000. s During 1989 through 1991 we had extended outages at The projects that have already transitioned to ariable rates Calvert Clifts.These outages drove up fuel costs, and have had lower revenues under variable rates than they did 61 resuhed in fuel rate proceedings before the hiaryland PSC under fixed rates. However, we have not yet experienced for several years. In these proceedings, the hiaryland PSC total lower earnings from the California projects because considered whether any portion of the extra fuel costs should the combined revenues from the remaining projects, which be charged to BG E instead of passed on to customers. continue to supply electricity at fixed rates, are high enough to ofTset the lower revenues from the variable-rate projects. i In December 1996, we settled the proceedings by agree.mg When the remaining projects transition to variable rates, we not to bill our customers for $118 milh.on ofelectnc replace-expect the revenues from those projects also to be lower ment energy costs associated w. h these outages. All costs u than they are under fixed rates. associated wu. h the outages m excess of $ 118 million have already been collected from customers through the fuel rate. Our power projects business is pursuing ahernatives for in 1990, we wrote ofr$35 million of these costs. In 1996, w-some of these power generation projects including: wrote ofTthe remaining $83 million plus $5.6 million of = repowenng the projects to reduce operating costs, related financing charges.The 1996 wn.te-ofTs, together, changing fuels to reduce operating costs, a reduced after-tax earnings by $57.6 million. renegotiating the power purchase agreements to a Also in 1996, we wrote oft 56.8 million of fuel costs related improve the terms, restructuring financings to improve the financing to earlier outages that were disallowed by the hiaryland PSC.This write-ofTreduced 1996 after-tax earnings by terms, and selling its ownership interests in the projects. $4.5 million. We have reported all of the 1996 write-ofTs as " Disallowed The California projects that make the highest revenues will replacement energy costs" in our Consolidated Statements transition to variable rates in 1999 and 2000.The projects
ofincome, which transition in 1999 contributed $10.7 million. or
$.07 per share to 1998 earnings, while those changing over in Califeenlo Pewer Purdose Agreements 2000 contributed $24.0 million, or $.16 per share to 1998 Constellation Power, Inc. and sabsidiaries and earnings. We expect earnings to ultimately decrease by similar Constellation Investments, Inc. (whose power projects are amounts beginning in 1999 as these projects transition. managed by Constellation Power) have $310.6 million l l l l
i const.lletlen a..I heet. except for Church Street Station which we intend to sell as hiost of Constellation Real Estate Group's (CREG) real discussed in Note 3. hianagement evaluates strategies for all estate projects are in the Baltimore-Washington corridor. its businesses, including real estate, on an ongoing basis. We The area has had a surplus of available land in recent years anticipate that competing demands for our financial and as a result these projects have been economically hurt. resources and changes in the utility industry will cause us to CREG's real estate projects have continued to incur carrying ev luate thomughly all diversified business strategies on costs and depreciation over the years. Additionally, CREG a regular basis so we use capital and other resources m a manner that is most beneficial. has been charging interest payments to expense rather than capitalizing them for some undeveloped land where It may be helpftd for you to understand when we are development activities have stopped. These carrying costs, required, by accounting rules, to write down the value of a depreciation, and interest expenses have decreased earnings real estate project to market value. A write-down is required and are expected to continue to do so. in either of two cases.The first is ifwe change our intent Cash flow from real estate operations has not been enough about a project from an intent to hold to an intent to sell to make the monthly loan payments on some of these and the market value of that project is below book value. projects. Cash shortfalls have been covered by cash obtained The second is if the expected future cash flow from the from the cash flows of, or additional borrowings by, other pmject is less than the investment in the project. We discuss diversified subsidiaries. ouneal estate pmjects and inwstments further m Note 3 on page 52. We consider market demand interest races, the availability of financing, and the strength of the economy in general Y.or 2000 Pr.lect when making decisions about our real estate projects. Ifwe We have not experienced any significant year 2000 problems a i were to decide to sell our real estate projects, we could have to date and we do not expect any significant problems to write-downs. In addition, if we were to sell our remaining impair our operations as we transition to the new century. real estate projects in the current market, we would have i Iowever, due to the magnitude and complexity of the year 't losses which could be material, although the amount of the 2000 issue, even the most conscientious efforts cannot 5 losses is hard to predict. guarantee that every problem will be found and corrected prior to January 1, 2000. We discuss our year 2000 project I hianagement's current real estate strategy is to hold each real further in the # Year 2000 Readiness Disclosure" section of estate project until we can realize a reasonable value for it, hianagement's Discussion and Analysis on page 33. 3. n.e.1 1 Fair %Iue ofFinancialInstrainents The fair value of a financial instrument represents the We show the carrying amounts and fair values of financial amount at which the instrument could be exchanged in a instruments included in our Consolidated Balance Sheets current transaction between willing parties, other than in a in the following table. forced sale or liquidation. Significant differences can occur between the fair value and carrying amount of financial carrying rair carrying Fair instruments that are recorded at historical amounts. We Arnount Value Amount Value used the following methods and assumptions in estimating u,,,,, A,,w fair value disclosures for financial instruments. Investments and ther assets for which it is:
Cash and cash equivalents, net accounts receivable, other Practicable to current assets, certain current liabilities, short-term estimate fair value 5 213.0 5 213.0 $ 197.4 $ 198.8 borrowings, current portions oflong-term debt and Not practicable to preference stock and certain deferred credits and other estimate fair value 56.5 N/A 57.5 N/A liabilities:The amounts reported in the Consolidated Fixed-rate long-term Balance Sheets apprnximate fair value.
debt 2,95L7 3,076.6 2,637.5 2,7l8.4
Investments and other assets where it was practicable to Redeemable preference estimate fair value: The fair value is based on quoted stock 7.0 7.2 113.0 116.5 market prices where available.

Fixed-rate long-term debt, and redeemable preference
{ stock: The fair value is based on quoted market prices l where available or by discounting remaining cash flows at l current market rates.The carrying amount of variable-l rate long-term debt approximates fair value. l
1 1 s e I h was not practicable to estimate the fair value ofinvestments The investments in solar powered energy production facility held by our diversi6ed businesses in: pannerships totaled $ 10.9 million at December 31,1998 = several fmancial partnerships that invest in nonpublic and 1997, representing miership interests up to 13% debt and equity securities, .The total assets of all of these pannerships totakd several partnerships that own solar powered energy $41.5 million at December 31,1997 (which is the latest producuon facihnes, and information available). + a company involved in developing intemational power projects with a carrymg amount afS3.7 milhon at December 31,1998 and $3.0 million at December 31,1997. It was n t pract cable to determme the fair value ofcertam loan guarantees of BG E and its diversiGed businesses. This is because the timing and anmunt ofcash flo,vs from BG E guaranteed outstanding debt and other obligations these investments are difDeult to predict. We report these totaling $ 18.0 million at December 31,1998 and investments at their original cost in our Consolidated $20 million at December 31,1997. Our diversi6ed busi-Balance Sheets. nesses guaranteed outstanding debt totaling $59.7 million The investments in financial partnerships totaled at December 31,1998 and $43 million at December 31, t 997' W# d " ' *"'i'i '** 'h*' *# *i1l "##d '" f""J $41.9 million at December 31,1998 and $43.6 million E at December 31,1997, representing ownership interests these guarantees. up to 10% The total assets of all of these partnerships totaled $5.8 billion at December 31,1997 (which is the latest information available). E .i; ... 12 Quarteriy FinancialData (Unaudited) .~ Our quanerly financial information has not been audited but, in management's opinion, includes all adjustments necessary for a fair presentation. Our utility business is seasonal in nature with the peah sales periods generally occurring during the fd., summer and winter months. Accordingly, comparisons among quaners of a year may not represent overall trends and changes in operations. j 1998 Quarterly Data 1997 Quarterly Data Fmnp Em np Emmnp fanp Imome AppI4 N Shm imonw AppluNe bsha Fmm Net mComnsm dCommon Fmm Nei mcenxm dConmmn Rcwmues Omsn inmme hk hk Revenues operma Inamw hk hk (It atilww. exeptper slurr amounts) (In mallwm. exceptperskerv entounn) Quaner Ended: Quarter Endeu: March 31 $ 866.1 $183.4 $ 80.2 $ 74.4 $0.50 March 31 $ 887.7 $163.9 $ 72.1 $ 64.2 $0.43 June 30 767.6 156.2 63.2 57.4 0.39 June 30 746.4 78.8 15.0 7.1 0.05 September 30 934.0 320.4 167.7 160.9 1.08 September 30 860.8 321.0 171.4 164.4 1.11 December 31 790.4 81.1 16.6 13.2 0.09 December 31 812.7 159.9 24.3 18.4 0.12 Vear Ended: Year Ended: December 31 $3,358.1 $741.1 $327.7 $305.9 $2.06 December 31 $3.307.6 $723.6 $282.8 $254.1 $1.72 Our third quaner results include a $ 10.4 million after-tax Our first quarter results include a $ 12.0 million after-tax gain for earnings in a partnership (see Note 3). write-down of a real estate project (see Note 3). Our fourth quarter resuhs include: Our second quarter results include a $31.9 million after-tax . a $15.4 million after-tax write-offof a real estate invest-write-down ofa real estate project (see Note 3). ment (see Note 3), and Our founh quarter results indude: + a $5.5 million after-tax write-offofan energy services investment. (See the Other Energy Semces secn,on of , a $37.5 million after-tax write-offof merger costs (see Note 2), and Management s Discussion and Analysis on page 28). j
a $2.1 million after-tax wnte-down ofa real estate project (see Note 3).
The sum ofthe quarterly earningsper share amounts may not equalthe totalfor theyear due to the e(Rcts ofrounding. i __J
t e BG E Board of Directors Bea;me,.O...nd El.c,;c Cem,.,ond Ses 18;.,;.. CHRISTIAN H. H. FURLONG BALDWIN DOUGLAS L, BECKER 8EVERLY 8. 8YRON J. OWEN COLE Chairman and Chief 1%ident and Co-Chief Former Congressuvman. Ihmtor, fine Afaryland Chairman, nnidens hecutiw Offiar. Secutin Opcer, Sylvan U.S. Ilouse of Bamvry: Guairman. and Chiefhuurwe yg,,ca,,gge ya,,;,ha,e, Lemino ysterous. Iru. RrPresentatives First NationalBank of s Ofcy, BCE c,77,, ration i mg Age 66; elected 1993 Alaryland 7not l Age 60; elected 1988 Age 67; elected 1988 Committee Age 69; elected 1977 a DAN A. COLUSSY EDWARD A. CROOKE JAMES R. CURTISS, ESQ. JEROME W. GECKLE DR. FREEMAN A. HRA80W5K1, III i Former Chairman, l' ice Chairman, BGE;
Partner, Retured Chairman, hesident and Onef Chairman. IWsident u"onston & Seraten PillI Corporatwn 1%ident. Unirvnity l
herunn Ofar, and Onef thecutin Age 45; elected 1994 Age 69; clared 1980 o[Afd7 and / Balismore county a UNCincorporated Ofar. Constellation Age 67; elected 1992 Enterpnses, Inc. Age 48; elected 1994 Age 60; elected 1988 EREAK NANCY LAMPTON CHARLES R. LARSON GEORGE V.
GEORGEL, MICHAEL D. SULLIVAN MCGOWAN RUSSELL, JR., ESO.
Chairman. GolfAmerica Chairman and Gnef Admiral, UmredStates Exnstin Offiar, Naty (Retired) Former Guairman and
Partner, Age 59;elcetedl992 Amnican 14 and Age 62; elected g99g ChiefEmmtin Offiar, Piper & Afarbury Aaident Iniurance BGE Age 69; elected 1988 Company ofKentucky Age 71: elected 1988 Age 56; elected 1994 COMMITTEES OF THE BOARD AUDIT COMMITTE E COMMITTEE ON NUCLEAR POWER LONG RANGE STRATEGY COMMITTEE J. Owen Cole, G> airman James R. Cu tiss. Chairman H. Iurlong Baldwin, Chairman Ibuglas L. Becker Ikverly B. Byron Douglas L. Becker Beverly B. Byron Charles R. Larson Dan A. Colussy Dr. I'reeman A. H rabowski, Ill George V. McGowan James R. Curtiss George L. Russell, J r.
Jerome W. Get kle EXECUTIVE COMMITTEE Nancy lampton COMMITTEE ON MANAGEMENT George V. McGowan Chairman Charles R. Larson Jerome W. Geckte. Chairman ll. I urlong Baldwin Mkhael D. Sullivan J. Owen Cole Edward A.Crooke Dan A.Colussy Dr. I reeman A. Hrabowski. Ill COMMITTEE ON WORKPLACE DIVER $1TY Michael D. Sulhvan Christian H. Poindexter Beverly B. Byron, Chasruvman George L. Ruwell,Jr. James it Curtiss j Dr. heeman A. Urabowski, til Nancy lampton
t Constellation Enterprises Board of Directors..i, .,.G...nw ,eC.,., ,oSe. EDWARD A.CitOOKE ROGER W. GALE CHRISTIAN H. POINDEXTER Chairman,1%sidant and ChiefExecutin hident, %hing* n Chairman, kident and Ojuer, Constellation Enterprises, Inc.: InternationalEnery Group ChiefExecutiw Ofcer, BGE Vice Chairman, BGE Age $2 Age 60 Age 60 JEROME W. GECKLE MAYC A. SHATTUCK, til H. FURLONG BALDWlN Retind Chairman, Pi(11 Corporation Co-Chairman and Co-ChiefExec~rin Ofcer, Chairman and ChiefSecutin Ofar, Age 69 BTAlex Brwn incorporated Mercantile Bankshares Corporation Age 44 Age 67 EDWARD W. KAY* CHARLES W. $HIVERY Retired Co-Chairman and ChiefOperating JAMES T. 9RADY Oficer, Ernst & Young Chairman, kident and FermerSecretary Maryland Deprtment Age 71 ChsgExecun'w Ofca opusiness andEconomie Devewpment 0""'II'N'" Ib" 8'"'"' I" Age 58 GEORGE V. MCGOWAN Age 53 Former Chairman and ChiefExecutiw Ofcer, BGE f[,}'"0f 'h' Age 71 l Executive Ofi9cers BALTIMORE GAS AND ELECTRIC COMPANY CONSTELLATION ENTERPRISEC ,B CHRISTIAN H. POINDEXTER E. FRANK BENDER, JR. EDWARD A. CROOKE Chairman, kident Vice1%.ident, RetailServices Chairman, kident.tnd ard ChiefExecutin Ofur Age 5l Chief &rcutin Opar Age 60 A e 60 6 NOBERT 5. FLEISHMAN EDWARD A.CEOOKE Ma kident, Corporate Afair, DIANE L. FEATHERSTONE Mce Chairman andGeneralGumel Miaent, Constellation Enery Sourre, Inc. Age 60 Age 45 Age 45 o" ROBERT E. DENTON RONALD W. LOWMAN STEVEN D. KESLER = Executive Vice1%sident, Mce hident, FouilEnerg kident, Constcilation Inns.ments, Inc. Generation Age 54 Age 47 Age 56 GREGORY C. MARTIN WILLIAM H. MUNN FRANK O. HtiNTZ Mce kident, GeneralServices and 1%sident and ChiefExecutin Ofcer. Executin Yur hident, ChiefInformation Ofcer BGEllme 1% ducts &Servias, Inc. Utihty Operations Age 50 Age 5l Age $4 LINDA D. MILLER CHARLES W. SHIVERY THOMAS F. ERADY Vice1%sident, Human Rewurces Chairman, kidens and Mce 1%sident, Corporate Age 48 ChiefExecutin Ofar Stratey & Dewlopment Constellation Ibuer Sourre, Inc. Age 49 STEPHEN F. WOOD Age 53 Mce Midens. Electric DAVID A. ERUNE liansmission &Disersbution JOHN f. WALTER Mce1%sident. Finana & Accountsng, Age 46 kident, Constellation Ibuer, Inc. ChiefFinanci.IOfcer andSecwtay Age 64 Age 58 RICHARD M. BANGE, JR. Controller, Aaounting RONALD F. WATSON CHARL ES H. CRUSE Age 54 Ivesident, Consullation Senior Services, Inc. Mce 1%sident, Nuclear Enery Age 50 Age 54 THOMAS E. RUSZIN, JR. Tvrasu,:r, Finana CARSERLO DOYLE Age 44 " ice hident, Gas Distribution Age 56 J
Five-Year Statistical Summary -_.c,.... .c.,., asm.s.. 1998 1997 1996 1995 1994 j Censumen steek Does QuarterlyEarnings PerShare First Quarter $0.50 $0.43 $0.62 $0.41 $0.49 ] Second Quarter 0.39 0.05 0.36 0.28 0.39 i Third Quarter 1.08 1.11 0.93 1.04 0.79 Fourth Quarter 0.09 0.12 (0.06) 0.29 0.26 Total - $2.06 $1./2 $1.85 $2.02 $1.93 Dividends Dividends Declared Per Share $1.67 $ 1.63 $1.59 $1.55 $1.51 1 Dividends Paid Per Share 1.66 1.62 1.58 1.54 1.50 j Dividend Payom Ratio Reported 81.1 % 94.8 % 85.9 % 76.7 % 78.2%. Excluding nm.airring charges to s...ings 75.9 % 71.5 % 70.0 % 76.7 % 78.2 % Market Prices ~ High $ 35% $ 34% $ 29% $ 29 $ 25% low 29% 24% 25 22 20% Close 304 34% 26% 28% 22% i Capitel Streetere Consolidated Long-Term Debt 53.5 % 48.0 % 45.0% 42.f% 46.1 % 68 Short-Term Debt 4.7 5.1 4.4 1.0 Preferred and Preference Stock 2.9 4.8 6.5 8.5 8.9 Common Shareholders' Equiry 43.6 42.5 43.4 44.3 44.0 Utility Only long-Term Debt 51.$% 45.4 % 42.5% 40.4 % 43.5 % Short-Term Debt 5.8 6.1 5.2 1.2 Preferred and Preference Stock 3.6 5.9 7.8 10.0 10.6 Common Shareholders' Equiry 44.9 42.9 43.6 44.4 44.7 i The sum ofthe quartertv earningsper share amounts may nos equalthe totalfor theyear due to the efeca ofrounding andchanges in the awrage number ofshare. outstanding throughout theyear 7Fe quarterly earningspershare amounts include certain one -time adjustmenn as shouw in Note 12 to the ConsolidatedFinancialStatemenn.
e 4 e f Shareholder Information m.m_ .em-,.as_., Common Stock Dividends and Pelse Ranges 1998 1997 Dividend Price Dividend Price Ded ad liigh low Dedared Hm,h im First Quarter $.41 534 % $ 29 % First Quarter $.40 $28 $ 26% Second Quarter .42 32'L 29 % Second Quarter ,41 27 24 % Third Quarter .42 33% 29 % Third Quarter .41 28 26 Fourth Quarter .42 35% 30% Fourth Quarter .41 34L 25'k Total $ 1.67 Total 51.63 Dividend Pelley Exeestive OHices The common stock is entitled to dividends when and as Gas and Electric Building declared by Ihe Board of Directors.There are no limitations Charles Center in any indenture at other agreements on payment of Baltimore, Maryland 21201 dividends unless we elect to defer interest payments on the Maih P.O. Box 1475 7.16% Deferrable Interest Subordinated Debentures due Baltimore, Maryland 21203-1475 June 30,2038, and any deferred interest remains unpaid; Shoreholder Investment Plan or all dividends (and any redemption payments) due on our preference stock have not been pa.d. BG E's Shareholder Investment Plan provides common i shareholders an easy and economical way to acquire add.i-Dividends have been paid on the common stock tional shares ofcommon stock.The plan allows sharehold-continuously since 1910. Future dividends depend ers to: reinvest all or part of their common stock dividends, unon future earnings, the fmanAt cw lition of the purchase additional shares ofcommon stock, deposit the company, and other factors. common stock they hold into the plan, and request a transfer or sale of shares held in their accounts. commen stuk nividend potes Record dates are normally on the 10th of March, June, Stock Transfer Agents and Registrars Septemba and December. Quarterly dividends are custam-Transfer Agent and Registrar: arily mailed to each sharehokier on or about the I st of April, Baltimore Gas and Electric Company, July, October, and January. Baltimore, Maryland Co-Transfer Agent and Registrar: " "I' "E' "*" ' Chicago, Ilh."" BGE's common stock, which is traded under the ticker non symbol BGE, is listed on the New York, Chicago, and Pacific stock exchanges, and has unlisted trading privileges ,g, on the Boston, Cmcmnan, and I hiladelphia exchanges. if you need assistance with lost or i.tolen stock certifi-As of December 31,1998 there were 69,888 common r dividend checks, name changes, address changes, cares shareholders of record. stock transfers, the Shareholder Investment Plan, or other matters, you may contact our shareholder service P '*** "'I"*' "' I"t l"**
The annual meeting ofshareholders will be held at 10 a.m.
un Friday, April 16,1999 at the Morris MechanicTheatre, By telephone (Monday-Friday,8 a.m.-4:45 p.m.): 25 Hopkins Plaza, Baltimore, Maryland 21201. Bahimore Metropolitan Area 410-783-5920 j Within Maryland 1-800-492-2861 ] Ferne 10.K Outside Maryland 1-800-258-0499 i Upon written request, the company will furnish, with-By U.S. mail'- 6 out charge, a copy ofits Annual Report on Form 10-K, Baltimore G.as and Electric C,ompany .mcluding financial statements, after gs filed with the Shareholder Services, j g Secunties and Exchange Commisuon m March 1999. PO. Box 1642 ,y Requests should be addressed to David A. Brune, Bahim Mm03M h Chief Fmancial Officer and Secretary, Vice President, 34 Finance & Accounting, P.O. Box I475, Baltimore, In person or by overnight delivery: jy Maryland 21203-1475, Bahimore Gas and ElectHc Compcny r* Sharebokler Services-Rm m 820 i} Auditors 39 W. Iexingt a Street 2$ PricewaterhouseCoopers Lt.P Bahimore, M D 21201 0
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?..o Shareholder Information m_.e..umm.-.m.me. Ceaumes steek Divideeds and Price Reages 1998 1997 Dividend Price Dividend Price Dedared Iligh low Dedared High low i' First Quarter $.41 $34% $29% First Quarter $.40 $28 $ d,% k Second Quarter .42 32 L 29 % S:cond Quarter .41 27 24 % Third Quarter .42 33% 29 % Third Quarter .41 28 26 Fourth Quarter .42 35% 30% Fourth Quarter .41 34 % 25'k Total $1.67 'Ibtal $1.63 Dividend Pelley Emesotive Offlees The commc n stock is entided to dividends when and as Gas and Electric Building declared by the Board of Directors. There are no limitations Charles Center in any indenture or other agreements on payment of Baltimore, Maryland 21201 dividends unless we elect to defer interest payments on the Maib EO. Box 1475 7.16% Deferrable laterest Subordinated Debentures due Baltimore, Maryland 21203-1475 June 30,2038, and any deferred interest remains unpaid; snuireliesdedevesw Ple. or all dividends (and any redemption payments) due on J our preference stock have not been paid. BGE's Shareholder Investment Plan provides common shareholders an easy and economical way to acquire add,-i Dividends have been paid <an the common stock tional shares ofcommon stock. The plan allows sharehold-continuously since 1910. Future dividends depend ers to: reinvest all or part of their common stock dividends, upon future earnings, the financial condition of the purchase additional shares ofcommon stock, deposit the company, and other factors. common stock they hold into the plan, and request a transfer or sale ofshares held in their accounts. Commes s6eek Dividend potes Record dates are normally on the 10th of March, June, steek Transfer Agents med Registrars September, and December. Quarterly dividends are custom-Transfer Agent and Registrar: arily mailed to each shareholder on or about the 1st ofApril, Bahimore Gas and Electric Company, July, October, and January. Bahimore, Maryland Co-Transfer Agent and Registrar: BGE's common stock, which is traded under the ticker "*"I' ".ang Savings Bank, '*E ' *** symbol BG E, is listed on the New York, Chicago, and Pacific stock exchanges, and has unlisted trading privileges on the Boston, Cmcmnan, and Philadelphia exchanges. Ifyou need assistance with lost or stolen stock certifi-As ofDecember 31,1998 there were 69,888 common r dividend checks, name changes, address changes, cares shareholders of record. stock transfers, the Shareholder Investment Plan, or other matters, you may contact our shareholder service '*P'***"'** * **I"" "' The annual meeting ofshareholders will be held at 10 a.m. on Friday, April 16,1999 at the Morris MechanicTheatre, By telephone (Monday-Friday,8 a.m.-4:45 p.m.): 25 Hopkins Plaza, Baltimore, Maryland 21201. Baltim.m Metropolitan Area 410-783-5920 sj Within Maryland 1-800-492-2861 j Ferne 10 K Outside Maryland 1-800-258-0499 Upon wrMen request, the company will furnish, with-e By U.S. mail-f out charge, a copy ofits Annual Report on Form 10-K, Baltimore Gas and Electric Company j mcludmg financial statements, after stys filed with the Shareholder Services, 'g Secunties and Exchange Commission m March 1999. PO. Ih 1642 Requests should be addressed to David A. Brune, h;B Chief h_ nancial Officer and Secretary, Vice President, Baltimore, MD 21203-1642 g Finance & Accounting, P.O. Box 1475, Baltimore, In person or by overnight dehvery: h Maryland 21203-1475. Baltimore Gas and Electric Company ga Shareholder Services Room 820 g} aeditors 39 W. Irxington Street 2d PricewaterhouseCoopers LLP Bahimore, MD 21201 O a J
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ML20207M228

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ML20207M228

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