Text

Forwards Guarantee of Payment of Deferred Premiums for CCNPP Reactors IAW 10CFR140.21.Listed Exhibits I-IV Encl
	ML20236W414
Person / Time
Site:	Calvert Cliffs
Issue date:	07/31/1998
From:	Cruse C; BALTIMORE GAS & ELECTRIC CO.
To:	; NRC (Affiliation Not Assigned)
References
	NUDOCS 9808050262
	Download: ML20236W414 (15)
	v • d • e

CII ARLES II. CRUSE Baltimore Gas and Electric Company Vice President Calvert Cliffs Nuclear Power Plant Nuclear Energy 1650 Calvert Cliffs Parkway Lusby, Maryland 20657 410 495-4455 i

July 31,1998 U. S. Nuclear Regulatory Commission Washington,DC 20555 ATTENTION:

Director, Nuclear Reactor Regulation

SUBJECT:

Calvert Cliffs Nuclear Power Plant Unit Nos.1 & 2; Docket Nos. 50-317 & 50-318 Guarantee of Retrospective Premium In accordance with the requirements of 10 CFR 140.21, we are attaching the guarantee of payment of deferred premiums for out Calvert Cliffs Nuclear Power Plant reactors.

Exhibit i A copy of the 1997 Annua! Report to Shareholders of Baltimore Gas and Electric Company containing certified financial statements Exhibit 11 A copy of quarterly financial statements as of June 30,1998 Exhibit 111 A copy of Projected Cash Flow for the twelve months ended July 31,1998 Exhibit IV Narrative statement on curtailment / deferment of capital expenditures (if any) to ensure that retrospective premiums up to $10 million per reactor year for each nuclear incident would be available for payment.

Due to the short time period between closing of the second quarter, and the submission of this guarantee of deferred premiums, our preferred anniversary date for future submittals would be August 15 of each year for both Calvert Cliffs' Units No. I and No. 2.

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Should you have questions regarding this matter, we will be pleased to discuss them with you.

Very truly yours, 40 9808050262 980731

/

PDR ADOCK 05000317 J

PDR CHC/JKK/bjd Attachments: As stated

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EXHIBIT III PROJECTED CASH FLOW FOR 12 MONTHS ENDED JULY 31, 1998 i

Baltimore Gas and Electric Company Calvert Cliffs Nuclear Power Plant July 31,1998 1

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1 Exhibit III Page 1 of 2 Internal Cash Flow Projection For Calvert Cliffs Nuclear Power Plant Percentage Ownership in all Operating Calvert Cliffs Unit No. I 100.00 %

Nuclear Units Calvert Cliffs Unit No. 2 100.00 %

Maximum Total Contingent Liability (000)

- per Nuclear Incident

$159,000 Payable at Per Year (000)

$20,000 Projected Twelve Months Twelve Months-Ended 6/30/98 Ended 7/31/99

' Non - Cash Expenses ($000)

Depreciation and Amortization

$409,548

$433,793 Deferred Income Taxes and Investment Tax Credits

7.346 (6.254)

Total

$416,894

$427,539 l

Percentage of Total to Maximum l

Total Contingent Liability Payable Per Year 2,084.5 %

2.137.7 %

Retained Earnings ($000)

' Net Income After Taxes

$339,021 Plus Non-Cash, Non Recurring j

additions to income -

48,444 i

Less Allowance for Funds Used During Construction 9,400 Less Dividends paid 267.746 Total

$110,319 TotalInternal Cash Flow

$527.213 Percentage of TotalInternal Cash Flow Maximum Total Contingent Liability Payable Per Year 2,636.1 %

Exhibit III Page 2 of 2 Baltimore Gas and Electric Company Underlying Assumptions for Proiected Cash Flows (1)

Projected cash flow does not inc!nde an estimate of retained earnings. However, internally generated funds without retained earnings are well in excess of the maximum possible retrospective premiums.

(2)

Depreciation is generally computed using composite straight-line rates applied to the average investment in classes of depreciable property. Vehicles are depreciated based on their estimated useful lives.

(3)

- Estimates of Federal income taxes and other tax expense are based upon existing tax laws and any known changes thereto.

(4)

Accounting policies are consistent with those in effect June 30, 1998.

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EXHIBIT IV l

NARRATIVE STATEMENT l

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Baltimore Gas and Electric Company Calvert Cliffs Nuclear Power Plant July 31,1998

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Exhibit IV

' Baltimore Gas and Electric Company Curtailment of Capital Expenditures Estimated construction expenditures including nuclear fuel, Allowance for Funds Used During Construction, and conservation expenditures for the twelve months ended July 31,1999 are $452 million. To insure that retrospective premiums under the Price Anderson Act would be available during the aforementioned twelve month period without additional funds from external sources, construction curtailments would affect all construction expenditures rather than impacting a specific project.

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Nuclear Reactor Rrgul: tion July 31,1998 Page 2 cc:

Document Control Desk, NRC (Without Attachments) 1 R. S. Fleishman, Esquire II. J. Miller, NRC J. E. Silberg, Esquire Resident Inspector,NRC S. S. Bajwa, NRC R. I. McLean, DNR A. W. Dromerick, NRC J. H. Walter, PSC i

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EXHIBIT I l

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1997 ANNUAL REPORT TO SHAREHOLDERS Baltimore Gas and Electric Company Calvert Cliffs Nuclear Power Plant July 31,1998

EXHIBIT II i

QUARTERLY FINANCIAL STATEMENTS AS OF JUNE 30,1998 1

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Baltimore Gas and Electric Company Calvert Cliffs Nuclear Power Plant July 31,1998 J

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QUARTERLY FINANCIAL

SUMMARY

June 1998 l

l

+

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y.

7-l SOCS'4tIATED STATE 5E:38 SF 8%C@%E (UDAUDifEO)

Three MeArEnded Six MinAr Erded hehe Momhs Endid June 30, June 34 June 30, 1998 1997 l

. 1998 1997 1998 1997 (in Millions, Eseept Per $Aare A rnounns) i Revmuss l

Dectne...... _

$525.2 5498.1 51,024.3 51.015.4

$ 2,200.6 5 2,15. 9 t

Gas _

82.0 92.3 262.6 306.0 478.1 5 ht.5 Diversified budocsses.....

160.4 156.0 346.8 312.7 628 4 531.9 Total revenues.. _

767.6 746.4 1.633.7 1.634.1 3,3cri.1 3.3 9a.3 Emxsts OmenTHM JtcanTAND!@wETW3 Dectric feel and purrwt energy -

115.6 112.8 242.1 248.0 513.8 520.9 Disalleered replacement energy costs.......

88 6 Gas parchased for resale..........

32.2 48.2 130L4 181.4 241.2 287.4 Operations.-

139.7 133.2 265.8 265.0 519.1 529.1 Maintenance-.~._

57.9 62.7 92.1 102.2 168.4 181.1 l

Diversified budoesss-4elling, general, aed administrative. _

126.8 127.4 270L9 249.1 466.8 408.3 Writealomas of real estaic investacets -.....

49.1 67.6 3.2 67.6 Depreciation and amornzao'on 89.6 85.2 166.1 170.S 358.1 333.2 Tazes other thee iocome taxes...

49.6 49 0 106 6 107.3 216.0 215.9 Total exposes othcr than istarcn and income ancs..

611.4 667 6 1.294.0 1.391 4 2.486.6 2 632.1

)

laceme fran Operations......

__156.2 78.8 339.7 242 7 820.5 1

$62.2 Onem INcowe (EUENSE) 1 Write.off of merger cans (57.9) ado *umae for epsty fusch med dwing connrucson..

1.6 1.2 3.2 2.4 6.1 5.0 Equiry is earmags of Safe Harbor Water j

Power Corporation...........

1.2 1.2 2.5 2.5 5.0 4.8 Nc: other income and (deductions) --

)

._(1.9)

(14)

(2.9)

(2 9)

(5.2)

(3 7)

Total otheriacome(crpense)........

0.9 1.0 2.8 2.0

($2.0) 61 i

laceme Bdore lotcrest and 1ocome Taxes......

157.1 79.8 342.5 244.7 768.5 565J INTEAIST BOE. SE N

Interest chstges

$9.6 59.8 121.4 116.1 246.5 228.0 Company obhgated mandatorily redeceable trust preferred secutities..

0.8 0.8 0.8 Capitalized iateress (0.6)

(1.7)

(2.0)

(4.0)

(6.3)

(13.1)

A1)owance for borrowed funds used during Net interest expense.....

(0 9)

(0.7)

(1.7)

(13)

(3.3)

(17) construcpos ---

~-58.9 57.4 118.5 110 s 23 7.7 212.2 income Beforelocome Ta:es -

~ 98.2 22.4 224.0 133.9 530.8 356.1 INoowE TAXE5 Cunent Deferred...

=

30.7 24.8 88.1 68 8 177.5 146.7 6.1 (15.5)

(3.9)

(16.2) 21.7 (15 6) lavcstacat tax credit adjustments.

(1.8)

(1.9)

(3 6).

(3 8)

(7.4)

(7.6)

Total income taxes -.

35.0 7.4 80.6 46 8 191.8 123 5-Netloczase 63.2 13.0 143.4 87.1 339:0 232.6 Preference Stock Dividcmds-.

5.8 7.9 11.6 15.8 24.4 32 6 f

Earnings Applicable to Commeo Stock..

'5 57.4 5

7.1 5 131.8 5

73.3 5 314 6 5 2000 Average Shares of Common Stock Outstanding.

148.3 147.7 148.1 147.7 147.9 147.6 f

EAaMNos Ptn CouxoN SHARE Faou CtmaEAT-YEAA OPEAAUoNS l

Utility business...

l Constellation Enterprises (Diversified 50.34 1023 50.75 50.62 52.07

$1.72 Budocacs).-

0 05 0.04 0 14 0 16 032 033 Tcad esmags per shaic furo csertat. year opesatiam.

50.39 50.27 50.89 50.78 52.39 52.05 Write.off d merger caste -

(025)

Write. domes of real estate investinents'.m (0.22)

(0J0)

(0.01)

(030)

Disallowsuce of replacement snergy costs *....

(039)

Total Earnings Per Camace Share and Earnings Per Common Share-Assuming Dilution..

$0.39

$0.05 50 89 10 48 5213 5136 l

C3NS1ELaATION EN7ERPRISES, INC. AND $UB31 DIARIES (CEI)

ComusunoN TO EAAxtNcs Pta Cowwos SHARE By Out Divousnsn Buswissts Power Marketing.

50.01 50.01 5 -

50.01 5-Power Generation-.-...

0.04 0.05 0.11 0.12 0.24 020 j

Gas Brokering and Energy Services.

(0.01)

(0.02)

(0.08)

(0.02) j Home Pmduca and Commerdal Bldg Syrtems.._.

0.01 0.01 0.02 0.02 0.03 0.03 j

Other(Primarily Real Essate & Investments).

(0.22) 0 02 (0.26) 0.11 (0.18) l Tota!.

50 05 5to.18) 50.14 5(0.14) 50.31 50 03

=

4 BGE's lovesrinent in CEl-End of Period -

3309.9 5426.3 5$09.9 5426.3 5509 9 542fL3 Informan'on for Cf.) does not reflect coMolidon'ag elineinctionsfor buerconveny balances and trarrectioM.

2he inserim inforneation cantoined herein reflecu appordonment.r ad esimates ofsane bems subject so final adjunmenu et the calendaryear.

and. Resulufer interim periods, which con be forgsly influenced by umher conditionr, are not necessarily indicatin of resula to be crpectedfor mi cndreyear.

Cersninprior.perded omounu how been recfossified to cor(orm with she currentperiod's presentation.

Nonrecurring charges so tornings.

Baldmore Ga.r ed Elecme company endSubsidiaries

)'

I GOC 3OLID ATED SALAOCE COggts (3%AG0lTEO)

I June 30, 1998 1997 l

ASSETS Cymsspr Assggy (in Mi.%ns)

Cash and cub equivalens.

5 302.5 1 271.2 Accounts receivaNe (aet of allowance for uncolleenb1cs of $24.1 and $16.4, rcapectively)..

388.1 400.4 l

Trading sonrritics.....

Fuel stocks 121.7 85 0 75.3 60.2 Matcrials aad supplies.

160.5 166.3 Psepaid tases other than lacome taxes.

3.0 3.0

[

Asses from cocrgy trading activitjes.... -

3513 Oihar 2&7 39.1 Total curtcot asses..~..

.. ~.

I<4311 10452 le. tsTm75 ANDOTHEA ASSETS v

Real estate projus..

4214 440.8 Power generettoa systeins..

539.8 404.9 Tisancial lamtments............. --

187.4 198.0 Nucacar dacommisioniog trust fund..

165 0 12&7 Net pension amet.....

Safe Huber Walcr Power Corporation 114.8 96.9 34.4 34.4

.....m

- = - _.

Seeier living facilities 76.6 44.4 Other 1061 99.0 Totalievestacets and onber assets 1,646.S 1,449.1 UTRrTv PLAkT Utility Plant...

8.597.2 8,315.4 Accummutated depreciscon......

(2.966 9)

(1 719.7)

Net utility phet

.......... ~..

5.6303 55957 DEFIAman OLAncEs Regulatory uncts (act)...................

4310 464.5 Oit er............

534 10s.5 Total deferred charges =

4904 5730 TorAI. Assrrs..

59_.19s 3 58s663 0 1.IABILITIES AND CAPITAL!ZA710N Cumazwr1 tAan mcs Short terms borrowings

$ 715 5 116.9 Cunent portions of long-tens debt and preference stock :

631.0 324.8 Accouais payable Customer deposits....,....

200.6 147.5 32.5 26.4 Accawed taxes...............

0.6 3.2 Accrued jetsrest 60.5 61.4 Dwidends dadered 68.0 68.4 z_......

Accrued vacat.on costs.......

38.7 38 9 Usbilities from emergy trading setivities.......

333.1 Oib er............

26 1 23 5 Total current liabihties--.

DaTAarD CAtor:s AND Ornta 1.JAsiurits 1.463 6 el) o Deferred incarne taxes...

1.2AS.3 1,274.7 Postratirement and postemploysest benefits.

195.3 180.5 l

Decommissioning of federal uraniwo carichment facihties 34.9 38.6 l

Other. -

Total deferred credits and other habilities..

584 64 6 i

1.573 9 1.558 4 CAPITAll2NilON j

IANc.7taat Durr First refunding mortgage bonds of BCE..

1,570.8 1,619.4 l

Oiber losC.terni debt of BGE.

1,027.8 937.8 1.mg. tam debt of diversified busiact.acs 735.9 841.1 Unamortzed discoest and premive.....

(13.3)

(14.3)

Curvent partion oflong. term debt.

__f508.0)

(221 8)

Total toeg.tenn debt.

c 21112 3.162.2 CowPwy OeuoATED MepATonr1.Y RrosswAntz ThusT PapuAED Stcunmcs 250 0 RnJ>< Ant.z PkETEADCE $70CC.......... -

110.0 216.0 Qarrect portion of redeemable preference stock

_(103.0)

(103 0J Total redeeanable preference stock 7.0 113.0 PRDnENCE SmCK Not SuwEcrTo MAmeAroav REpoartoN - _

210.0 210 0 Qineer portion of preference stock not subject to mandstory redcaption..

Total prefeseece stock not subject to mandatory redemptoo.

4..

.. m (20.0) 190 0 210 0 Cowwow SHAitzwtotes' Ecurry Ceuw e stock....

1,454.5 1,431.7 Ret, '

mass,

w Aci d orhercomprebenr.iveincome 1,4413 1,368.0 j

Tot amos sharebelden' etjuity................

48 6,,7,,

2,900.6 2.806 4 l

Total Cs,stalizoflee 6,160.8

, $&663.0 6.291 6 70TA1.11ABluTIES AND CAPITAUZAT10's :

$9,198.3 Cerneinprior-period amounts Asw been reclestifad se ecnform edh he cunentpcried'rpresentsnon.

Baltimore Gas ans Electne Company end Subsibaries

UTILITY SPED AflNC ST AflSTIC S Three Months Ended SirMonthsEnded Ts. ele Mauhs Ended June 30, Jame 30 June 30, DICTR1C 1998 1997 1998 1997 1998 1997 Kmyves GnMituant)

Residential-with bouschesneg. -.

S 83 4 5 83.1

$ 1934 5 202.2 5 392S 5 3953

--ota

--4atal 1313 121.1 246.6 237.9 539.7 520 0 Comroerdal

"~).14.7 M2 440.2 440.J 932.6 9T E 224.0 213.8 414.1 408.7 897.9 867.0 1sdassial......_

55 3 52.1 1003 98 6 213.9 207.9 Systeso Sea -

N..ge and Otha Sales. -

494.0 470.1 954.8 947.4 2.044.4 1,990T Imierdian 25 5 22.8 57.9 58.4 132.2 136.4 Total 57 5.2 11.7 9.7 24 3 25 3

!~31C2 5 498.1 51.0244 51015.5 52.2009 511539-ses #7a naurandr)-MWH ResidentiaWth bousci: Mag.-

968 974 2,487 2,614 4,863 4,959

-- other --

1.387 1.272 2.747 2.638 5.905 56&S

-40tal...

~ 2,355 2,246 5,D4 5,252 10.7&3 10,644 Cosntmacia!..

3,178 2.995 6,330 6.088 12,960 12.541 ledustrial 1.195 1.138 2J09 2263 4 621 4.562 Sysica Sees-

' O ta 6,379 13JY3 13,603 28J69 27,747 Interchange and Deer Sales.-

1 063 1.108 2,798 2,S63 6.159 6.831 Total

'7,793 7.487 16 671 16 466 34.528 34.578 GAS Anwuts anMillions)

Readeneal--cxduding ddivery scrvia ~. S 49.2 S 56.6

$ 1641 5 191.2 5 294.6

$ 3143

--ddivery sawce.

06 1.9 2.4

~4otal......-

49.6 566 166.0 191.2 297.0 314f Comnumd-exduding ddivery savice....

11.5 17.5 44.8 70.4 87.9 115.5

-<leisvay scrvice.

36 3.0 10A 6.9 16.7 11.2 Industrial --exduding ddivery semce.

OE 1.6 3.6 6.6 85 13.6 Klehver System Sales... - y service.....

3J 42 8.2 64 16.9 16.8 69.5 hz.9 233.4 263.5 427.0 472.0 Off. System Sees -

10.8 7.5 25.6 18.7 44 3 32.0 Other.... -

1.7 1.9 36 38 68 6.5 Total.-

SnLks On Thousands}--D]M_..

5 82.0 5 92 3 5 262 6 5 3060 s 475 1 5 5105 R sidentielm:xdudang delivery service 5,160 6,616 20,911 24,144 36.726 40,569

-widivery savice-227 718 924

--4otal.............

~~Dh7 6,616 21,029 24,144 37,650 40.569 Cornmer21!- esdu&a.g ddivery savice 1,514 2.531 7,166 11.1 %

14,404 19,387

-dehvery servia.

3,402 2.878 9.315 6,878 15.401

!!,838 Industrial --<xdu&ng ddivery savios..

50 366 519 1,175 1.360 2,338

--ddivcry savice BJ27 9 681 17.180 16.766 37.204 38.254 Sysican Sales.-

'TE,seo 210f2 55.809 62.u9 106.019 112.3 %

oft.Systcro Sdes....

5,210 4,035 11.113 9.399 19.325 14 W Totd..

2a.090 26.107 EGI2 71.55a 125344 127.330 Uniky operating stasuncs do not reficct she elimination ofintercompany transacsior.s.

Certainprior-periodamounts hase been reclassified to cenform with the currestperiod' presentation.

DE ATIN0/ COOLING DEGREC D#Jif (Caiendet. Month Basis)

Henting degree days -Acrual......_..

463 671 2.4E5 2,923 4.383 4,840

-Normal 534 558 3,011 3,090 4.822 4.901 Cooling degree days-Actual-258 179 279 182 843 689

--Norm al.......

227 217 230 220 814 804 E L E C TillC GENERAfl0N STAtlETICS Iwelw MontArEndedJune 30, Purchased H>dro Pos,vrNa ef Generatics by Fud Type (%)

Nuclear Cool Oil

& Gas Energy 3 ales Tosat 1998.-

44.8 60.1 2.3 37 (10.9) 100.0 1997 42.5 5&4 0.8 3.6 (53) 100.0 Thousands of MWH 1998..

.13.439 18,024 687 1,103 (3,256) 29.997 1997..

12.519 17,194 236 1,053 (1,553) 29,449 Avaage Cast of Fuer (Cents per Million Bru) 1998.-

1997 45 %

138.88 267J1 102.07 47.11 141.01 299.51 10196 baltimore Gas andE!ccaric Company andSut<sieuries

COCSOLIOOTEO STATECENTO CF CCSM FLCOs UKA'JOITED) s',Monrkr Emled TmeheMonArEnded June 30 June 30 1998 1997 1998 1997 (In Millions)

CasN FIDess Faow Orsa4mc Acnvmes Na income 5143.4 5 87.1 5339D 52324 Adjustments to accondle to act cash provided by operanet ac6 vines Depcdation and amorar.: tion.

209.0 195.7 4092 3s73 Deferred income taxes Q.9)

(18.2) 21.7 (154) levessment tax credit adjustments (3.6) p.8)-

p.4) 04)

Deferred foci cx>su..

20.4 27.7 IID 82 Difereed cacrgy r==vanon reveaucs 28 5 Disallowed septacumcat energy casa...

88.6 Accrued pension and pestemployment benefits.

10.6 (0.1) p3)

(3.9)

Writoetfof mergerceu 57.9 Write. dooms of real esme invcsaseou.

67.6 33 67.6 Allowance for equity funds used during construction -

p.2)

(2.4)

(6.1)

(5D)

Equity se carsisgs of affiliates and joint ventures (nes)

(11.9)

(15.6) 090)

(40.9)

Nages in assen from energy trading acdvitics.

p41.9)

(351 3)

Nages in liabilities from coergy trading activities. -

324.5 333.1 Changes in cvrrent assets, othcr than sales of receivabics and assen from energy trading ac6 vines.-

104.9 57.9 p.2)

(59.7)

Changes in curvest liabilities other than sbart4enn borrowtags and habilines from energy trading activities (18.2)

(31.9) 56.4 13 3 (15.1)

(0.8) 05D) 5.1 Other

= ~ - - -

Na cash pHdad by operating acevides..

415.0 363.2 7783 6965 Cash Fmws FhoM Fnwomo ACDVmES Net maturity of shon. term borrowings (2t.34) p16.3)

(44A)

(15 7.9)

Praccaos from issusace of Lengacro debt.

141.4 5283 235.1 7502

-m. -..

21.6 55 Comeenn stock........

12.6 Compsey obligated mandatorily scdoematste trust preferred securities 250.0 250D Proceeds from sales of receivabics.....

10 0 Reacquid6am oflong.ncre debt.....

(59.1)

(102.2) p002)

(1902)

Redemption of prefuence stock........-.m..

(3.0)

(1.5)

(1(16.0)

(50 5)

Comocm stock dividends paid (121.2)

(118.1)

(2423)

(236 2)

Prclestace stock dividends paid..,..

(11.6)

(15.8)

(25 5) 03D)

Orher........

8.1 1.2 16 (13)

Net cash (uscd in) provided by finanong sciivities.....-

(25.8) 75 6 (210.1) 96 6 CASH Ft.ows FaowlievEsmo AcTrvrngs Utility construenos expenditures (including AFC).

(143.8)

(166.0)

(351 0)

(361.7)

A!!awance far equiry funds used during conservation......

3.2 2.4 6.1 50 Nucica? fuel capenditures...

(183) 97.1)

(45.0)

(48.7)

Deferred energy conservation expenditures..-... -

(10.8)

(13.1)

G4A) 90.0)

Consibunom to nuclear decommissioning trust fund...

(8.8)

(B.8)

(17.6)

(17 4)

Merrer cesis (22.4) 1.4 (45.9)

Purchw of markeable equiry secuntics...............

(163)

(9.9)

(29.6)

(19E) 18.7 21.5 43.7 36.9 Sales at marketabk equity secunnes -

Oiber finandalinvestacau......

13.6 (0.9) 14.1 03 Real eswc projects.........

m_

26.9 23 4 27.7 (12D) l Pom er generaties systems (82.1)

(17 2)

(1092) p1D) i Other (31.2)

(26.2)

(53 2)

(47A)

Net cash used is investing activi6cs.. -

(2493)

(2343)

(537A)

(561.9)

Nes laacase is Cash and Cash Equivalcar -

139.9 2043 31 3 233 2 Cash and Cash Equvalcats at Beginning of Period.

162.6 66.7 271.2 38 0 Cash and Cash Equivalesis et End of Period 33025 1271.2 53025 5 271.2 ODIEA CADI FIDWINFORMATioW l

Intercs: paid (nes of amoeats ca pitalized) 5114.7

$100.6 52354 5191 A

!aceae cases paid 5 M.9 5 57.9 51585 5 142.0 Cersein prior. period enountt how been reclamped to conform wns 6e currsnoperiod's presenrosion.

Balahnore Gar endElectric Company andSubsidiaries i

~

l C*J P P L E C ECT AL FIOOCClCL STATISTICS TmekeMonAtEndedJune 30, Utihry Conredidated 1998 1997 1998 1997 CarrTau2Aftra*

Imag-tsno debt.

46.9 %

46.8%

48.4 %

50.0 %

Company obligstad mandatorily redeemsble trust prefer.M securitics.

4.6%

36%

Shawtens barrowegs.

2.2%

1.1%

1.7%

Prefsence stock

_............. ~. - -

5.8%

7.8%

4.7%

6.3%

Commas equity......

42.7%

43.2%

42.2%

410%

RrnmW ON Avrancs Come. sow Ecurry Repreted...

11.2 %

8.1%

10 9%

7.0%

Excluding moerocurring charges to carmings".

12.7%

!a6%

12.2%

30.6 %

RAno or E4raewcs(SEC McTuoD)

To fined charges.

339 2.93 3.11 2.50 To fisal charges and prefaved and peference dividends combined 2.81 230 1 68 2 05 AFC As A % or Eaawmcs Arruc4st.zTo Comox Smcx.

3.5%

3.9%

3M 3.8%

l.

Eerscrrvt Tax RAtt..

35.7%

34.5 %

36.1%

34.7%

Cersninprior-pernodamount.r how been reclasnfled to conform wid she currentperiod*: presentation.

l

Capitalisenien includes currentpore'ons oflong term debt andpreference stock.

" Nonrecurring charges so earnings include she wrue+ffef merger costs, mvue doms of real estese innstments, and the wrue.off of dUellowed l

repleccment energy casts as shown on Ae '.lonsolideredSsstemenn ofincome.

COMMON $10CK DAT A j

ThreeMonths Ended TmelwMonths Ended June.30, June 30, l

1998 1997 1998 1997 l

Comon Smcr DvtDreos PrA SnAas l

-Declared.

50A2

$0 41 S t.65 51.61

-Paid.

50A1 SCA0

$164

$1.60 1

Maascer V4un pen Snaar

=-

$32%

$27 534 %

S28X 1

-Mgb -

l

-1.ew 330X

$24%

525 %

325

$31X.

526'X.

131 5 126 %

-Cc6e i

Shares C'W:;-End of Period (In Millionr)........-

148.3 147.7 1483 147.7 Book Value Per Shero-End of Period.

$1935

$19.01 519.55

$19.01 Cersain prior. period enouna how been reclassified to conform Mah she curres.rperiod' presentation.

1 1

Irupiirie.s concerning this swrunary should be directed to:

. D*MA. Brune XevinJ.MiIter Baltimore Gas andEleraic Company McePresidern,

Director, P.O. Bae 1475 ChiefThannaa! Officer, financialPlanning Balsimore, Maryland 21203 andSecresary (410)234 5434 (410)234 3511 Balaimore Gas sadElece"ic Company andSubsidiaries maren ssusu L_____________-._________________________-.---

W

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k

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i n p ain Engrsh 1997 Annual Report to Shareholders P

4

%l 4, 4. a et,(, g.

Contents As the nation's oldest gas utility and one of the earliest electric utilities, the hitimors 2

BGE at a Glance Gas and Electric Company brirngs gas and electricity to mora than 2.6 million r=ldents in 4

Chairman's Letter Central Maryland. BGE's subsidiaries also enhance customer service and increase revenue to Shareholders growth. In 1997 combined revenues totaled $3.3 billion from utility and diversified operations.

8 The rules are changing..

10.. and we'll be ready.

Financial Highlights 12 Here's what we're doing.

1997 1996

% Change _

17 Financial Contents ton mittoons except per-share amountss 56 Diret90rs and Officers COMMON STOCK DATA 60 Shareholder Informat. ion g

Earnings per share from current year operations Utility business

$1.94

$1.96 (1.0)%

Diversified businesses 0.34 0.31 9.7%

Eamings and DM4 ends Declam11 Total earnings per share from current-year operations

$2.28

$2.27 0.4% "

per Sham of Conan Stock

Write-off of merger costs (0.25)

Write-downs of real estate investments (0.31) s2.so -.- -.._

Disallowed replacement energy costs (0.42)

Total earnings per share

$1.72

$1.85 (7.0)%

Dividends declared per share

$1.63

$1.59 2.5%

88 Average shares outstanding 147.7 147.6 0.1%

~

~~

issa"iss4 'ines toes 1es7 Retum on average common equity sem semines(consandeted)

Reported 8.9%

9.5%

(6.3)%

""' DkW'"8' D**'a"8 Excluding nonrecurring charges to earnings 11.7%

12.0%

(2.5)%

Book value per share--year end

$19.44

$19.33 0.6%

Return on Market price per share-year end

$ 34*/s

$26a/4 27.6%

Average Common Equity 12s._. _ _. _. _

FINANCIAL DATA Revenues los _ _

y_.. ' _ _ _ _. _ _ _

Electnc

$ 2,192

$ 2,209 (0.8)%

os _

Gas 522 517 1.0%

~

Diversified businesses 594 427 39.1%

~

~~

~

Total revenues

$ 3,308

$ 3,153 4.9%

as.

Net income

$283

$311 (9.0)%

D,,, - -

,,4

,,,,,,3,,,

3 3

Eamings applicable to common stock

$254

$272 (6.7)%

Assets sbess M,U8

$7,M3 m

Common Stock Market Price Diversified businesses 1,595 1,401 13.8%

and Boom per St'.am Total assets

$8,773

$ 8,544 2.7%

sas sao _. _.- -

Utility construction expenditures (excluding Allowance

\\

for Funds Used Dur'.ng Construction)

$365

$349 4.6%

s2s.

BGE investment in the Constellation Holdings Companies

$342

$396 (13.6)%

s20..

sis..

l_

UTILITY SYSTEM DATA sto Electric sales--megawatt hours 28.1 28.4 (1.1)%

ss _

Gas system sales-dekatherms 112.4 114.3 (1.7)%

o.

_1994 19s3

~

. _190s 199s 19s7

Nonrecumng charges to eamings disco:ssed in Note 12 to the Consolidated Financial Statements (page 51).

an, m p,ge, gp og,,,p Certain poor-year amounts have been reclassefoed to conform with the current year's presentation.

mm saokvalue(paarend)

Vlelt eer wobelte at Committed to Equal Opportunity http://www.bge.com As an Equal Opportunity Employer, BGE does not disenminate on the basis of age, color, disabikty, mantal status, national origin, race, rehgion, sex. sexual ori.sntation, or veteran status.

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DCE ct a Gicnco Product / Service Companies Activities Customers and Markets Eloctric generation, BGE = Regulated, investorowned gas and electric utility, = More than 1.1 million transmission, and providing service in Central Maryland industrial, commercial, nd residential electric distribution = Owns and operates 10 generating plants (two nuclear customers in 2,300-l units); part owner of three generating plants in squaremile service Pennsylvania; total generating capacity exceeds Natural gas supply territory and distribution 6,200 megawatts = More than 565,000 = Belongs to Pennsylvania-NewJersey-Maryland industrial, commercial, interconnection (PJM), a power pool interconnecting nd residential natural-the transmission systems of eight energy companies = Stores and delivers natural gas through two gas f sq ar - plants and nine gate stations service territory Wholesale electric Constellation Power = Develops, owns, and operates power generation . Domestic and Latin generation and projects in the U.S. and Latin America; provides American wholesale distribution operations and maintenance services to energy and retail energy facilities markets Energy marketing Constellation = Provides wholesale power-marketing and risk-a Wholesale Power Source management services, with Goldman Sachs Power energy customers as exclusive advisor nationwide Constellation = Provides wholesale and retail = Wholesale and retail Energy Source natural-gas marketing services customers in the Mid-Atlantic and Northeast = Offices in MD, TX, PA, VA, and CT Energy products Constellation Energy = Offers energy consulting and power quality services = Industrial, commer-cial, government, and and services Projects & Services = Develops district and private electric, gas, and retail customers east chilled water systems of the Mississippi = Offices in MD, VA, and PA BGE Home Products = Sells, installs, and suvices HVAC and plumbing = Residential and & Services systems; sells and services appliane-s and commercial customers electronics; offers full range improvements in MD, VA, and BGE Commercial = Provides full-service building solutio..s, including HVAO, Washington, D.C. Building Systems plumbing, and building-automation systems Other businesses Constellation = Provides income from investments in securities = Relatively liquid investments and partnerships investment markets Constellation Real = Develops, owns, and operates commercial properties

Institutional investors Estate Group and regional cornmercial markets Constellation Senior a Develops, owns, and operates senior-living facilities.

= Elderly market on the Services with emphasis on assisted-living market East Coast 2

3 vf 4S 7

%r* J 6,Lmiaw+, W.8,6+. pm j r. .4( _\\ 3 1997 Highilghts [+i', t MAR = Generated $3.1 million in revenues through Premium Power Program s sales. Received EPRI Award for Best Utility Power Quality Program in U.S.

Set generation records in fossil and nuclear plants by generating f

31.2 million megawatt hours (MWHs), an increase of 22% wet N M ' since 1992

W la IAeryload.

v = Connected about 14,000 residential customers to gas heat; added / 2.2 million dekatherms (DTHs) of new industrial and commercial load; exceeded industry average for industrial and commercial gas customer satisfaction by 22% h( i, l ?l = Signed long-term power supply agreement with national distribution company in Guatemala; will develop generation plants to fulfill agreement e Developing co-generation plant in Curagao that will supply utility e,e ;. k I ,e needs of an oil refinery and electricity to the island utility a e De.veloping 700 MW electric generation site near Los Angeles for f I merchant sales in Southern California market e

Purchased and operating coal-pulverizing plant in Gary, IN, to eI supply U.S. Steel facility j

p. p.- 3 - j e Traded nearly 9 million MWHs throughout the U.S. with more than 60 companies in first year of operation d'd ' s = 1[ L i e Signed first U.S./ Canadian energy storage deal with Hydro Quebec 1 to swap power over two-year period y 'X [# Power Pleets Owood, Operated, e increased natural-gas sales 60% b{ er glemeded Ipy a==d=Mh Power = Invested in gas-management, risk-management, and accounting t.' systems to support large volumes of transactions typical ir' t's Sedpoldiary ONiees deregulated natural-gas market b .= s )

Provided total energy solutions to large

s. ;ncluding Social l -[jhh Security Administration, the U.S, Postal &

, and several commercial chain accounts [ a Received the Secretary of the Army's Energy Conservation Award I } ) ^ for making Aberdeen Proving Ground a showcase for EPA Energy [," - ( Star technology y

Improved profits through the growth of attractive business lines 4

and organizational efficiencies I 4 = Expanded product and service offerings to Maryland suburbs of I Washington, D.C. .a. e Capitalized on strong financial markets, resulting in another strong l- . f y performance year [, lE

Continued reduction of real estate assets, expansion of service

[ ( business, and investment in select, profitable new projects [ (. is I' s Current portfolio consists of 1,369 units in 26 facilities, of which b 11 are operating, five are under construction, and 10 are under ( development f-p f, t un-. 3

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Witn::o tho felicwing ccticns wo took in 1997: o We canceled our merger with Potomac Electric Power Company (Pepco). We did this because two of the regulatory orders approving it had imposed financial conditions that would have made it impossible for our investors to share in the benefits now or in the future, c We increased our dividend rate. This marked 88 consecutive years of paying dividends. We have raised our dividend 20 out of the last 22 years and have never lowered it. o We positioned ourselves to take advantage of new opportunities in the wholesale elec-tric market by creating Constellation Power Source. Through an exclusive arrangement, this new subsidiary draws on the risk-management and trading expertise of Goldman I Sachs Power, an affiliate of Goldman, Sachs & Co. l ssmpe a We filed a request to increase gas rates. This will give us an opportunity to earn a Cumulative Total Return to proper return on the new investments we've made to meet the growing demand Shareholders through 12/31/97 for service. si. coo % We strengthened our competitive position by further lowering our generation costs. Since 1992 we have lowered those costs 23%. 8* $700 $600 Dur goal is to continually increase shareholder value sroo Despite a year of mixed financial results, our stock price hit an all-time high in 1997. Total go, _ shareholder return ran well above utility industry average--nearly 35% versus industry noo average of 26%. We believe the increase in our stock prices not only reflects the favorable overall market conditions and interest rates, but also the investment community's confidence in our competitive advantages and earnings potential. l m2 im m2 Our reported eamings were down 6.7% from last year. Sales were down due to milder weather, and we took several write-downs. Without these charges, our earnings from "- Initini $1oo investment "' Totai neturn with Dividone. n.inv t.o operations were $2.28 per share. Here are the specifics: c During 1997 electric system sales decreased 1.2%, and gas system sales decreased BGE shareholders have enjoyed 1.7% compared to 1996. Most of the decline was due to milder weather. solid Investment returns over I""* o We wrote off our share of the merger costs incurred during the 27 months we were W in ME on hcenhr M, preparing to operate as Constellation Energy

Corporation. This amounted to 25 cents l

per share. Most of the costs were associated with information and telecommunication Providing a 16% annual retum, l systems conversions necessary for operating as in integrated company. with dividends reinvested, o Our real estate subsidiary wrote down costs associated with Church Street Station in Florida when we began negotiations to sell the project. We also wrott down the Piney Orchard project in Maryland, to comply with accounting rules, based on estimated future cash flows. 5

Maryland prepares t) give cc stomers choice c4 energy suppliers Although I was disappointed that we had to terminate the merger agreement with Pepco, it was the right thing to do at the time, in business, as in life, tirning is everything. When our merger with Pepco was announced in September 1995, it made perfect business sense. It would have further lowered our costs and increased our financial base. Yet those advantages were hot.mrth the price the regulatory orders required. We decided to cancel the merger when we saw that the orders would not be adequately modified. Now we are turning our fuli attention to important issues affecting our company " Preparing for competition has as we move toward customer choice. Both the Maryland Public Service Commission (PSC) and the state legislature are working to reshape the state's electric industry. The PSC's goal is to have legislation and regulations in place so been my Single moSt important that all customers will be able to choose their electric suppliers by July 2002. (See pages 8-10 for more information on restructuring activities.) goal since becoming chairman We're gaining valuable eN+"a through our gas tmainess While the change to customer choice will be dramatic for everyone who produces, delivers, or uses electricity, we've already seen competition open new markets in fiVJ years ago. I am OHCoup, the natural gas business. Our industrial customers have been able to purchase natural gas from third-party suppliers since 1983. Now commercial and residential customers are beginning to have that choice, as well aged by our accomplishmerstS To enjoy the benefits of a competitive marketplace, we believe customer choice is e%ential. That's why we have supported the PSC's efforts to establish retail gas So far." competition in the region. The process has helped us learn more about the market and what customers want from their suppliers it has also helped our nonregulated gar <merketing subsidiary, Constellation Energy Source, position itgelf to compete as the gas supply arena continues to open. It is important to remember that evera when customers choose their suppliers, their gas is still delivered through our distribution pipes. Our long-term goal is to continue to perform among the best local gas distribution companies. Toward that end, we've reduced operating costs per gas customer for the fourth straight year. And we've maintained a customer satisfactico rating that's well above the national average. We have a distinct advantage in wholesale power mar. eting amd smpply k With industry restructuring, we expect ths generation part of our utility business will move from a regulated environment to one driven by competition. As this evolves, we will continue l to work to be a low <:ost generator and reliable energy supplier in our service tarritory. We l also will continue to explore business opportunities in nonregulated energy markets. Already, deregulation in the electric utility industry has opened up the wholesale power supply market--where bulk electric power is sold for resale. This has spurred the increase in power marketers-companies that buy and sell energy on the open market. Now in a phase of exponential growth, power marketing has the potentia) to become the biggest commodity market in the country. These developments present us with exciting opportunities. In.last year's annual report, I announced that we had formed Constellation Power Source, our new power-marketing j company. In less than a full year of operations, Constellation Power Source has established I itself in the national wholesale market for electricity and associated risk-management l products. In 1998 we believe we'll see a rapid rise in our market position. l l 6 u_________

We enter the power-marketing business with a distinct advantage-an exclusive advisory BGE Generation Costs relationship with Goldman Sachs Power, an affiliate of Goldman, Sachs & Co. Between their Decresse Faster Than Rzglon's exp3rtise and ours, we have what it takes to be successful. (Ws powamur) I l That's why I am pleased to announce that we have again joined forces with Goldman Sachs. se In January 1998 we signed a letter of intent to form a company to buy power plants in the United States. j Under the terms of the agreement, this company will form strategic alliances with ae 'N Constellation Power Source and Constellation Operating Services-our subsidiary that operates power plants in the United States. Constellation Power Source will be the exclusive 3, provider of power-marketing and riskmanagement services, while Constellation Operating Services will provide the exclusive operations and maintenance services for acquired 3, power plants. U We'ro preparing to be a player in the competitive arena Preparing for competition has been my single most important goal since becoming chairman sus PM Costs W997 rmt avanatsei five years ago. I am encouraged by our accomplishments so far. We've earned our customers' confidence, maintaining residential customer satisfaction ratings that are among the best in the country. We've become one of the lowest cost, BGE Production efficient generators in the region. In the past six years, we've increased the number of Reaches Record Levels customers per employee. At the same time, we've improved our customer service, system (Mnhons of Megawatthours) reliability, and powerquality performance. 8' - For all we've accomplished, I especially want to thank our employees for their extraordinary 3, efforts 13st year, it was often difficult, given how uncertein the future seemed without resolution of the merger. But I also know the merger process has been an invaluable learning experience for all of us. It taught us how to perform well and shift gears in an atmosphere of uncertainty and s. dramatic change. We will need those skills as we navigate the challenges the next few years will present, o. 1992 1993 1994 1995 1996 1997 i also want to thank you, our shareholders, for your continued commitment to BGE. Our goal is to maintain your confidence by taking an active role in shaping our future in the new competitive world. Since 1992 we've lowered our generating costs by 23%, while increasing our electric produc-tion by 22% to meet growing customer demand. D / Christian H. Poindexter Chairman of the Board and Chief Executive Officer February 12,1998 7

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l l l l Wiro in the middle of an electric revolution l l The electric industry revolution began several years ago with candid questions from large electric customers: Why are there no choices in electric suppliers? Why is there no competition among utilities? How can we reduce our energy costs? The response to those questions has been a move to open the nation's electric industry to competition. As a result, both federal and state regulators and lawmakers have begun exploring the issues that come with restructuring the nation's most vital service. ( Meanwhile, nearly a dozen states where electric prices were highest-most notably California, Pennsylvania, Massachusetts, and New Hampshire--have already approved restructuring legislation and will begin offering customers choices of electric suppliers as soon as this year. All of this activity is creating new challenges for the $200-billion-a-year electric industry as it moves into uncharted territory. chang'ng lbctructuring presents new challenges for utilities Until now, regulated electric utilities performed three primary functions: generating electricity in power plants, transmitting it over high-voltage wires to the local distribution system, and distrib-uting it to businesses and homes in a franchised service territory. Restructuring, however, will separate those functions. In a deregulated market, competing companies can move into a utility's once-exclusive territory and sell power to that utility's customers. The local utility, meanwhile, would continue to distribute the electricity over its local power lines. Simple as that seems, restructuring has proven to be a complex undertaking. Because electric utilities are regulated, opening a state to electric competition requires regulatory changes that support market conditions that are fair for all competing companies. States are making decisions on a broad range of issues from how electricity will be taxed to who should pay for utilities' stranded costs. What are stranded costs? They are costs a utility would recover under a regulated pricing system, but not a competitive one. Traditionally, utilities have been required to serve all customers in their franchised area while regulators have set the rates to ppy for that service. To meet customers demand for electricity, utilities have had to build generating plants and buy power, among other things. While regulators have approved these investments, they have tried to keep prices low for consumers by setting rates that deferred or spread these costs over severa! decades. Under customer choice, however, electric supply rates will be set by the market, not by regulators. That rneans if the market price drops below the current regulated price, the utility would not recover its investment in generation and, therefore, the costs would be " stranded " MIryttad snakes a move toward competition Although restructuring is in at least the discussion stages in nearly all 50 states, each state has its own timetable and, in many cases, its own approach to restructuring issues. 9

a 4 io s, As of February 4,1998: O ctata= with orstomer choice approved C States with contmissions recommending customer choice In late 1997 the Maryland Public Service Commission (PSC) ordered that electric competition O states studying the issue be phased in over two years beginning July 1,2000. Under the order, all Maryland electric O Ctate with no action customers would be able to choose their electric suppliers by July 1, 2002. The PSC's decision also included direction on several key restructuring issues. It appears to Neirly every state in the U.S. allow Maryland utilities an opportunity to recover their stranded and transition costs, it also is et least discussing electric recommends that the state legislature reform tax laws to create a level playing field for all txtructuring, and more than a competitors while maintaining total tax revenues. donn have already approved Parallel to the PSC order, Maryland's General Assembly has created a legislative task force r: structuring or pilot programs mos ctive rogram a in C111fomia, where all customers will be able to choose their powIr suppliers this year, and We're seeking a level playing field l I P:nnsylvania, which began a From the beginning, BGE has had a voice in the restructuring debate in Maryland. While we cust:mer<hoice pilot program firmly believe the company and our shareholders can profit in a compe"dve energy supply last yIar. All Pennsylvania market BGE also believes restructuring is a complex process that must be done right the clectric customers will have the first time. ability to choose their suppliers Through our association with the Marylanders for Sensible Electricity Reform coalition, we y anuary On are strongly advocating a sensible and fair restructuring that does not hurt Maryland's environment, local charities, assistance to low-income citizens, or the state's economy. This voluntary coalition includes utilities, electric cooperatives, citizens, and businesses across Maryland. Among the coalition's goals is to ensure that the reliability of Maryland's electric system is not sacrificed, it also wants to protect the interests of Maryland utilities

shareholders in addition to these issues, many important questions still need to be decided as the debate continues in our state.

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Wo intend to be among the low-cost producers that will prosper 1 There's no getting around it. Price will be the first thing customers look at when they choose an electric supplier. That's why we've continued to work hard to drive down our electric-j / generation costs. And we've succeeded. Since 1992, we've lowered our generation costs ~ i by 23%, while increasing our electric production by 22% to meet growing customer demand. 1 I .Q h" We control costs For the third year in a row, BGE topped the list as the lowest cost electricity provider among the eight energy companies in our regional comparison group, the Pennsylvania-NewJersey-gy ' q Maryland (PJM) power pool. We've set even more aggressive goals for ourselves in the future. Here's what Controlling costs means getting the most value from our power plants. Every ycar this BGE Reduces injury Rate to Record Low decade, our fossil-plants have broken the previous year's record production (evels. Just since (Number of ounes per 200 employees) 1992 we've increased our total electric production from about 25 million megawatt-hours to just over 31 million megawatt-hours. In 1997 both our Calvert Cliffs Nuclear Power Plant and s.s _ _ __ _ ss _ A____ jointly owned Keystone fossil plant had their best production years ever. E,\\ ___ _ 4.s.__.. s We work productively Controlling costs also means our employees work productively. We've been cross-training our 3.s ____ _ _ _.--- - - - fossil-generation employees in both operations and maMtenance since 1995. A multi-skilled 3.0__...__...- 2.s _ work force allows any team on any shift to do whatever it takes to keep the plant running. 23 And that allows us to provide high-quality, low <:ost energy to customers. 1.s _. L_ is _. .~ PM gah h um m Ms W @@ h R's W @@ b & m .5. Duritig an extended heat wave last summer, customers set a new summer record for energy _._l_.. o_ _1994 1995 1996 1997 \\ Consumption. But most people never realized it. Because all of our generating units were 1993 SEIB BGE producing near 100%, we were able to meet customer demand and still have enough Aeft j n-Avmge or Edinan Electric institute over during the day to sell more than 10,000 megawatt-hours to our power pool. f,'. ember Compan6es (*1997 informanon not available) Employees' commitment to We work safely working safely has led to a 63% While we've reduced costs and improved productivity, our employees are working more safely rrduction in accidental injuries than ever. In the past five years our generation employees have reduced occupational injuries sincs 1993, consistently lower by more than 60%. In a 1996 Edison Electric Institute study BGE held the second-lowest than the average injury rate accidental injury rate among 14 comparable utilities, and our performance improved even among comparable companies, further in 1997. 12

l Some things you don't want to m learn the hard way-like how to operate a power plant. That's why we've invested in developing this state 4f-the-art simulated power-pient control room for our Brandon Shores, H.A. Wagner, and C.P. Crane 41ould Street energy complexes. It gives our piznt operators the closest thing to retHife situations without the risks, we're do'ng. We're helping set the model for a competitive bulk-power market BGE operates its transmission system as a member of the PJM, a power pool serving the Mid Atlantic region. As the electric.adustry evolves, power pools are changing how they do business. "We have seen the future, and the future is PJM" in a competitive bulk power market, there needs to be equal access to utility transmission systems. To accomplish this, we have been working wAh a group of PJM companies to restructure the transmission business to allow for open access. In November 1997 the Federal Energy Regulatory Commission (FERC) accepted the group's proposal. When FERC Chairman James Hoecker presented the order, he called it the model for the entire country, stating, "We have seen the future, and the future is PJM." Independent system operators wlH maintain reliability in the future the bulk transmission of electricity will continue to be regulated by FERC and operated regionally by independent system operators (ISO). The ISO's job wil! be to make sure the power reaches the local distribution company, which will deliver the power to its customers. The ISO's primary objective is to maintain system reliability by keeping supply and demand in balance at all times. 13

We're preparing for competition by improving the reliability of our distribution system in a competitive world, some things won't change. Even when customers can choose their energy supplier, the low utility will still deliver the power to their homes and businesses. And customers will still demand that their service is reliable and their energy needs are met. We've worked hard to improve the reliability of our distribution system and our services to customers. In these efforts we have made great strides. We've done it while lowering costs and improving our employee safety record, as well. We work to prevent outages in recent years we've redirected our focus from responding to outages to preventing them. That has helped us work smarter, manage our field crews better, and use the latest technology. And we've gotten results. Service interruptions have dropped 40% since 1994. We recognize our largest customers are the most at risk in a competitive world. In 1997 we increased our focus on improving reliability and power quality for industrial and commercial customers. As a result, for these customers we've reduced outages, including short-duration interruptions-or what we call momentaries-by 35% since 1995. Our efforts recently caught the attention of two industry organizations: the Southeastern Electric Exchange (SEE) and the Electric Power Research Institute (EPRI). SEE awarded us first prize in 1997 for Excellence in Engineering for our Distribution gutomation System. This sophisticated system helps us restore power remotely in minutes, greatly improving service reliability and restoration efforts. EPRI utility members recognized our Premium Power Program as the best utility power quality program in the U.S., presenting us with the coveted End-Use Leadership Award. Through this long-standing program, we've helped many industries and businesses-and ever' residences with PCs-prevent power disturbances that can cause everything from operational errors to equipment damage. Randle Cliff, in the southem end of our service area, is home to just over 1,000 BGE customers. Two years ago the reliability of its electric service was one of the worst in our system. Today we take pel6e in leaving boosted Randle Cliff into the list of top-s performing areas. Reconfiguring feeders, performing maintenance and tree trimming, and installing distribution automation, among other efforts, improved reliability of our electric service by 90% 3 R . s a g -m cV t 14

i l We've been expanding our gas business to meet growing demand. In 1997 we continued to open new areas for gas service, including southeaster Frederick County, Maryland, a region designated for residential development. It encompasses approximately 600 existing homes and 500 acres of land zoned for residential development. m x% .A We're already meeting the challenge of customer choice in our gas business While we're preparing for competition in the electric industry, we're already experiencing it in our gas business. Our industrial customers have had their choice of suppliers for more than a decade; our commercial customers since 1995. Now we are trying the concept with residential customers through a two-year pilot program, Gas Options. During this time as many as 25,000 customers will be able to choose their gas suppliers, while BGE continues to deliver the gas to their homes or businesses. Wa want to be the provider of choice With competition, we can't expect to retain 100% of the market share. But we're doing every-thing we can to become our custorners' provider of choice. And we expect to be able to succeed as more customers choose their gas suppliers. In 1996 the Maryland Public Service Commission allowed us to implement market based rates. This means our customers pay a price based on the market value of gas. When BGE buys below that price, both customers and the company share the profits. Market-based rates offer an added incentive to find and deliver gas at the lowest possible price. Last year, market-based rates increased our shareholders' earnings by $3.5 million and saved our gas customers the same amount. Wa're expanding gas service in our territory Even with competition we will continue to be the sole gas distributor to customers in our service territory. We see much potential for growth in the number of our gas customers. In 1997 we connected nearly 9,000 new homes to gas, improving our market share 11% over 1996. In addition we converted about 5,000 residential customers to gas heat, and added 2.2 million dekatherms of new industrial and commercial load. We've continued to improve our customers' satisfaction with their gas service, in 1997 our industrial and commercial customer satisfaction rating was 22% above the industry average. At the same time we've reduced operating costs per customer, increased the number of customers per employee, and improved our overall safety record. In fact, last year not a single employee in our gas division missed work as a result of injury. 15

En:rgy inductry dereguiction is paving tho way for now businocs cpportunitiso mm The future of the industry is energy marketing With competition comes risk. But in a competitive marketplace, risk and opportunity go hand-in-hand. Take the recent development of power marketing-the buying and L+ selling of energy on the open market. This industry didn't exist just a few years ago. Only in 1992 was the wholesale market-where bulk power is sold for resale-opened to competition. Now in a phase [ M-of exponential growth, power marketing has the potential to become the biggest O commodity market in the country. ~ Early last year we made the aggressive move to enter the power-marketing business, launching our Constellation Power Source subsidiary. Headquartered in Baltimore, 4( Constellation Power Source, through an exclusive advisory relationship, draws on the a risk-management and trading expertise of Goldman Sachs Power, an affiliate of one _ n 'q Q of the world's most prestigious investment banks, Goldman, Sachs & Co. 'N 4Dg 6 We're Nilding our assets g a Other irrestment opportunities are opening in the electric generation business. j Regulators have required some utilities to sell off their power plants. Other utilities have voluntarily opted to exit the generation business altogether. Tc take advantage of these developments and expand our power marketing business, we have again agreed to join Goldman Sachs in a new venture, in January 1998 we signed a letter of intent to form a company to buy power plants in the United States. This move will improve the market presence of two 4A. of our subsidiaries: Constellation Power Source will be the exclusive provider of W power-marketing and risk-management services, while Constellation Operating h Services will provide the exclusive operations and maintenance services for A 12G ' acquired facilities. Constellation Power Source now We're developing foreign and domestic niche energy markets has nearly 60 people marketing On the international front, BGE's Constellation Power-our independent power subsidiary-and trading power nationally has been active in Latin America. As countries privatize their electric generation and distribu-from its Baltimore headquarters. tion systems to meet growing demand, the governments have turned to foreign investors with Our new power <narketing energy experience. Constellation Power now has interests in 10 energy projects in seven Latin business offers wholesale American countries-Argentina, Bolivia, Brazil, Costa Rica, Cura ao, Guatemala, and Peru. energy customers creative eMMPm&epdhmmWheW@m@MA and costeffective solutions t ex anding its energy investments to 26. Among new projects, it began developing a site for a complex energy problems while helping them manage the risk of fluctuating energy prices, when it purchased a coal-pulverizing plant in Gary, Indiana, to supply U.S. Steel's Gary plant. Our future is in energy in a competitive world the low-cost produce: all prosper. So, too, will the energy marketers who will buy and sell all forms of energy. We have positioned ourselves to take advantage of both. As we move forward, we will continue to explore opportunities that allow us to do what we do best-producing and marketing energy and the products and services supporting that business. 16

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Utility Operating Ctatistiac Compound 1997 1996 1995 1994 1993 Growth 5 Year 10LYear Electric Operating Statistics ' Revenues (In Millions) Residential $ 932.5 $ 958.7 $ 955.2 $ 931.7 $ 931.7 2.11% 4.61% Commercial 892.6 861.3 879.4 853.0 869.8 1.16 3.88 Industrial 211.9 207.6 208.5 205.6 199.0 0.96 1.59 System Sales 2,037.0 2,027.6 2,043.1 1,990.3 2,000.5 1.57 3.93 Interchange and Other Sales 132.7 155.9 167.0 118.0 91.5 15.59 15.14 Other 22.3 25.5 21.0 19.1 20.1 6.08 2.00 Total $2,192.0 $2,209.0 $2,231.1 $2,127.4 $2,112.1 2.20 4.32 - S111s (In Thousands)--MwH Residential 10,806 11.243 10,966 10,670 10,614 2.11 2.40 Commercial 12,718 12,591 12,635 12,351 12,395 1.32 2.42 Industrial 4,575 4,596 4,591 4,433 3,763 4.55 1.25. System Sales 28,099 28,430 28,192 27,454 26,772 2.12 2.21 Interchange and Other Sales 6,224 7,580 8 149 5,684 4.149 14.37 17.26 2 Total _34,323 36,010 36,341 33,138 30,921 3.80 3.71 Customers (In Thousands) Residential. 1,001.0 995.2 988.2 978.6 968.2 0.91 1.33 Commercial 105.9 104.5 103.4 101.9 100.8 1.21 1.74 Industrial 4.5 4.3 4.1 4.0 3.8 3.44 6.05 Total- _1r111.4 1,104.0 1,095.7 1,084.5 1,072.8 0.95 1,39 - Average Use per Residential Customer--KWH 10,794 11,297 11,097 10,903 10,963 1.18 1.06 Average Rate per nwH (System Sales)-4 Residential 8.63 8.53 8.71 8.73 8.78 0.00 2.16 Commercial 7.02 6.84 6.96 6.91 7.02 (0.17) 1.43 4.83 4.52 4.54 4.64 5.29 (3.42) 0.33 . Industrial. Peak Load (One-Hour)--uw 5,980 5,955 5,947 6,038 5,876 1.47 1.43 Capability at Summer Peak-ww 6,741 6,800 6,731 6,722 6,701 0.16 1.36 System Load Factor 56.9% 57.5% 57.2% 54.7% 55.2% 0.75 0.67 Cas Operating Statistics R; venues (In Millions) Residential -Excluding Delivery Service $321.7 $320.1 $248.3 $262.7 $265.6 5.80 2.88 --Delivery Service 0.5 Commercial-Excluding Delivery Service 113.5 125.1 109.9 121.0 121.8 0.23 0.28 -Delivery Service 12.9 7.2 3.7 2.3 3.3 29.08 14.96 industrial -Excluding Delivery Service 11.4 17.1 16.7 20.2 22.3 (11.59) (5.42) -Delivery Service 17.2 14.6 16.3 9.6 12.9 3.76 (1.64) System Sales 477.2 484.1 394.9 415.8 425.9 3.91 1.88 Off-Systera Sales 37.5 26.6 Other 6.9 6.6 5.6 5.4 7.3 1.20 (9.87) Total $521.6 $517.3 $400.5 $421.2 $433.2 5.43 2.30 Stlss (In Thousands}-oTH Residential -Excluding Delivery Service 39,958 43,784 40.211 40,279 40,029 0.46 0.47 -Delivery Service 205 Commercial-Excluding Delivery Service 18,435 22,698 23,612 23,712 23.830 (4.72) (1.12) -Delivery Service 12,964 8,755 6,982 6,490 7,428 12.79 9.41 Industrial -Excluding Delivery Service 2,016 2,887 4,102 4,410 5,298 (17.62) (6.71) -Delivery Service _ _38 791 36,201 35J25 33,837 31,390 2.89 1.08 / System Sales 112,369 114,325 110,832 108,728 107,975 0.69 0.88 Off-System Sales ,,_17,611 10 204 Total _129 980 124,529 110,832 108,728 107,975 3.66 2.36 g Customers (In Thousands) Residential 524,5 516.5 506.8 498.2 491.2 1.50 0.85 Commercial 39.3 38.9 38.4 37.9 37.5 1.21 1.22 industrial 1.3 1.3 1.3 1.3 1.3 (1.47) 0.00 Total 565.1 556.7 546.5 537.4 530.0 1.47 0.87 Average Use per Residential Customer-Therms 762 848 794 809 815 (1.02) (0.37) Average Rate per Therm--$ Residential (Excluding Delivery Service) .81 .73 .62 .65 .66 5 49 2.38 Commercial (Excluding Delivery Service) .62 .55 .47 .51 .51 5.25 1.39 Industrial (Excluding Delivery Service) .57 .59 .41 .46 .42 7.34 1.52 P:ak Day Sendout (in Thousands)-0TH 765.0 709.0 706.3 761.9 657.7 4.66 1.86 ' f>eik Day Capability (In 7housandsFoTH 870.0 870.0 847.0 847.0 847.0 0.54 1.76 Utility operatirlg statistics do not reflect the elimination ofintercompany transactions. 18 Baltimore Gas and Dectric Company and Subsidianes

j Selected Financirl Data Compound 1997 1996 1995 _1994 1993 Growth (Dollar amounts in millions, except per share amounts)

5. Year 10+ Year Summary of Operations.

Total Revenues $3,307.6 $3,153.2 $2,934.8 $2,783.0 $2.741.4 5.26% 5.47% i Expenses Other Than Interest and income Taxes _2,584 8 2 483.7 2J39.1 2,147.7 2 125.0 5.00 6.22 1 1 L - Income Frt.m Operations 723.6 669.5 695.7 635.3 616.4 6.21 3.21 Other income (Expense) _,_152.81 6.1 8.8 32.3 20.3_ income Before interest and income Taxes 670,8 675.6 704.5 667.6 636.7 3.77 2.07 Net interest Expense 230.0 198.5 197.0 190.1 188.8 3.93 7.10 Income 8efore income Taxes 440.8 477.1 507.5 477.5 447.9 3.69 0.24 income Taxes _ _150.0 166.3 _169.5 153.9 138.1_ 8.87 1.94 Net income 282.8 310.8 338.0 323.6 309.8 1.36 (0.59) ( Preferred and Preference Stock Dividends _ 28.7 $ 297.4 $ 283.7 $ 268.0 2.73 (0.74). 38.5 40.6 ._ 39.9 41.8_ (7.42) 0.84 Etrnings Applicable to Common Stock $ 254.1 $ 272.3 Earnings' Ser Share of Common Stock $1.72 $1.85 $2.02 $1.93 $1.85 1.08 (2.91) Dividends Declared Per Share of Common Stock $1.*83 $1.59 $1.55 $1.51 $1.47 2.65 2.69 Ratio of Earnings to Fixed Charges 2.78 3.10 3.21 3.14 3.00 0.96 (3.97) l Ratio of Earnings to Fixed Charges and Preferred (nd Preference Stock Dividends Combined 2.35 2.44 2.52 2.47 2.34 2.47 (3.22) l l Financial Statistics at Year End Total Assets $8.773.4 $8.544.3 $8.277.6 $7.995.9 $7,829.6 4.01 6.26 Capitalization l Long-term debt $2,988.9 $2,758.8 $2,598.2 $2,584.9 $2,823.1 4.69 5.76 l Preferred stock 59.2 59.2 59.2 Redeemable preference stock 90.0 134.5 242.0 279.5 342.5 (25.63) (7.02) Preference stock not subject to mandatory l redemption 210.0 210.0 210.0 150.0 150.0 13.81 6.68 Common shareholders' equity _2 870.4 2J54.7 2.811.2 2.1719.0 2,620.5, 2.52 5.04 t 1 Total Capitalization $6,169.3 $5.958.0 $5.920.6 $5.792.6 $5,995.3 2.38 4.90 Book Value Per Share of Common Stock $19.44 $19.33 $19.06 $18.43 $17.94 1.97 2.74 Number of Common Shareholders (In Thousands) 73.7 77.6 79.8 81.5 82.3 (1.73) (1.10) Czrt:in priortear amounts have been reclassified to conform with the current year's presentation. l D' I jl 6 t l B;ltirrore Gas and Electric Company and Subsidiaries 19 _.______ ___________ ____ - - _ w

Manag; ment'c Discussion and An:Iysia of Financial Condition and Results of Operations introducthm The electric utility industry is undergoing rapid and substantial In Management's Discussion and Analysis we explain the general change. Competition sn the generation part of our business is financial condition and the results of operations for BGE and its increasing. The regulatory environment (federal and state) is diversified business subsidiaries including: shifting toward customer choice. These matters are discussed g what factors affect our businesses, briefly in the " Competition and Response to Regulatory Change" c what our eamings and costs were in 1997 and 1996, section beginning on page 21. They are discussed in detail in a why eamings and costs changed from the year before, our Annual Reports on Form 10-K. O wnere our earnings came from, We continuously evaluate changes in the utility industry. Based o how all of this affects our overall financial condition, n the evaluations, we refine short and long term busir.ess a what our expenditures for capital projects were in 1995 plans. We may also enter new businesses, which may be through 1997 and what we expect them to be in 1998 opp rtunties to: through 2000, and - D 'where we will get cash for future capital expenditures, a provide our core energy business customers more services, or e attract new customers for our core energy business, or As you read Management's Discussion and Analysis, it may be a expand our diversified stream of revenues. helpful to refer to our Consolidated Statements of Income on page 31, which present the results of our operations for 1997, 199S, and 1995. In Management's Discussion and Analysis, we analyze and explain the annual changes in the specific line items in the Consolidated Statements of income. Our analysis . may be important to you in making decisions about your investments in BGE. Cesults of Operations in this section, we discuss our 1997 and 1996 eamings and the downs in the "Real Estate Development and Senior-Living factors affecting them. We begin with a general overview, then Facilities" section on page 27. separately discuss earnings for the utility business and for in 1997, utility earnings from current-year operations were lower diversified businesses. weather (people use less electricity and gas to heat or cool their Overview homes in milder weather). We discuss our utility earnings in more detail in the ' Utility Business" section beginning on page 21 T:t:1 Eamings per Share of Common Stock In 1997, diversified business eamings from current-year opera-1997 1996 1995 tions were higher mostly because the Constellation Holdings Earnings per share from Companies had higher eamings from power generation projects current-year operations: and financial investments. We discuss our diversified business Utility business $1.94 $1.96 $1.84 "E Diversified businesses (subsidiaries) .34 .31 .18 beginning on page 26. Total earnings per share from current-year operations 2.28 2.27 2.02 1996 Write off of merger costs (see Note 12) (.25) Our 1996 total earnings decreased $25.1 million, or $.17 per Writedowns of real estate share, from 1995. Our total earnings decreased because we investments (see Note 12) (.31) wrote off disallowed replacement energy costs. We discuss this Disallowed replacement in detail in the

Disallowed Replacement Energy Costs" section energy costs (see Note 12)

(.42) on page 23. Total earnings per share $1.72 $1.85 $2.02 in 1996, utility earnings from operations were higher due to three factors: we sold more electricity and gas due to colder 1997 winter weather, there was an increase in the number of Our 1997 total eamings decreased $18.2 million, or 5.13 per customers, and we had lower operations and maintenance share, from 1996. Our total earnings decreased because: expenses. We would have had even higher utility camings from a we wrote off costs associated with the proposed merger operations except we sold less electricity in the third quarter due to milder summer weather, with Potomac Electric Power Company, and c Constellation

Holdings, Inc. and Subsidiaries (together in 1996, diversified business eamings were higher mostly because I

known as the Constellation Holdings Companies) wrote the Constellation Holdings Companies had highe. eamings from down their investments in two real estate projects. power generation projects and financial investments. We discuss the write-off of merger costs in the " Write-Off of l Merger Costs" section on page 25, and the real estate write-20 Battimore Gas and Electric company and Subsidianes J

Utility Budnoco Before we go into the details of our electric and gas operations, During the cooling season, hotter weather is measured by more we believe it is important to discuss four factors that have a cooling degree days and results in greater demand for electricity strong influence on our utility busir,ess performance: regulation, to operate cooling systems. During the heating season, colder the weather, other factors including the condition of the economy weather is measured by more heating degree days and results in in our service territory, and competition, greater demand for electricity and gas to operate heating systems. l Rrgulation by the Maryland Public Service Commission (Miryland PSC) We show the number of cooling and heating degree days in 1997 The Maryland PSC determines the rates we can charge our and 1996, the percentage changes in the number of degree days customers. Our rates consist of a " base rate" and a " fuel rate." from prior years, and the number of degree days in a " normal" The base rate is the rate the Maryland PSC allows us to charge year as represented by the 30-year average in the following table. our customers for the cost of providing them service, plus a profit. We have both an electric base rate and a gas base rate. 30 Year 1997 1996 Average Higher electric base rates apply during the summer when the demand for electricity is the highest. Gas base rates are not Cooling degree days 746 786 804 affected by seasonal changes. Percentage change from prior year (5.1)% (25.6)% The Maryland PSC allows us to include in base rates a Heating degree days 4,822 5,138 4,901 component to recover money spent on conservation programs. Percentage change from prior year (6.2)% 11.7% This component is called an " energy conservation surcharge." However, under this surcharge the Maryland PSC limits what our Other Factora profit can be. If, at the end of the year, we have exceeded our Other factors, aside from weather, impact the demand for elec-allowed profit, we lower the amount of future surcharges to our tricity and gas. These factors include the " number of customers" customers to correct the amount of overage, plus interest. and " usage per customer" dunng a given period. We use these terms later in our discussions of electric and gas operations. In in addition, we charge our electric customers separately for the those sections, we discuss how these and other factors affected fuel we use to generate electricity (nuclear fuel, coal, gas, or oil) electric and gas sales during 1997 and 1996. and for the net cost of purchases and sales of electricity (primarily wi*h other utilities). We charge the actual cost of these The number of customers.in a given period is affected by new items to the customer with no profit to us. We discuss this in home and apartment construction and by the number of more detail in the

Electric Fuel Rate Clause" section on page 23 businesses in our service territory.

and in Note 1. Usage per customer refers to all other items impacting customer We also charge our gas customers separately for the natural gas sales which cannot be separately measured. These factors they consume. The price we charge for the natural gas is based include the strength of the economy in our service terntory, on a market based rates incentive mechanism approved by the When the economy is healthy and expanding, customers tend Maryland PSC We discuss market based rates in more detail in to consume more electricity and gas. Conversely, during an the " Gas Cost Adjustments" section on page 24 and in Note 1. economic downtrend, our customers tend to consume less electricity and gas. From time to time, when necessary to cover increased costs, we ask the Maryland PSC for base rate increases. The Maryland PSC holds hearings to determine whether to grant us all or a Competition and Response to Regulatory Change portion of the amount requested. The Maryland PSC has histori-Our electric and gas businesses are also af fected by Cally allowed us to increase base rates to recover costs for competition. We discuss competition in each business below. replacing utility plant assets, plus a profit beginning at the time Electric Business of replacement. Generally, rate increases improve our utility earn-ings because they allow us to collect more revenue. However, Electric utilities are facing competition on various frontt, rate increases are normally granted based on historical data and including: those increases may not always keep pace with increasing costs, a in the construction of generating units to meet increased demand for electricity, Wsather a in the sale of their electricity in the bulk power markets, Weather affects the demand for electricity and gas, especially a in competing with alternative energy suppliers, and among our residential customers. Very hot summers and very cold winters increase demand. Mild weather reduces demand. a in the future, for electric sales to retail customers which Utilities now serve exclusive!y. We measure the weather's effect using " degree days." A degree day is the difference between the average daily actual We regularly reevaluate our strategies with two goals in mind: to improve our competitive position, and to anticipate and adapt to temperature and a baseline temperature of 65 degrees. Cooling regulatory changes. We cannot predict the ultimate effect degree days result when the daily actual temperature exceeds the 65 degree baseline. Heating degree days result when the competition or regulatory change will have on our eamings. daily actual temperature is less than the baseline. We discuss competition in our electric business in more detail in our Annual Reports on Form 10-K under the heading " Electric Regulatory Matters and Competition." Baltimore Gas and Dectric Company and Subsidiaries 21

Sectric System Sales bklumen Gas Boninese Regulatory chings in the natural gas industry is well und:r way. " Electric system sales" are sales to customers in our servics We discuss competition in our gas business in more detail in our territory at rates set by the Maryland PSC. These sales do not Annual Reports on Form 10LK under the heading " Gas Regulatury include interchange sales and sales to others. Matters and Competition." The percentage changes in our electric system sales volumes, by type of customer, in 1997 and 1996 compared to the respective Sim @ prior year were: W3 will continue to develop strategies to keep us competitive. 1997 1996 These strategies might include one or more of the following: Residential (3.9)% 2.5% o the complete or partial separation of our generation. Commercial 1.0 (0.3) transmission, and distribution functions, Industrial (0.4) 0.1 a purchase or sale of generation assets, in 1997, we sold less electricity to residential customers mostly ci mergers or acquisitions of utility or norvutility businesses, for two reasons: lower electricity usage per customer and milder a ' pirvoff or sale of one or more businesses, weather. We sold more electricity to commercial customers s We cannot predict whether any transactions of the types mostly because usage per customer increased. We would have described above may actually occur, nor can we predict what their sold even more electricity to commercial customers except for effect on our financial condition or competitive position might be, milder weather during the year. We sold about the same amount of electricity to industrial customers as we did in 1996. in 1996, we sold more electricity to residential customers for Utility Business Earnings per Share of Common Stock three reasons: colder weather in the first quarter, greater 1997 1996 1995 electricity usage per customer, and an increase in the number j LTdlity earnings per share from of customers. We would have sold even more electricity to residential customers except for milder summer weather. We current-year operations: Electric business $1.77 $1.75 $1.70 sold about the same amount of electricity to commercial and . Gas business .17 .21 .14 industrial customers as we did in 1995. I Total utility earnings per share Weather impacts residential, more than commercial and industrial, from current-year operations 1.94 1.96 1.84 sales, in 1997 and 1996, other items offset the impact of weather Writeoff of merger costs (see on commercial and industrial sales. Other items included the f Note 12) (.25) demand for power to fuel manufacturing equipment and office Disallowed replacement machinery, which vary with changes in the customers' businesses, (.42) energy costs (see Note 12) Total utility earnings per share $1.69 $1.54 $1.84 Sales of Electricity Our 1997 total utility eamings increased $24.0 million, or $.15 per share, from 1996. Our 1996 total utility eamings decreased i4 $44.5 million, or $.30 per share, from 1995. We discuss the factors affecting utility earnings below. 12 _.__ _~ 10 - -p -.? -- J -- ? - 1 Electric Operations a h - h Electric Revenues 6 __ f _. -._e l The changes in electric revenues in 1997 and 1996 compared to g k 4 .I e t l . th@ respective prior year were caused by: 4 -._J w l 1997 1996 [ ~ ~} ~f }l 2~ l 0 m} t a L (In millions) Electric system sales volumcc $(15.5) $ 0.3 1993 1994 1995 1996 1997 Base rates 29.2 (2.5) Full rates (4.3) (12.3) '*I Total change in electric revenues "" C""*I*l from electric system sales 9.4 (14.5) Int:rchange and other sales (23.2) (11.1) muuindustrial Other (3.2) 4.5 1 Total change in electric revenues $(17.0) $(21.1) L l \\ 1 I l t 22 Bartimore Gas and Electric Company and subsidiaries

. Base Rates Electric Fuel and Pur hased Energy Expenses In 1997, base rats revenu:s w:re higher than they were in 1996 because of higher energy r, observation surcharge revenues. 1997 1996 1995 During 1996, we exceeded our profit limit under the snergy (in millions) conservation surcharge. As a result, we excluded $28.5 million Actual costs $504.5 $539.2 $554.5 of our 1996 surcharge billings from revenue. To correct the Net recovery of costs overage, we lowered the surcharge on our customers' bills under electric fuel beginning in July 1997 and will continue to bill the lower surcharge through June 1998. rate clatse (see Note 1) 15.2 8.2 24.3 Disallowed replacement energy in 1996, base rate revenues were about the same as they were costs (including carrying in 1995. Although we sold more electricity in 1996, our revenues charges)(see Note 12) 95.4 did not increase because the higher sales occurred during the Total electric fuel and winttr when our base rates are lower. purchased energy expenses $519.7 $642.8 $578.8 e FueWatee Actual Coets Th3 fuel rate is the rate the Maryland PSC allows us to charge in 1997, our actual costs of fuel to generate electricity (nuclear our customers, with no profit to us, for; fuel, coal, gas, or oil) and electricity we bought from others were s D our actual cost of fuel used to genera *.e electricity, and lower than in 1996 mostly for two reasons: we bought less elec-I c the net cost of purchases and sales of electricity (primarily tricity from & er utilities because we were ele to meet demand with other utilities). Using the electricity we generated, and we were able to use a less costly mix of generating plants mostly because of shortu . If these costs go up, the Maryland PSC permits us to increase refueling and maintenance downtime at Calvert Cliffs. the fuel rate. If these costs go riown, our customers benefit from a reduction in the fuel rate. The fuel rate is impacted most by the in 1996, our actual costs were lower than in 1995 because the amount of electricity generated at our Calvert Cliffs Nuclear g g g Power Plant (Calvert Cliffs) because the cost of nuclear fuel is lower and we sold less electricity. The price we pay for electricity cheaper inan coal gas, or oil. We discuss the calculation of the and capacity we buy from other utilities changes based on fuel rate in Note 1. rr.arket conditions, complex pricing formulas for PJM transactions, and contract terms. Chariges in the fuel rate normally do not affect earnings, How ver, if the Maryland PSC disallows recovery of any part of Electric fuel Rate Clause the fuel costs, our eamings are reduced. We discuss this more Under the electric fuel rate clause, we defer (include as an asset thoroughly in the " Disallowed Replacement Energy Costs' section or liability in our Consolidated Balance Sheets and exclude from b3 low and in Note 12. our Consolidated Statements of Income) the difference between in 1997, fuel rate revenues decreased mostly because we sold our actual costs of fuel and energy and what we collect from less electricity. In 1996, fuel rate revenues decreased due to a customers under the fuel rate in a given penod. We either bill or lowar fuel rate because we were able to operate plant 3 with the refund our customers that difference in the future. We discuss lowest fuel costs. Fuel rate revenues would have been even lower the calculation of the fuel rate in Note 1. except 'we sold more electricity. In 1997 and 1996, our actual costs of fuel and energy were lower than the fuel rate revenues we collected from our customers. Interchange ami Other Sales

interchange and other sales" are sales in the Pennsylvania-Disallowed Replacement Energy Costs New Jersey-Maryland Interconnection (PJM) energy market and to in December 199S, we settled fuel rate proceedings about others. PJM is a regional power pool with members that include extended outages that occurred at Calvert Cliffs in 1989 through miny wholesale market participants, as well as BGE and seven 1991. We agreed not to bill our customers for $118 million of other utility companies. We sell energy to PJM members and electric replacement energy costs associated with these outages.

to others after we have satisfied the demand for electricity We wrote off a portion of these costs in 1990 and wrote off the in our own system. remaindri in 1996. We discuss this further in Note 12. In 1997, we had lower interchange and other sales comiared to 1996 mostly Decause of lower sales volumes due to reduced demand. In 1996, we had lower interchange and other sales compared to 1995 because we generated less electricity at Calvert Cliffs. This meint that we had less electricity to sell outside of our service 1:rritory. We generated less electricity at tr.at plant mostly because the 1996 outage for regular refueling and maintenance l took longer than in 1995. l-BIltimore Gas and Electric Company and Subsidiaries 23

Base Rates Cza Cperations in 1997, base rate revenues were higher than they were in 1996. Although we sold less gas in 1997, our base rate he chan gas revenues in 1997 and 1996 compared to the revenues increased because of a higher energy conservation respective prior year were caused by: surcharge in the last six months of the year. 1997 1996 in 1996, base rate revenues were higher than in 1995 because (in millions) in November 1995, the Maryland PSC allowed us to increase our I Gas system sales volumes $(7.3) $ 8.2 gas base rates. This increased our annual base rate revenues for Bne rates 0.6 18.9 1996 by $19.3 million. That amount included $2.4 million to Gas cost adjustments (0.2) 62.1 recover higher depreciation expense (an accounting procedure Total change in gas revenues which spreads the cost of utility plant in service over the years in from gas system sales (6.9) 89.2 which it is used). Off system sales 10.9 26.6 Other' O.3 1.0 During 1997, we applied for a $36.7 million increase in our gas Total change in gas revenues $ 4.3 $116.8 base rates. The Maryland PSC is currently reviewing our application. and is expected to issue an order by June 1998. Our earnings will be impacted during 1998 and 1999 by the outcome of this case. Gas System Sales Molumes The percentage changes in our gas system sales volumes, by Gas Cost A(fustments typ3 of customer, in 1997 and 1996 compared to the respective We charge our gas customers for the natural gas they consume prior year were: using gas cost adjustment clauses set by tne Maryland PSC. 1997 1996 These clauses operate similar to the electric fuel rate clause Residential (8.3)% 8.9% desenbed in the " Electric Fuel Rate Clause" section on page 23. Commercial (0.2) 2.8 However, effective October 1996, the Maryland PSC approved a Industrial 4.4 (2.3) modification of these clauses to provide a market based rates incentive mechanism. Under market based rates, our actual cost of In 1997, we sold less gas to residential customers mostly for two reasons: lower usage per customer and milder weather. We sold gas is compared to a ma,ket index (a measure of the market price about the same amount of gas to commercial customers as we did of gas in a given period). The difference between our actual cost and the market index is shared equally between BGE (which bene-in 1996. We sold more gas to industrial customers mostly because fits shareholders) and customers. We also discuss this in Note 1. the milder weather caused fewer service interruptions and Bethlehem Steel (our largest customer) used more gas. We would Delivery service customers, including Bethiehem Steel, are have sold even more gas to industrial customers except gas usage not subject to the gas cost adjustment clauses because we by industrial customers other than Bethlehem Steel decreased, are not selling them gas (we are selling them the service of in 1996, we sold more gas to residential and commercial delivering their gas), customers due to colder winter and early spring weather and an in 1997, gas cost revenues decreased mustly because we sold increase in the number of customers. We would have sold even less gas. In 1996, gas cost revenues increased because we had more gas to those customers except that gas usage per to pay more for gas and we sold more gas, customer decreased. We sold less gas to industrial customers because Bethlehem Steel used less gas. We would have sold OffSystem Sales even less gas to industrial customers except for ircrresed gas Off-system gas sales, which are low-margin direct sales to whole-usage by other industrial customers, an increase in the number sale suppliers of natural gas outside our service territory, are not of customers, and colder winter weather. Subject to gas cost adjustments. We began sales of off-system gas during the first quarter of 1996. The Maryland PSC approved Sales of Gas an arrangement for part of the earnings from off-system sales to (Millions of Dekatherrns) benefit customers (through reduced costs) and the remainder to be retained by BGE (which benefits shareholders). 50 _. --- -- ~- -~ In 1997 and 1996, off-system gas sales increased mostly because we first began off-system sales of gas in February of 40 _ l_ _ _ _f_ A _ [. k 1996. These increases in off system sales did not significantly 30 -- j impact eamings. 20 J N Gas Purchased For Resale Expenses i 10 g 4 1997 1996 1995_ 0. (In millions) 1993 1994 1995 1996 1997 Actual costs $291.6 $295.4 $205.9 Net recovery (deferral) of we Residential costs under gas adjustment mum Commercial clauses (see Note 1) 0.5 (11.0) (7.8) men Industrial Total gas purchased for resale expenses $292.1 $284.4 $198.1 24 Baltimore Gas and Doctric Company and subsidiaries - a

) Actual Costs Othtr incoms and Expenses Actual costs include the cost of gas purchased for resale to our Write 4ff of Merger Costs l customers and for sale off-system. Actual costs do not include l the cost of gas purchased by delivery service customers, in September 1995 we signed an agreement with Potomac l including Bethlehem Steel. Electric Power Company to merge together into a new company, l Constellation Energy Corporation, after all necessary regulatory l In 1997, actual gas costs decreased from 1996 mostly because approvals were received, in December 1997, both companies I we sold less gas. In 1996, actual gas costs increased from mutually terminated the merger agreement. Accordingly, in 1997, i I 1995 due tc three factors: higher market prices of gas, higher we wrote off $57.9 million of costs related to the merger. This j l sales volumes, and the purchase of gas to resell off-system write-off reduced after-tax earning by $37.5 million, or $.25 per (beginning in the first quarter of 1996), share. We also discuss the writeoff of these costs in Note 12. Gas A(ustment Clauses Allowance for Funds Used During Construction (AFC) We charge customers for the cost of gas sold through gas adjust. We finance construction projects with borrowed funds and equity j ment clauses (determined by the Maryland PSC), as discussed funds. We are allowed by the Maryland PSC to record the cost of

e j

under " Gas Cost Adjustments" earlier in this section, these funds as part of the cost of construction projects in our { Consolidated Balance Sheets. We do this through the AFC, which l In 1997, the portion of our actual gas costs subject to these we calculate using a rate authorized by the Maryland PSC, We bill clauses was lower than the revenues we collected from our our customers for the AFC plus a retum after the utility plant is customers. In 1996, the portion of our actual gas costs subject placed in service. We also describe AFC in Note 1. to these clauses was higher than the revenues we collected from our customers. In 1997, AFC was about the same as it was in 1996. In 1996, we had lower AFC compared to 1995 because we completed several projects and started less new construction. We also had Other Operating Expenses I wer AFC because the Maryland PSC decreased the gas AFC rate in November 1995 from 9.40% to 9.04A Operations and Maintenance Expenses in 1997, our operations and maintenance expenses were slightly Net Other income and Deductions lower than they were in 1996. Net other income and deductions represent miscellaneous income in 1996, our operations and maintenance expenses decreased and expenses which are not directly related to operations. $18.5 million due to our continued efforts to control costs. This in 1997, net other income and deductions were ebout the same decrease would have been even greater except we had higher as they were in 1996. In 1996, net other income and deductions costs to maintain our nuclear plant. increased $4.9 mimon compared to 1995 mostly because the Constellation Holdings Companies had lower deductions not Depreciation and Amortization Expenses directly related to operations and BGE had about $2 million more We describe depreciation and amortization expenses in Note 1. of other interest and finance charge income. In 1997, our depreciation and amortization expense increased $12.7 million from 1996 mostly because we had more plant in nterc cha epresent the interest we paid on outstanding debt. service (as our level of plant that is in service changes, the amount of our depreciation and amortization expense changes). In 1997, we had $23.6 million hgher interest charges compared in 1996, our depreciation and amortization expense increased to 1996 because we had more debt outstanding and interest $12.8 million from 1995 because we had more utility plant in r tes were higher. service, and we had more energy conservation program costs in 1996, we had $2.1 million lower interest charges compared to to be amortized. 1995 largely because of lower interest rates. We would have had The increase in 1996 expenses would have been even greater even lower interest charges except we had more debt outstanding. except that in 1995 depreciation and amortization expense included Income Taxes !>14.2 million for the writeoff of costs associated with planned future generation facilities at our Perryman site that will not be built. In 1997 out income taxes decreased because we had lower We discuss this writeoff also in Note 1. In 1996, depreciation and taxable income from both our utility operations and our diversified businesses, amortization expense did not include any such writeoff, in 1996 our income taxes decreased because we had lower T;xes Other Than inconte Taxes taxable income from utility operations. Our income taxes would in 1997, taxes other than income taxes were about the same as have been even lower except that we had higher taxable income they were in 1996. from our diversified busin. 3ses. - in 1996, taxes other than income taxes were $9.6 million higher than in 1995 mostly due to three factors: plant additions made in 1995 increased our property taxes about $7 million, higher 1996 revenues increased our gross receipts taxes about $2 million, and higher labor costs increased our payroll taxes about $1 million. l l r Baltimore Gas and Electric Company and Subsidianes 25 1 ]

Diversified Businesses Power Generation The Constellation Holdings Companies' power g:nsration busi-In the 1980s, we began to diversify our business in response to ness develops, owns, and operates domestic and intemational limit:d growth in gas and electric sales. Today, we continue to power generation projects. We discuss international projects later diversify our business in response to regulatory changes in the in this section. utility industry. Some of our diversified businesses are related in 1997, eamings increased from 1996 mostly because of to our core utility business and others are not. Our diversified improved performance of various energy projects. businesses are organizej in three groups: in 1996, earnings increased from 1995 mostly due to our share c the Constellation Holdings Companies-our power genera, of higher eamings from energy projects and a $14.6 million after-tion, financial investments, and real estate businesses, tax gain on the sale by a Constellation partnership of a power a Constellation Energy Solutions, Inc. and Subsidiaries-purchase agreement with Jersey Central Power & Light Company our energy marketing businesses, and back to that utility. Energy projects had higher earnings for a c BGE Home Products & Services Inc. and Subsidiaries-variety of reasons-some ongoing (like improved efficiency due to our home products and commercial building systems equipment or procedure changes) and some onetime (for businesses' example, losses incurred in 1995--to shut down certain opera-tions at a plani-did not occur again in 1996). These increases were offset by $16.2 million of writeoffs of investments in certain ~ Div:rsiflu) Business Eamings Per Share of Common Stock power projects. We describe these writeoffs further in Note 3. 1997 1996 1995' CaWomia Power Purchase Apoements Constellation Holdings Companies 6.39 $.29 $.18 The Constellation Holdings Companies have $261 million Constellation Energy Solutions (.08) .00 .00 invested in 16 projects that sell electricity in Califomia under BGE Home Products & Services .03 .02 .00 power purchase agreements called " Interim Standard Offer No. 4' Total diversified business earnings per agreements. Eamings from these projects were $37.3 million, or share from currenttear operations .34 .31 .18 Write-downs of real estate investments Under these agreements, the electricity rates change from fixed by the Constellation Holdings rates to variable rates during 1996 through 2000. The projects Companies (see Note 12) (.31) which already have had rate changes have lower revenues under Total diversified business variable rates than they did under fixed rates. When the eamings per share $.03 $.31 $.18 remaining projects transition to variable rates, we expect their reverwes also to be lower than they are under fixed rates. Our 1997 diversified business eamings decreased $42.2 million, However, the California projects that make the highest revenues or $.28 per share, from 1996. Our 1996 diversified business will transition in 1999 and 2000. As a result, we do not expect earnings increased $19.3 million, or $.13 per share, from 1995. the Constellation Holdings Companies to have significantly lower These changes came mostly from the Constellation Holdings earnings before 2000 due to the transition to veiable rates. We Companies. We discuss factors affecting the earnirgs of our cannot predict the financial effects of the transition from fixed to diversified businesses below, variable rates on the Constellation holdings Companies or on BGE, but the effects could be material. The Constellation Holdings Companies-We describe these projects and the transition process in detall Our Power Generation, Financial investments, in Note 12. and Real Estate Businesses The Constellation Holdings Companies: Informational The Constellation Holdings Companies' power generation a develop, own, and operate power generation projects, business in Latin America: o engage in financial investments, and a develops, acquires, owns, and operates power generation o develop, own, and manage real estate and senior-living projects, and facilities, a acquires and owns dlstribution systems. Earnings per Share from the Constellation Holdings Companies At December 31,1997, the Constellation Holdings Companies had were: 1997 1996 1995 invested about $23.1 million and cammitted another $4.3 million Power generation $.25 $.18 $.13 in power projects in Latin America. In the future, the Constellation Financial investments .18 .14 .08 Holdings Companief power generation business may be expanding further in both domestic and international projects. Real estate development and senior-living facilities (.01) (.02) (.02) Other , (.03) (.01) (.01) . Total Constellation Holdings Companies' earnings per share from currenttear operations .39 .29 .18 Write-downs of real estate investments (see Note 12) (.31) Total Constellation Holdings Companies' earnings per share $.08 $.29 $.18 26 Balumore Gas and Electnc company and subsidiaries

Financial Investments Constillition Energy Solutions, Inc. and Subsidlirlso-Earnings from the Constellation Holdings Companies' portfolio of Our Energy Mirketing Businesses financial investments include income from: Our energy marketing businesses: D marketable securities, rovide power marketing and risk management services to a o financiallimited partnerships, and c financial guaranty insurance companies, wholesale customers in North America by purchasing and selling electric power, other energy commodities, and in 1997, earnings were higher than in 1996 due to better related derivatives, etrnings from trading securities, and increased gains from a provide natural gas brokering and related services for marketable securities. wholesale and retail customers, and a mnge y cusemM eg sWen, 8 a in 1996, earnings were higher than in 1995 because of better n n an n sys s, earnings from marketable securities and increased gains from financial limited partnerships, g. a% SWce, aM camps and multhbuilding energy systems. Raal Estate Development and Senior-Living Facilities in 1997, earnings from our energy marketing businesses were - Th3 Constellation Holdings Companies' real estate development lower than ira 1996 mostly because of lower gas brokering busin:ss includes: margins and increased uncollectible expense. In 1996, eamings a lind under development, o of$ce buildings, a rstall projects. BGE Home Products & Services, Inc. and c distribution facility projects, Subsidiaries-Our Home Products and D En entertainment, dining, and retail complex in Orlando, Commercial Building Systems Businesses

Florida,

. O a mixed-use planned-unit development, and BGE Home Products & Services, Inc. and subsidiaries: c senior-living facilities. a sells and services electric and gas appliances, in 1997, earnings from real estate development and senior-living 8 engages in home improvements, and facilities were lower than in 1996 mostly due to: a sells and services heating and air conditioning systems. o a $14.1 million after tax write down of the investment in in 1997 and 1996, earnings increased due to improved Church Street Station-an entertainment, dining, and retail performance in the service and installation business. complex in Orlando, Florida-which occurred because the Constellation Holdings Companies have now decided to sell . rather than keep the project, and o a $31.9 million after-tax write 4own of the investment in Piney Orchard-a mixed-use, plannedmnit development-which occurred because the expected cash flow from the project was less than the Constellation Holdings Companies' investment in the project. In 1996, earnings from real estate development and senior-living facilities were about the same as they were in 1995, W3 consider market demand, interest rates, the availability of finincing, and the strength of the economy in general wher, miking decisions about our real e* ate investments. Wo believe that until the economy shovcs sustained growth and there is more demand for new development, our real estate values will not imcrove much. If we were to sell our real estate projects in the I

' current market, we would have losses, although the amount of the losses is hard to predict. Depending on market conditions in l

the future, we could also have losses on any future sales. l *. We describe the Constellation Holdings Companies' real estate l business further in Note 12, i l B11timore Gas and Electric Company and Subsidiaries 27 1 E________________ _l

ugusety and capital ceseerces Cv:rview Our business requires a great deal of capital. Our actual capital requirements for De years 1995 through 1997, along with estimated amounts for the years 1998 through 2000, are shown below. 1995 1996 1997 1998 1999 2000

* #*"*]

Utility Buelness Capital Requirements Construction expenditures (excluding AFC) $223 $219 $ 238 $214 $ 222 $ 229 Electric 70 84 89 77 76 72 l Gas 51 46 38 34 27 24 Common Total construction expenditures 344 349 365 325 325 ~C5 22 10 8 7 7 6 AFC Nuclear fuel (uranium purchases and processing charges) 46 47 44 50 50 48 Daferred energy conservation expenditures 46 31 27 12 10 10 279 184 243 117 344 264 Retirement of long-term debt and redemption of preference stock Total utility business capital requirements 737 621 687 511 736 653 DiverelRed Buelnese Capital Requirements: ..westment requirements 118 118 156 169 134 157 Retirement of long-term debt 55 52 188 164 137 246 ' Totti diversified business capital requirements 173 170 344 333 271 403 Total capital requirements $910 $791 $1.031 $844 $1.007 $1.056 Capital Requirements of Our Utility Business Our securities ratings at the date of this report are shown in the f0ll Wing table. In October,1997, Standard & Poors upgraded our We continuously review and change our construction program, so mortgage bonds from A+ to AA. actual expenditures may vary from the estimates for the years-1998 through 2000 in the capital requirements chart-Standard Moody's & Poors investors Duff & Phelps Electric construction expenditures include improvements to Rating Group Service Credit Rating Co. generating plants and to our transmission and distribution facilities. Our projections of future electric construction Mortgage Bonds AA-A1 AA-expenditures do not include' costs to build more generating units. Unsecured Debt A A2 A+ Preference Stock A "a2" A Our utility operations provided about 78% in 1997, 96% in 1996, and 100% in 1995, of the cash needed to meet our capital I requirements, excluding cash needed to retire debt and redeem Capital Requirements of Our Diversified Businesses preferred and preference stock. In the past, capital requirements of our diversified businesses nly included the Constellation Holdings Companies because Dunng the three years from 1998 through 2000, we expect utility they had the only significant capital requirements. From time to operations to provide 115% of the cash needed to meet our time, however, our other diversified businesses may develop capital requirements, excluding cash needed to retire debt and significant capital requirements. As that occurs, we will include redeem preference stock. the capital requirements of those businesses in the capital When we cannot meet utility capital requirements internally, we requirements table above. As discussed unaer " Diversified sell debt and equity securities. We also sell securities when Business investment Requirements,' capital requirements for l market conditions permit us to refinance existing cebt or prefer-Constellation Power Source -a subsidiary of Constellation { ence stock at a lower cost. The amount of cash we need and Energy Solutions, Inc., and ComfortLink@~a general partnership me-ket conditions deterinine when and how much we sell. During in which BGE is a partner, are also included this year. the three years ended December 31,1997, we sold: Our diversified businesses expect to expand their businesses, p - $619 million of long-term debtf This may include expansion in the energy marketing, power c $60 million of preference stock, and generation, financial investments, real estate, and senior living D $4 million of common stock. facility businesses. Such expansion could mean more invest-ments in and acquisition of new projects. Our diversified busi-j nesses have met their cap'tal requirements in the past through Security Ratings independent credit-rating agencies rate our fixed-income borrowing, cash from their operations, and from time to time, l securities. The ratings indicate the agencies' assessment of loans or equity contributions from BGE. Our diversified our ability to pay interest, dividends, and principal on these businesses plan to raise the cash needed to meet capital securities. These ratings affect how much it will cost us when we requirements in the future through these same,nethods, sell these securities. The better the rating, the lower the cost of the securities to us when we sell them. i 23 Balbriore Gas and Electnc Company and Subsidianes

Diversified Business investment Requirements Diversified Business Debt and Uquidity The investment requirements of our diversified businesses include: Our diversified businesses plan to meet capital requirements by c the Constellation Holdings Companies' investments in refinancing debt as it comes due, by additional borrowing, and financial limited partnerships and funding for the develop-with cash generated by the businesses. This includes cash from t ment and acquisition of projects, as well as loans made to project entities' Products & Services may also meet capital requirements through c funding for growing Constellation Power Source's pcmer sales of receivables. We also discuss receivab'e sales in Note 12. marketing business, and if the Constellation Holdings Companies can get a reasonable o Comforttink's funding for construction of district energy value for real estate, additional cash may be obtained by selling

projects, real estate projects. The Constellation Holdings Companies' ability investment requirements for 1998 through 2000 include es Jmates to sell or liquidate assets will depend on market conditions, and we cannot give assurances that these sales or liquidations could of funding for existing and anticipated projects. We continuously be made. For more information, see the discussion of the real review and modlfy those estimates. Actual investment require-estate business and market in the "Real Estate Development and ments could vary a great deal from the estimates on page 28 Senior-Living Facilities" section beginning on page 27.

because they would be subject to several variables, including: In 1997, the Constellation Holdings Companies issued $289 0 the type and number of projects selected for development, million of three and four-year notes. In addition, our diversified c the effect of market conditions on those projects, businesses have the following revolving credit agreements to O the ability to obtain financing, and provide additional cash for short-term financial needs: 0 the availability of cash from operations. Amount of Revolving Credit Agreement Constellation Holdings Companies $75 million ComfortLink $50 million Constellation Energy Solutions, Inc. and Subsidiaries $10 minion - Other Matters Environmental Matters We have identified and evaluated all of our systems and applica-l We are subject to increasingly stringent federal, state, and local tions that may be affected by the year 2000 issue, and have j laws and regulations that work to improve or maintain the quality developed plans to ready these systems and applications for the of the environment. If certain substances were disposed of or century change. Modification and replacement projects are released at any of our properties, whether currently operating or currently under way. We plan to complete our evaluation of 3 not, these laws and regulations regulce us to remove or remedy suppliers' systems and applications by mid-1998. We plan to j the effect on the environment. This 1ncludes Environmental have our systems and applications ready for the year 2000 by Protection Agency Superfund sites. You will find details of our mid-1999. We do not expect the costs to address the year 2000 l environmental matters in Note 12 and in our Annual Reports on issue to be material. Form 10LK under item 1. Business--Environmental Matters. These details include financial information. Some of the Information is about costs that may be material. Accounting Standards issued i We will adopt De following statements that the Financial The Y:ar 2000 lasue Accounting Standards Board issued in 1997 on the dates I indicated below: The year 2000 issue affects virtually all companies and organiza-tions. Many existing computer programs and digital systems use a Statement of Financial Accounting Standards No.130, l only two digits to identify a year in the date field. These programs Reporting Comprehenske income, which we must adopt in our cnd systems were designed and developed without considering financial statements for the quarter ended March 31,1998, the impact of the upcoming change in the century. If not and . corrected, many computer applications could fail or create a Statement of Financial Accounting Standards No.131, j erroneous results by or at the year 2000. Disclosures About Segments of an Enterprise and Rclated } Information, which we must adopt in our financial state-in 1997, we formed a special task force to: ments for the year ended December 31,1998. . O identify and evaluate our systems and applications that may We do not expect the adoption of these standards to have a be affected by the year 2000 issue, material impact on our financial results or financial statement D modify or replace those systems and applications so they disclosures, will work property in the year 2000, and O communicate with our suppliers to make sure they are prepared for the year 2000. l Barbmore Gas and Electric Company and Subsioaries 29 ._-__--_-____-________a

Report of Manag:mont The management of the Company is responsible for the informa-internal control procedures. Coopers & Lybrand LL.P., indepen-tion and representations in the Company's financial statements. dent accountants, audit the financial statements and express - The Company preparer. the financial statements in accordance their opinion about them. They perform their audit in accordance with generally accepted accounting principles based upon with generally accepted auditing standards. available facts and circumstances and management's best The Audit Committee of the Board of Directors, which consists of estimates and judgments of known conditions. four outside Directors, meets periodically with management, Th3 Company maintains are accounting system and related internal auditors, and Coopers & Lybrand L.LP. to review the system of internal controls designed to provide reasonable activities of each in discharging their responsibilities. The internal cssurance that the financial records are accurate and that the audit staff and Coopers & Lybrand LLP. have free access to the Company's assets are protected. The Company's staff of internal Audit Committee. Euditors, which reports directly to the Chairman of the Board, conducts periodic reviews to maintain the effectiveness of Christian H. Poindexter David A. Brune Chairman of the Board Chief Financial Officer and Chief Executive Officer Rcport of Independent Accountants To the Shareholders of Baltimore Gas and Electric Company We have audited the accompanying consolidated balance sheets audit also includes assessing the accounting principles used and and statements of capitalization of Baltimore Gas and Electric significant estimates made by management, as wea as evalu-Company and Subsidiaries as of December 31,1997 and 1996, ating the overall financial statement presentation. We believe and the related consolidated statements of income, cash flows, that our audits provide a reasonable basis for our opinion. common shareholders' equity, and income taxes for each of the in our opinion, the financial statements referred to above present three years in the period ended December 31,1997. These fairly, in all material respects, the consolidated financial position financial statements are the responsibility of the Company's of Baltimore Gas and Electric Company and Subsidiaries as of management. Our responsibility is to express an opinion on December 31,1997 and 1996, and the consolidated results of thIse financial statements based on our audits. their operations and their cash flows for each of the three years We conducted our audits in accordance with generally accepted in the period ended December 31,1997 in conformity with auditing standards. Those standards require that we plan and generally accepted accounting principles. perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting j the amounts and disclosures in the financial statements. An Coopers & Lybrand L.L.P. Baltimore, Maryland l January 21,1998 i l 30 Dattimore Gas and Electric cornpany and subsidiaries

1 Consolidated Ctat:menta of inccme Year Ended December 31, 1997 1996 1995 (In millions, except per share amounts) Revenues Electric $2,191.7 $2.208.7 $2,229.8 Gis 521.6 517.3 400.5 Diversified businesses 594.3 427.2 304.5 Total revenues 3,307.8 3,153.2 2,934.8 ' Expenses Other Than Interest and Income Taxes Electric fuel and purchased energy 519.7 547.4 578.8 Disallowed replacement energy costs (see Note 12) 95.4 Gas purchased for resale 292.1 284.4 198.1 Operations 518.3 526.4 550.8 Maintenance 178.5 174.1 168.3 Diversified businesses-selling, gei.eral, and administrative 444.9 311.1 220.6 Write-downs of real estate investments (see Note 12) 70.8 Depreciation and amortization 342.9 330.2 317.4 Taxes other than income taxes 216.8 214.7 205.1 Total expenses other than interest and income taxes 2,584.0 2,483.7 2,239.1 income from Operations 723.6 669.5 695.7 Other income (Expense). Write-off of merger costs (see Note 12) (57.9) Allesance for equity funds used during construction 5.3 6.5 14.2 Equity in earnings of Safe Harbor Water Power Corporation ' 5.0 4.6 4.5 Net other income and (deductions) (5.2] (5.0) (9.9) Total other income (expense) (52.8) 6.1 8.8 income Before Interest and income Taxes 670.8 675.6 704.5 Interest Expense 1 Interest charges 241.2 217.6 219.7 l Capitalized interest (8.4) (15.6) (15.0) Allowance for borrowed funds used during construction (2.8) (3.5) (7.7) Net interest expense 250.0 198.5 197.0 locome Before income Taxes 440.8 477.1 507.5 )

income Taxes 158.0 166.3 169.5 Not income 282.8 310.8 338.0 Preferred and Preference Stock Dividends 28.7 38.5 40.6 l*

Eamings Applicable to Common Stock $ 254.1 $ 272.3 $ 297.4 1 Average Shares of Common Stock Outstanding 147.7 147.6 147.5 Eamings Per Common Share and Eamings Per Common Share-Assuming Dilution $1.72 $1.85 $2.02 See Notes to Consolidated Financial Statements. Bdtimore Gas and Dectnc Company and Subsidianes 31

Consolidated Ccirnce Sheets 1997 1996 At December 31, (In millions) A: sets Current Assets ' Cash and cash equivalents $ 162.6 66.7 l Accounts receivable (net of allowance for uncollectibles 419.8 419.5 of $24.1 and $18.0 respectively) 119.7 68.8 l Trading securities 87.6 87.1 Fuel stocks 164.2 147.7 Materials and supplies 65.2 64.7 Prepaid taxes other than income taxes 27.4 44.7 Other Total current assets 1,046.5 899.2 investments and Other Assets 446.8 525.8 Real estate projects 451.7 379.1 Power generation projects 196.5 204.4 Financial investments Nuclear decommissioning trust fund 145.3 116.4 113.0 84.5 Net pension asset ' Safe Harbor Water Power Corporation 34.4 34.4 62.2 36.4 i Senior living facilities Other 108.1 92.2 l Total investments and other assets 1,558.0 1,473.2 UtlHty Plant - Plant in service Electric 6,725.6 6,514.9 Gas 846.9 777.0 Common 554.1 523.5 - Total plant in service 8,126.6 7,815.4 Accumulated depreciation J2,843.4) (2,617.1) Net plant in service 5,283.2 5,198.3 Construction work in progress 215.2 221.9 Nuclear fuel (net of amortization) 127.9 132.9 Plant held for future use 25.2 25.5 Net utility plant 5,651.5 5,578.6 I osenrod chng Regulatory assets (net) 470.7 512.3 Other 46.7 81.0 1 Total deferred charges 517.4 593.3 Total Assets $8,773.4 $8.544.3 l See Notes to Consolidated Financial Statements. l Certain prior-year amounts have been reclassified to conform with the current year's presentation. l l I i I l a 32 Baltimore Gas and Electric Company and Subsidiaries

Consolidated Balnnco Che:ta l I l At December 31, 1997 1996 (In millions) Wabilities and Capitalization Current Umbilities (_ Short-term borrowings $ 316.1 $ 333.2 l Current portions of long-term debt and preference stock 271.9 280.8 l Accounts payable 203.0 172.9 l Customer deposits 30.1 28.0 j l'* Accrued taxes 5.5 6.5 l l - Accrued interest 58.4 57.4 ) l ' Dividends declared 66.3 66.9 l Accrued vacation costs 36.2 34.3 Other 44.3 37.1 Total current liabilities _1 031.8 1,017.1 7 Deferred Credits and Other Uabilities Deferred income taxes 1,294.9 1,295.9 Postretirement and postemployment benefits 185.5 169.2 Decommissioning of federal uranium enrichment facilities 34.9 38.6 Other 67.0 65.5 Total deferred credits and other liabilities _1 582.3 1,569.2 1 I i Capitalization I Long-term debt 2,988.9 2,758.8 Rzdeemable preference stock 90.0 134.5 . Preference stock not subject to mandatory redemption 210.0 210.0 Common shareholders' equity 2,870.4 2,854.7 Total capitalization 6,159.3 5,958.0 l Commitments, Guarantees, and Contingencies-See Note 12 l l l Total Uabilities and Capitailzation $8,773.4 $8,544.3 l i See Notes to Consolidated Financial Statements. i Cert in prior-year amounts have been reclassified to conform with the current year's presentation. I l Buumore Gas and Dectric Company and Subsidiaries 33 w-__-__-______-____--__-_____-___-____.___-_-__________

' Consolidated Stat:m:nts of C:sh FI:wa 1997 1996 1995 year Ended December 3L (In millions) Cash Flows From Operating Activities Net income $282.8 $310.8 $338.0 Adjustments to reconcile to net cash provided by operating activities Depreciation and amortization 396.8 383.1 379.0 Deferred income taxes 7.4 26.0 103.5 investment tax credit adjustments (7.5) (7.6) (8.1) Deferred fuel costs 18.3 0.5 5.6 28.5 1.3 Deferred energy conservation. senues 95.4 DiscIlowed replacement energy costs Accrued pension and postemployment benefits (18.0) (13.8) (7.6) Writeoff of mergercosts 57.9 . Write <fowns of real estate investments 70.8 Allowance for equity funds used during construction (5.3) (6.5) (14.2) ' Equity in earnings of affiliates and joint ventures (net) (42.5) (48.3) (21.3) Changes in current assets, other than sales of accounts receivable (54.7) (88.0) (107.4) - Changes in current liabilities, other than short term borrowings 42.6 (4.9) (7.3). Other J22.6) 26.7 6.7 Net cash provided by operating activities 726.0 701.9 668.2 Cash Flows From Financing Activities - Net issuance (maturity) of short-term borrowings (17.1) 53.9 215.6 Proceeds from issuance of Longterm debt 622.0 383.2 184.4 Preference stock 59.3 3.7 0.3 Common stock 10.0 2.0 Proceeds frorn sales of receivables Reacquisition of long-term debt (343.3) (158.5) (315.1) Redemption of preferred and preference stock (104.5) (112.6) (73.0) Common stock dividends paid. (239.2) (233.1) (227.2) Prsferred and preference stock dividends paid (29.7) (37.0) (40.1) Other 2.5 (1.2) Net cash used in financing activities ,{109.3) (91.6) (193.8) Cash Flows From investing Activities Utility construction expenditures (including AFC) (373.2) (360.5) (366.0) Allowance for equity funds used during construction 5.3 - 6.5 14.2 Nuclear fuel expenditures (43.6) (46.8) (46.3) Deferred energy conservation expenditures (27.1) (31.4) (45.5) Contributions to nuclear decommissioninir trust fund (17.6) (25.5) (9.8) Merger costs (20.9) (28.5) (5.1) Purchases of marketable equity securities (23.0) (32.7) (18.5) Sites of marketable equity securities 46.5 39.7 49.8 Other financial investments (0.4) 7.1 9.4 Real estate projects 24.2 (55.3) (15.6) Power generation systems (44.3) (5.3) (34.4) Other (46.7) (34.3) (21.8) Net cash used in investing activities L520.8) (567.0) (489.6) Not increase (Decrease) in Cash and Cash Equivalents 95.9 43.3 (15.2) Cash and Cash Equivalents at Beginning of Year 66.7 23.4 38.6 Cash and Cash Equivalents at End of Year $162.6 $ 66.7 $ 23.4 Other Cash Flow Information Cash paid during the year for; interest (net of amounts capitalized) $224.2 $193.6 $195.3 Income taxes $171.2 $160.1 $ 99.6 See Notes to Consolidated Financial Statements. Certain prior-year amounts have been reclassified to conform with the current year's presentation. 34 Baltimore Gas and Electric Company and Subsidiaries

-Consolidated Ctat:m:nta of Common Sh:rcholders' Equity Unrealized Gain (Loss) on Available Pension Common Stock Retaned For Sale Liability Total Years Ended December 31,1997,1996, and 1995 Shares Amount Earnirgs Securities Adjustment Amount (Dollar amounts in millions, number of shares in thousands) Balance at December 31,1994 147,527 $1,425.4 $1.312.6 $(2.5) $(16.5) $2,719.0 Net income 338.0 338.0 Dividends declared Preferred and preference stock (40.6) (40.6) Common stock ($1.55 per share) (228.6) (228.6) Common stock issued 0.3 0.3 Other 0.1 0.1 Net unrealized gain on securities 10.0 10.0 Deferred taxes on net unrealized gain on securities (3.5) (3.5) Pension liabilit" adjustment 25.4 25.4 Dsferred taxed on pension liability adjustment (8.9) (8.9) Balance at December 31,1995 147,527 1,425.8 1,381.4 4.0 2,311.2 Net income 310.8 310.8 Dividends declared Preferred and preference stock (38.5) (38.5) Common stock t$1.59 per share) (234.6) (234.6) Common stock issued 140 3.7 3.7 Other 0.4 0.4 N:t unrealized gain on securities 2.6 2.6 Deferred taxes on net unrea'ized gain on securities (0.9) (0.9) Balance at December 31,1996 147,667 1,429.9 1,419.1 5.7 2,854.7 Net income 282.8 282.8 Dividends declared . Preference stock (28.7) (28.7) Common stock ($1.w3 per share) (240.7) (240.7) Othir 3.1 3.1 Net unrealized loss on securities (1.2) (1.2) l Deferred taxes on net unrealized loss on securities 0.4 04, Balance at December 31,1997 147,667 $1,433.0 $1,432.5 $4.9 $2,870.4_ r See Notes to Consolidated Financial Statements. Certain prior-year amounts have been reclassified to conform with the current year's presentation. ^ e a j' 1 i i l l B21timore Gas and Electric Company and Subsidiaries 35

' Consolidated Ctat:m:nt3 of C:pitalizati:n 1997 1996 ' At December 31, (in millions) Long-Term Debt First Refunding Mortgage Bonds of BGE 6%% Series, due August 1,1997 24.9 125.0 125.0 Floating rate series, due April 15,1999 8.40% Series, due October 15,1999 91.1 91.1 125.0 125.0 SM% Series, due July 15,2000 8%% Series, due August 15,2001 122.3 122.4 22.7 7%% Series, due January 1,2002 7%% Series, due July 1,2002 124.5 124.5 5M% Installment Series, due July 15, 2002 9.8 10.4 6M% Series, due February 15,2003 124.8 124.8 6%% Series, due July 1,2003 124.9 124.9 SM% Series, due April 15,2004 125.0 125.0 Remarketed floating rate series, due September 1,2006 125.0 125.0 7M% Series, due January 15,2007 123.5 123.7 6%% Series, due Match 15,2008 124.9 125.0 7M% Series, due March 1,2023 125.0 125.0 7M% Series, due April 15,2023 100.0 100.0 Total First Refunding Mortgage Bonds of BGE _1,570.8 1.610.4 Other long-term debt of BGE Term bank loan due March 29,2001 50.0 Medium-term notes, Series B 100.0 100.0 Medium-term notes, Series C 143.0 183.0 Medium-term notes, Series D 225.0 138.0 Medium-term notes, Series E 183.5 Pollution control loan, due July 1, 2011 36.0 36.0 Port facilities loan, due June 1, 2C13 48.0 48.0 Adjustable rate pollution control loan, due July 1, 2014 20.0 20.0 5.55% Pollution control revenue refunding loan, due July 15,2014 47.0 47.0 Economic development loan, due December 1, 2018 35.0 35.0 - 6.00% Pollution control revenue refunding loan, due April 1,2024 75.0 75.0 Variable rate pollution control loan, due June 1, 2027 8.8 Total other long-term debt of BGE 921.3 732.0 Long-term debt of Constellation Holdings Companies Loans under revolving credit agreement 65.0 Variable rates based on LIBOR, due December 9,1999 Mortgage and construction loans and other collateralized notes 8.69% mortgage note, due January 28,1998 28.4 24.9 7.90% mortgage note, due September 12,2000 8.6 8.8 8.00% mortgage note, due July 31,2001 0.1 0.1 8.00% mortgage note, due October 30, 2003 1.6 1.5 7.50% mortgage note, due October 9, 2005 9.7 9.8 Variable rate mortgage notes, due through 2009 93.5 94.9 7.357% mortgage note, due March 15,2009 5.5 5.8 9.65% mortgage note, due Februaiy 1,2028 9.7 9.7 8.00% mortgage note, due November 1,2033 1.2 Unsecured notes 579.1 387.2 Total long-term debt of Constellation Holdings Companies 737.4 607.7 Long-term debt of other diversified businesses Loans under revolving credit agreement 22.0 12.0 Unamortized discount and premium (13.7) (14.5) Current portion of long-term debt (248.9) (197.8) Total long-term debt $2.988.9 $2,758.8 continued on page 37 See Notes to Consolidated Financial Statements. Cert:In prior-year amounts have been reclassified to conform with the current year's presentation. 36 Baltimore Gas and E ectric Company and Subsidiaries

l Consolidated Ctatz:monta of Ccpitclization At December 31, 1997 1996 (In millions) Preference $tock Cumulative, $100 par value,6,500,000 shares authorized Redeemable preference stock 7.50%,1986 Series,365,000 and 395,000 shares outstanding. Callable at $102.50 per share prior to October 1, 2001 and at lesser amounts thereafter 36.5 39.5 6.75 %,1987 Series,425,000 and 440,000 shares outstanding. Callable at $102.25 per share prior to April 1,2002 and at lesser amounts thereafter 42.5 44.0 7.80%,1989 Series,500,000 shares redeemed at par on July 1,1997 50.0 8.25%,1989 Series, 100,000 shares redeemed at par on October 1,1997 10.0 8.625%,1990 Series, 130,000 and 390,000 shares outstanding 13.0 39.0 7.85%,1991 Series,210,000 and 350,000 shares outstanding 21.0 35.0 Current portion of redeemable preference stock (23.0) L83.0j Total redeemable preference stock 90.0 134.5 Preference stock not subject to mandatory redemption 7.78%,1973 Series,200,000 shares outstanding, callable at $101 per share 20.0 20.0 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 outs'anding, not callable prior to October 1,2003 50.0 50.0 6.70%,1993 Series,400,000 shares outstanding, not callable prior to January 1,2004 40.0 40.0 6.99%,1995 Series,600,000 shares outstanding, not callable prior to October 1,2005 60.0 60.0_ Total preference stock not subject to mandatory redemption 210.0 210.0 Common Shareholders' Equity Common stock without par value, 175,000,000 shares authorized; 147,667,114 shares issued and outstanding at December 31,1997 and 1996. (At December 32,1997 166,893 shares were reserved for the Employee Savings Plan and 3,277,656 shares were reserved for the Dividend Reinvestment and Stock Purchase Plan.) 1,433.0 1,429.9 R tained earnings 1,432.5 1,419.1 Unrealized gain on available-for-sale securities 4.9 5.7 Total common shareholders' equity _2 870.4 2,854.7 t Total Capitalization $6,159.3 $5.958.0 See Notes to Consolidated Financial Statements. Certain prior-year amounts have been reclassified to conform with the current year's presentation. m. l l Baltimore Gas and Electric Company and Subsidiaries 37

Consolidated Ctat:menta of incoma Texc3 Y;ar Ended December 31, 1997 1996 1995 l (Dollar amounts in millions) . Income Taxes Current $158.1 $147.9 $ 74.1 Def2rred Change in tax effect of temporary differences (1.0) 22.0 116.9 Change in income taxes recoverable through future rates 8.0 4.9 (1.0)

Deferred taxes credited (charged) to shareholders' equity 0.4 (0.9)

(12J Deferred taxes charged to expense 7.4 26.0 103.5 investment tax credit adjustments _(7.5) (7.6) (8.1) income taxes per Consolidated Statements of income $158.0 $166.3 $169.5 ' reconciliation of income Taxes Computed at Statutory R Federal Rate to Total income Taxes income before income taxes $440.8 $477.1 $507.5 Statutory federal income tax rate 35% 35% 35% income taxes computed at statutory federal rate 154.3 167.0 177.6 Increases (decreases) in income taxes due to Depreciation differences not normalized on regulated activities 13.9 12.6 11.0 Allowance for equity funds used during construction (1.9) (2.3) (5.0) Amortization of deferred investment tax credits (7.5) (7.7) (8.1) Tax credits flowed through to income (0.5) (0.5) (0.5) Amortization of deferred tax rate differential on regulated activities (2.3) (1.9) (2.0) State income taxes 6.2 4.1 1.6 Other _(4.2) (5.0) (5J Total income taxes $158.0 $166.3 $169.5 Effective federal income tax rate 35.8% 34.9% 33.4% e ^ At December 31, 1997 1996 (Dollar amounts in millions) Deferred income Taxes Deftrred tax liabilities Accelerated depreciation $ 953.5 $ 920.6 Allowance for funds used during construction 206.7 209.2 Income taxes recoverable through future rates 89.8 92.6 Deferred termination and postemployment costs 41.1 45.6 Deferred fuel costs 1.5 7.9 Leveraged leases 25.2 27.6 Percentage repair allowance 38.7 38.4 Energy conservation expenditures 24.5 26.6 Other 191.5 175.6 Total deferred tax liabilities _1 572.5 1,544.1 1 Daferred tax assets Accrued pension and postemployment benefit costs 37.6 40.6 Deferred investment tax credits 44.3 46.9 Capitalized interest and overhead 44.5 42.5 Contributions in aid of construction 39.7 35.7 Nuclear decommissioning liability 24.3 20.0 Other 87.2 62.5 Total deferred tax assets 277.6 248.2 Deferred tax liability, net $1,294.9 $1.295.9 See Notes to Consolidated Financial Statements. Certain prior-year amounts have been reclassified to conform with the current year's presentation. 38 Baltsrnore Gas and Electric cornpany and Subsidiaries

Notra to Consolidated Finrncirl Stat:m:nts Note 1. Significant Accounting Policies Nature of Our Business However, sometimes the Maryland PSC orders an accounting Baltimore Gas and Electric Company (BGE) is the parent company treatment different from that used by nonregulated companies to and conducts our primary business-the electric and gas utility determine the rates we charge our customers. We discuss this business. That business serves Baltimore City and all or part further in Note 5. of 10 Central Maryland counties. We also conduct various diversified businesses in subsidiary companies. We describe Utility Revenues our diversified businesses in Note 3. We record utility revenues in our Consolidated Statements of income when we provide service to customers. We use three different accounting methods to report our invest-Fuel and Purchased Energy Costs I ments in our subsidiaries or other companies: consolidation, the We incur costs for: j equity method, and the cost method. s the fuel we use to generate electricity, { Consolidation a purchases of electricity from others, and ~ We use consolidation when we own a majority of the voting stock u natural gas that we resell, of the subsidiary. This means the accounts of our subsidiaries These costs are shown in our Consolidated Statements of are combined with our accounts. We eliminate intercompany Income as " electric fuel and purchased energy" and

gas balances and transactions when we consolidate these accounts.

purchased for resale." We discuss each of these separately Our consolidated financial statements include the accounts of: below. O BGE, o Constellation Holdings, Inc. and Subsidiaries (the fuel Used to Generate Electricity and Purchases of Electricity Constellation Holdings Companies), From Others O Constellation Energy Solutions, Inc. and Subsidiaries, and Under the electric fuel rate clause set by the Marytand PSC, we a BGE Home products & Services, Inc. and Subsidiaries. charge our electric customers for:. a the fuel we use to generate electricity (nuclear fuel, coal, l The Equity Method gas, or oil), and We usually use the equity method to report corporate joint a the net cost of purchases and sales of electricity, primarily ventures, partnerships, and affiliated companies (including power with other utilities. generation projects) where we hold a 20% to 50% voting interest. Under the equity method, we report: We charge the actual costs of these items to customers with no profit to us. To do this, we must keep track of what we spend c our interest in the entity as an investment in our and what we collect from customers under the fuel rate in a Consolidated Balance Sheets, and given period. Usually these two amounts are not the same D our percentage share of the earnings from the entity in our because there is a difference between the time we spend the Consolidated Statements of Income. money and the time we collect it from our customers. The only time we do not use this method is if we can exercise Under the electric fuel rate clause, we defer (include as an asset control over the operations and policies of the company. If we or liability in our Consolidated Balance Sheets and exclude from have control, accounting rules require us to use consolidation. our Consolidated Statements of income) the difference between We report our investment in Safe Harbor Wa'.er Power our actual costs of fuel and energy and what we collect from Corporation under the equity method. customers under the fuel rate in a given period. We either bill or refund our customers that difference in the future. We discuss The Cost Method this further in Note 5. We usually use the cost method if we hold less than a 20% We calculate the electric fuel rate using three factors: l voting interest in an investment. Under the cost method, we report our investment at cost in our Consolidated Balance e the mix of generating plants we used over the last 24 ,l* Sheets. The only time we do not use this method is when we can

months, l

ex1rcise significant influence over the operations and policies of a the latest three-month average fuel (Ast for each generating l the company. If we have significant influence, accounting rules unit, and ~ r: quire us to use the equity method. a the net cost of purchases and sales of electricity, primarily with other utilities, over the last 24 months. Cogulation of Utility Business The Maryland Put>lic Service Commission (Maryland PSC) regu-We may change the fuel rate only if the calculated rate is more than 5% above or below the rate in effect. The fuel rate is lates our utility business. Generally, we use the same accounting affected most by the amount of electricity generated at our policles and practices used by nonregulated companies for finan-Calvert Cliffs Nuclear Power Plant (Calvert Cliffs) because the cial reporting under generally accepted accounting principles. cost of nuclear fuel is cheaper than coal. gas, or oil. { BIltimore Gas and Dectric Company and Subediaries 39

We also report two other items as " electric fuel and purchased Under the mark to market method of accounting, we report: energy" in our Conso0 dated Statements of Income: a commodity positions and derivatives at fair value in our O amortization of nuclear fuel (described under " Utility Plant" Consolidated Balance Sheets, and later in this note). We amortize nuclear fuel based on the a changes in fair value as diversified business revenues in our energy produced over the life of the fuel. W6 pay quarterly Consolidated Statements of income, fees to the Department of Energy for the future disposal of At December 31,1997, Constellation Power Source had deriva-spent nuclear fuel, and accrue these fees based on the live assets with a fair value of about $9.4 million and derivative kilowatt-hours of electricity sold. We bill our customers for liabilities with a fair value of about $8.6 million. nuclear fuel as described earlier in this note. D amortization of deferred costs of decommissioning and Market Risk decontaminating the Department of Energy's uranium enrich. We rneasure our exposure to market risk at any point in time by ment facilities. We discuss these costs further in Note 5. companng our open positions to a market estimate of fair value. The Extended outages at Calvert Cliffs drive up fuel costs and may market prices we use to determine fair value are based on manage-result in fuel rate proceedings before the Maryland PSC. In these ment's best estimates, which consider vanous factors including: proceedings, the Maryland PSC would consider whether any a closing exchange prices, a time value of money, and portion of the extra fuel costs should be paid by BGE instead of a over-the-counter prices, a volatility factors. passed on to customers. We discuss the financial impact of past extended outages in Note 12. At December 31,1997, our exposure to market nsk was not material. Natural Gas Taxes ' We charge our gas customers for the natural gas they consume We summarize our income taxes in the Consolidated Statements using

gas cost adjustment clauses" set by the Maryland PSC.

of income Taxes on page 38. As you read this section, it may be These clauses operate the same as the electric fuel rate clause helpful to refer to those statements. described earlier in this note. However, effective October 1996, the Maryland PSC approved a modification of the gas cost adjust-Income Tax Expense ment clauses to provide a market based rates incentive mecha-We have two categories of income taxes in our Consolidated nism. th' der market based rates our actual cost of gas is Statements of income--current and deferred. We describe each compared to a market index (a measure of the market price of of these below. gas in a given period). The difference between our actual cost and the market index is shared equally between BGE (which Our current income tax expense consists solely of regular tax benefits shareholders) and customers. less applicable tax credits. Our 1996 and 1995 current income tax expense amounts include attemative minimum tax credits of $30 million in 1996 and $40 million in 1995. The alternative Risk Management minimum tax can be carried forward indefinitely and used as j We engage in risk management activities in our gas business tax credits in years when our regular tax liability exceeds the and in our diversified businesses. We separately desenbe these alternative minimum tax liability. We do not have any remaining activities for each business below. alternative minimum tax credits. Gas Business Our deferred income tax expense is equal to the changes in the In 199E, we iagan using basis swaps in the winter months deferred income tax liability and regulatory asset (described later (November through March) to hedge price risk associated with in this note) during the year, excluding amounts charged or ' natural gas purcha0es. Under internal guidelines, we are not credited to common shareholders' equity, permitted to try to predict market changes. Investmsnt Tax Credits We defer, as unrealized gains or losses, the net amount we owe We have also deferred the investment tax credit associated with (unrealized losses) or are due (unrealized gains) under the swaps our regulated utility business in our Consolidated Balance Sheets in our Consolidated Balance Sheets. At December 31,1997, we as a regulatory liability. The regulatory liability is amortized evenly had outstandbg basis swap agreements covering 15.4 million to income over the life of each property. We discuss this further dscatherms of natural gas purchases through March 1998. We in Note 5. We reduce income tax expense in our Consolidated i had unrealized gains of $1.0 million related to the outstanding Statemer:ts of Income for the investment tax credit and other tax agreements. When amounts are paid under the agreements, we credits associated with our nonregulated diversified businesses, report the payments as gas costs in our Consolidated other than leveraged leases. Statements of Income. Deferred Income Tax Assets and Liabilities OhwrsMed BusJoesses We must report some of our assets and liabilities differently for j Our subsidiary, Constellation Power Source, engages in power our financial statements than we do for income tax purposes. marketing activities, which include trading electricity, other energy The tax effects of the differences in these items are reported as commodities, and related derivatives (such as forwards, options, deferred income tax assets or liabilities in our Consolidated and swaps). Constellation Power Source reports trading activities Balance Sheets. We measure the assets and liabilities using using the mark-to-market method of accounting. income tax rates that are currently in effect. 40 Bartimore Gas and Electric company and Subsidiaries

A portion of our total deferred income tax liability relates to our Trading Securifles utility business, but has not been reflected in the rates we The Constellation Holdings Companies classify some of their charge our customers. We refer to this portion of the liability investments in marketable equity securities and financial limited as " income taxes recoverable through future rates." We have partnerships as trading securities. We include any unrealized l recorded that portion of the liability as a regulatory asset in our gains or losses on these securities in diversified business Consolidated Balance Sheets. We discuss this further in Note 5. revenues in our Consolidated Statements of income. Franchise Taxes Available-for-Sale Securities We pay Maryland public service company franchise tax instead of We classify our investments in the nuclear decommissioning trust state income tax on our utihty revenue from sales in Maryland. fund as available-for-sale securities. We include any unrealized We include the franchise tax in " taxes other than income taxes" gains or losses on the trust assets as a change in the decom-in our Consolidated Statements of Income. missioning reserve. We describe the nuclear decommissioning trust and the reserve under the heading " Decommissioning invantory Costs" later in this note. We report the majonty of our fuel stocks and materials and supplies at average cost. in addition, the Constellation Holdings Companies classify some of their investments in marketable equity securities as available-Evaluation of Assets for impairment for-sale securities. We include any unrealized gains or losses on Statement of Financial Accounting Standards No.121 these securities in shareholders' equity in our Consolidated Balance Sheets. We also include the Constellation Holdings Accounting for the Impairment of Long-Lived Assets and for Long-Companies' portion of unrealized gains or iosses on securities lived Assets to Be Disposed Of, applies particular requirements of equitymethod (described et.rlier in this note) investees in to some of our assets that have long lives (some examples are shareholders' equity. utility property and equipment, and real estate). We determine if those assets are impaired by comparing their undiscounted expected future cash flows to their carrying amount in our Utluty Pbnt, Depreciation and Amortization, and accounting records. We recognize an impairment loss if the Decommissioning undiscounted expected future cash flows are less than the Utillty Plant carrying amount of the asset. Utility plant is the term we use to describe our utility business property and equipment that is irs use, being held for future use, Rsal Estate Projects r under construction. We summarize utility plant in our in Note 4, we summarize the real estate projects that are in our Consolidated Balance Sheets. We report our utility plar.1 at its Consolidated Balance Sheets. The projects consist of the onginal cost, which includes: Constellation Holdings Companies' investments in: a material and labor, a rental and operating properties, that they are holding for a contractor costs, investment, and s, construction overhead costs (where applicable), and a properties under development, that they are holding for a an allowance for funds used during construction (described future development and subsequent sale. I ter in this note). The Constellation Holdings Companies include the costs incurred We charge retired or otherwisedisposed-of utility plant to to acquire and develop these properties as part of the costs of accumulated depreciation, the properties. Generally, the Constellation Holdings Companies report these properties at cost, unless the amount invested We own an undivided interest in the Keystone and Conemaugh exceeds the fair value. In these cases, the Constellation Holdings electric generating plants in Western Pennsylvania, as well as in Companies write down the projects to their fair values, the transmission line that transports the plants' output to the jo nt owners' service territories. Our ownership interests in these plants are 20.99% in Keystone and 10.56% in Conemaugh. FintncialInvestments and Trading Securttles These ownership interests represented a net investment of in Note 4, we summarize the financial investments that are in $152 million at December 31,1997, and $153 million at our Consolidated Balance Sheets. December 31,1996. We report these properties in the same Statement of Financial Accounting Standards No.115, Accounting accounts we use for our other utility plant (described above). for Certain Inwstments in Debt and Equity Securities, apphes particular requirements to some of our investments in debt and Depreclaflon hpense equity securities. We report those investments at fair value, and Generally, we compute depreciation by applying composite, we use specific identification to determine their cost for straight-line rates (approved by the Maryland PSC) to the average computing realized gains or losses. We classify these investments investment in classes of depreciable property. We depreciate as either trading securities or available'for-sale securities, which vehicles based on their estimated useful lives. As a result of the we describe separately below. We report investments that are not Maryland PSC's November 1995 gas base rate order, we revised covered by Statement of Financial Accounting Standards No.115 our gas utility plant depreciation rates to reflect the results of a at their cost, detailed depreciation study. The revised rates increased deprecia-tion expense by approximately $2.4 million annually. Baltimore Gas and Electric Company and Subsidiaries, 41

' Our 1995 depreciation expense includes the writeoff of expendi-Prior to November 1995, we used a pre-tax rate of 9.40% to turns associatzd with a second combustion turbine at our calculate AFC for all of our utility plant. Effective November 1995, Perryman site that will not be built. This write-off reduced after-the Maryland PSC reduced the pre-tax AFC rates to 9.04% for gas tax earnings during 1995 by $9.7 million, or $.07 per share. The plant and 9.36% for common plant. We continue to use 9.40% construction of the first 140-megawatt combustion turbine at for electric plant. We compound AFC annually. Perryman was completed, and the unit was placed in service, during June 1995. Capitalized interest The Constellation Holdings Companies capitalize interest costs incurred to finance real estate developed for intemal use and Amortization Egense Amortization is an accounting process of reducing an amount in power generation development projects. our Consolidated Balance Sheets evenly over a period of time. When we reduce amounts in our Consolidated Balance Sheets, Longterm Debt we increase amortization expense in our Consolidated We defer (include as an asset or liability in our Consolidated Statements of income, An amount is considered fully amortized Balance Sheets and exclude from our Consolidated Statements when it has been reduced to zero.

income) all costs related to the issuance of long-term debt.

These costs include underwriters' commissions, discounts or . Decommissionlig Costs premiums, and other costs such as legal, accounting and W3 must accumLlate a reserve for the costs that we expect to regulatory fees, and printing costs. We amortize these costs incur in the future to decommission the radioactive portion of over the life of the debt. ' Calvert Cliffs. We do this based on a sinking fund methodology. When we incur gains or losses on debt that we retire prior to In 1995, the Maryland PSC authorized us to record decommis-maturity, we amortize those gains or losses over the remaining sioning expense based on a facility-specific cost estimate so we originallife of the debt. can accumulate a decommissioning reserve of $521 million in 1993 dollars by the end of Calvert Cliffs' service life in 2016, Cash Flows adjusted to reflect expected inflation. We have reported the decommissioning reserve in " accumulated depreciation" in For the purpose of reporting our cash flows, we define cash our Consolidated Balance Sheets. The total reserve was equivalents as highly liquid investments that mature in three $201.6 million at December 31,1997, and $167.5 million months or less. at Dacember 31,1996. Use of Accounting Estimates To fund the costs we expect to incur to decommission the plant, Management makes estimates and assumptions when preparing we established an external decommissioning trust in accordance f nancial Statements under generally accepted accounting princh with Nuclear Regulatory Commission (NRC) regulations. We ples. These estimates and assumptions affect various matters, report the assets in the trust in " nuclear decommissioning trust including-t. fund" in our Consolidated Balance Sheets. The NRC requires utili-ties to provide financial assurance that they will accumulate suffi-u our reported amounts of assets and liabilities in our cient funds to pay for the cost of nuclear decommissioning based Consolidated Balance Sheets at the dates of the financial upon either a generic NRC formula or a facility-specific decommis-statements, sioning cost estimate. We use the facility-specific cost estimate e our disclosure of contingent assets and liabilities at the (mantioned above) for funding these costs and providing the dates of the financial statements, and renuired financial assurance. e our reported amounts of revenues and expenses in our Consolidated Statements of income during the reporting Allowance for Funds Used During Construction periods. and Capitalized Interest These estimates involve judgments with respect to, among other Allowance for Funds Used Durlig Construction (AFC) things, future economic factors that are difficult to predict and We finance construction projects with borrowed funds and equity are beyond management's control. As a result, actual amounts funds. We are allowed by the Maryland PSC to record the costs could differ from these estimates. l of these funds as part of the cost of construction projects in our { _ Consolidated Balance Sheets. We do this through the AFC, which blassificatbns we calculate using a rate authorized by the Maryland PSC. We bill We have reclassified certain prior-year amounts for comparative our customers for the AFC plus a return after the utility plant is purposes. These reclassifications did not affect consolidated net ) placed in service. income for the years presented. 42' Baltmore Gas and Electric Cornpany and Subsidianes

l Not3 2. Information by Business Segment We have three business segrnents: electnu, gas, and diversified businesses (subsidiaries). Our electric business generates, purchases, and sells electricity. Our gas business purchases, transports, and sells natural gas. Our diversified businesses are involved in various activities which we describe in Note 3. We show selected financial information for each of our business segments in the following table. Construction Identifiable segment intersegrnent Total Income from Depreciation / Expenditures Assets at Revenues Revenues Revenues operabons Amortizauon (Including AFC) December 31 (In millions) 1997-Electric $2,191.7 $ 0.3 $2,192.0 $596.8 $286.5 $278.7 $6,204.7 Gas 521.6 521.6 63.5 39.3 94.5 896.9 Diversified businesses 594.3 10.3 604.6-63.3 17.1 1,595.2 Other identifiable assets 76.6 Intercompany eliminatioris {10.6) _{10.6) Total $3,307.6 $3,307.6 $723.6 $342.9 $373.2 $8,773.4 1996--Electric $2.208.7 $ O.3 $2,209.0 $498.0 $279.3 $262.5 $6,222.6 Gas 517.3 517.3 68.9 37.8 98.0 810.1 I Diversified businesses 427.2 6.8 434.0 102.6 13.1 1,400.6 Other identifiable assets 111.0 J Intercompany eliminations (7.1). (7.1) l Total $3.153.2 $3.153.2 $669.5 $330.2 $360.5 $8.544.3 1995-Electric $2,229.8 $ 1.3 $2,231.1 $574.3 $276.3 $288.5 $6,193.4 Gas 400.5 400.5 48.1 29.6 77.5 748.5 Diversified businesses 304.5 6.6 311.1 73.3 11.5 1,266.1 Other ideat; Sable assets 69.6 Intercompany eliminations (7.9) (7.9) Total $2.934.8 $2,934.8 $695.7 $317.4 $3660 $8.277.6 l Note 3. Information About Ocr Subsidiaries Our diversified business subsidiaries are organized in three groups: 1997 1996 1995 o Our power generation, financial investments, and real estate locome Statements businesses, Revenues c Our energy marketing businesses, and Real estate projects $152.7 $80.8 $108.4 o Our home products and commercial building systems Power generation systems 109.1 93.1 57.7 businesses. Financial investments _ 51.9 38.9 25.2 Total revenues 313.7 212.8 191.3 Our Power Generation, Financial Investments, Expenses other than interest and Real Estate Businesses and income taxes W3 refer to all of these together as the Conste11ation Holdings ~238.8 113.2 114.4 income from operations 74.9 99.6 76.9 Companies. Constellation Holdings, Inc. is a wholly owned .n. n es 2 3 subsidiary of BGE and holds all of the stock of the following three subsidiaries: 0 6 Capitalized interest 8.4 14.6 13.6 c Constellation Power, Inc.-develops, owns, and operates income tax expense _(11.8) (26.6) (14.4) power generation projects, Net income $ 11.9 $42.3 $ 27.1 O Constellation investments, Inc.-engages in financial Contribution to our earnings investments, and per sha e of common stock $.08 $.29 $.18 o Constellation Real Estate Group, Inc.-develops, owns, and manages real estate and senior-living facilities. Salance Sheets Current assets $ 170.4 $ 115.7 $ 98.5 We show condensed financiat information for the Constellation Noncurrent assets _i 190.0 1,189.7 1,102.5 Holdings Companies in the following table. We have not reflected t the elimination of intercompany balances or transactions that are Total assets $1,360.4 $1.305.4 $1.201.0 climinated in our consolidated financial statements. We describe Current liabilities . $ 181.1 $ 134.0 $ 70.4 this further in Note 1. Noncurrent liabilities 837.0 775.2 778.5 Shareholder's equity 342.3 396.2 352.1 Total liabilities and _s_hareholder's equdy ?",360.4 $1.305.4 $1.201.0 Baltimore Gas and Dectric Company and Subsidiaries 43

The 1997 income statement includes aftertax write-downs of real a Constellation Energy Source, Inc.-provides natural estate projects totaling $46 million. We describe these wnte downs gas brokering and related services for wholesale and l in the *Re6 Estate Development and Senior-Living Facilities" retail customers. section of Management's Discussion and Analysis on page 27. m Constellation Energy Projects & Services, Inc. and Subsidiaries-provides a broad range of customized The 1996 income statement includes a $14.6 million after-tax gain energy seses, Wng WaM ebcW and gas on the sale of a power purchase agreement that was offset by: distribution systems, energy consulting, power quality a a $7.0 million aftertax write-off of an investment in two services, and campus and multi-building energy systems. geothermal wholesale power generating projects that sell electricity under California power purchase agreements, Our Home Products and Commercial Building Systems a a $3.0 million after-tax write-off of development costs for a Businesses coal-fired power project, and BGE Home Products & Services, Inc. and subsidiaries: e a $6.2 million aftertax write-off of a portion of an invest-a sells and services electric and gas appliances, ment in a solar power project, u engages in home improvements, and a sells and services heating and air conditioning systems. Our Energy Marketing Businesses Constellation Energy Solutions, Inc. is a wholly owned subsidiary Other of BGE and serves as the holding company for our three energy Safe Harbor Water Power Corporation is a producer of marketing businesses: hydroelectric power. BGE owns two-thirds of Safe Harbor's a Constellation Power Source, Inc.--provides power marketing total capital stock, including one-half of the voting stock, and risk management services to wholesale customers in and a two-thirds interest in its retained earnings. North America by purchasing and selling electric power, other energy commodities, and related derivatives. Nota 4. Real Estate Projects and Financial Investments Amortized Unreehzed Unrealized Fair Real Estate Projects Real estate projects consist of the following investments held by A.t December 31.1997 Cost Basis Gains Losses value (In millions) the Constellation Holdings Companies: Marketable Equity Securities $ 77.3 $12.0 $(0.5) $ 88.8 At December 31, 1997 1996 U.S. Government agency 14.9 0.2 15.1 (in millions) State municipal bonds 65.5 2.2 67.7 Properties under development $220.8 $286.2 Totals $157.7 $14.4 $(0.5) $171.6 Rental and operating properties (net of accumulated depreciation) 225.6 237.7 Amortued Unreahzed unreanzed Fair Other real estate ventures 0.4 1.9 At December 31,1996 cost Basis Gains Losses value Total real estate projects $446.8 $525.8 (In millions) Marketable Equity Securities $ 52.5 $ 8.0 $(0.1) $ 60.4 Financial investments U.S. Government agency 18.1 0.3 18.4 Financial investments consist of the following investments held State municipal bonds 73.6 2.2 (0.1) 75.7 by the Constellation Holdings Companies: Totals $144.2 $10.5 $(0.2) $154.5 At December 31, 1997 1996 (In millions) Gross and net realized gains and losses on available-for sale Insurance companies $ 88.8 $ 76.8 securities were as follows: Marketable equity securities 33.3 46.2 1997 1996 1995 Financial limited partnerships 43.6 48.1 (in millions) = leveraged leases 30.8 33.3 Gross realized gains $9.3 $4.3 $5.5 Total financial investments $196.5 $204.4 Gross realized losses 10.6) (0.2) (2.51 Net realized gains $8.7 $4.1 $3.0 Investments Classified as Available-for Sale We classify our investments in the nuclear decommissioning trust The U.S. Govemment agency obligations and state municipal fund and the Constellation Holdings Companies' marketable bonds (shown above) mature on the following schedule: squity securities (shown above) as available-for-sale. This means At December 31,1997 Amount we do not expect to hold them to maturity and we do not (in millions) consider them trading securities. Less than 1 year $ 1.0 We show the fair values, gross unrealized gains and losses, and 1-5 years 24.1 amortized cost bases for these available for-sale securities, 5-10 years 51.8 exclusive of $3.5 million of unrealized net gains on securities of More than 10 years 5.9 equity method investees, in the follow,ng tables. i Total maturities of debt securities $82.8 44 Baltimore Gas and Electric Company and subsidianes

Nota 5. Regulatory Assets (not) As discussed in Note 1, the Maryland PSC regulates our utility Deferred Nuclear Expenditures business. Generally, we use the same accounting policies and Deferred nuclear expenditures are the net una:nortized balance practices used by nonregulated companies for financial reporting of certain operations and maintenance costs at Calvert Cliffs. Under generally accepted accounting principles. However, some-These expenditures consist of times the Maryland PSC orders an accounting treatment different from that used by nonregulated companies to determine the rates a costs incurred from 1979 through 1982 for inspecting and we charge our customers. When this happens, we must defer repairing seismic pipe supports, certain utility expenses and income in our Consolidated Balance a expenditures incurred from 1989 through 1994 associated Sheets as regulatory assets and liabilities. We then record them with nonrecurring phases of certain nuclear operations in our Consolidated Statements of locome (using amortization) projects, and when we include them in the rates we charge our customers. a expenditures incur.ed during 1990 for investigating leaks in We have recorded these regulatory assets and liabilities in our Consolidated Balance Sheets in accordance with Statement of We are amortizing these costs over the remaining life of the plant Financial Accounting Standards No. 71, Accounting for the in accordance with the Maryland PSC's orders. Effects of Certain Types of Regulation.11 we were required to terminate application of that statement for all of our regulated Deferred Energy Conservation Expenditures operations, we would have to record the amounts of all regula-Deferred energy conservation expenditures include two components: tory assets and liabilities in our Consolidated Statements of Income at that time. This means our eamings would be reduced e operations costs (labor, materials, and indirect costs) asso-by the total net amount in the table below. net of applicable ciated with energy conservation programs approved by the income taxes. Maryland PSC, which we are amortizing over five years in accordance with the Maryland PSC's orders, and We summarize our regulatory assots and liabilities in the following table, and we discuss each of them separately below. a revenues we collected from customers in 1996 in excess of Our profit limit under the energy conservation surcharge. At December 31, 1997 1996 The Maryland PSC allows us to collect from customers money (In millions) spent on conservation programs under an " energy conservation income taxes recoverable through future rates $256.5 $264.5 Deferred postretirement and surcharge." However, under this surcharge the Maryland PSC limits what our profit can be. If, at the end of the year, we have postemployment benefit costs 96.4 89.2 exceeded our allowed profit, we lower the amount of future Deferred nuclear expenditures 77.7 82.1 surcharges to our customers to correct the amount of overage, Deferred energy conservation expenditures 55.8 46.7 plus interest. Deferred costs of decommissioning During 1996, we exceeded our profit limit under the energy federal uranium enrichment facilities 42.4 46.0 conservation surcharge. As a result, we deferred $28.6 million of Deferred environmental costs 38.8 47.7 our 1996 revenue from surcharge bi!!ings as a regulatory liability. Deferred termination benefit costs 21.0 41.1 To correct the overage, we lowered the surcharge on our Deferred fuel costs 4.4 22.7 customers' bills from July 1997 to June 1998. Deferred investment tax credits (126.6) (133.9) Other 4.3 6.2 Deferred Costs of Decommissioning Federal Uranium Total regulatory assets (net) $470.7 $512.3 Enrichment Facilities Deferred costs of decommissioning federal uranium enrichment income Taxes Recoverable Through Future Rates facilities are the unamortized portion of our required contributions As described in Note 1, income taxes recoverable through future to a fund for decommissioning and decontaminating the rates are the portion of our deferred income tax liability that is Department of Energy's uranium enrichment facilities. We are applicable to our utility business, but has not been reflected in required, along with other domestic utilities, by the Energy Policy the rates we charge our customers. These income taxes repre-Act of 1992 to make contributions to the fund. The contributions sent the tax effect of temporary differences in depreciation and are generally payable over 15 years with escalation for inflation and the allowance for equity funds used during construction, offset b', are based upon the proportionate amount of uranium enriched by differences in deferred tax rates and deferred taxes on deferred the Department of Energy for each utility. We are amortizing these investment tax credits (discussed later in this note). We amortize costs over the contribution period as a cost of fuel. We also these amounts as the temporary differences reverse. discuss this in Note 1. Deferred Postretirement and Postemployment Benefit Costs Deferred Environmental Costs Deferred postretirement and postemployment benefit costs are Deferred envkonmental costs are the estimated costs of investi the costs we recorded under Statements of Financial Accounting Eating and cleaning up contaminated sites we own. We discuss Standards No.106 (for postretirement benefits) and No.112 (for thir further in Note 12. We are amortizing $21.6 million of these postemployment benefits) in excess of the costs we included ;n costs (the amount we had incurred through October 1995) over a the rates we charge our customers. We will amortize these costs 10-year period in accordance with the Maryland PSC's November over a 15-year period beginning in 1998. We discuss these costs 1995 order. further in Note 6. Baltimore Gas and Dectric company and Subsidianes 45

m,_ _ ______ At December 31, 1997 1996 Deferred Termination BeneRts . Deferred terrnination benefit costs tre the net unamor zed (in millions) ti bilInce o' the cost of certain termination benefits offered to Electric deferred fuel costs employees of our regulated utility operations. We describe these Costs deferred (over-recovered) $(19.0) $113.2 . termination benefits further in Note 7. We are amortizing these Disa!! owed replacement (11_83 costs over a five-year period in accordance with the Maryland energy costs 'see Note 12) PSC's orders. Net electric deferred (over-recovered) fuel costs (19.0) (4.8) Oeferred Fuel Costs Gas deferred fuel costs 23.4 27.5 As described in Note 1, deferred fuel costs are the difference Total deferred fuel costs $ 4.4 $ 22.7 between our actual costs of electric fuel, net purchases and silJs of electricity, and natural gas and our fuel rate revenues Deferred investment Tax Credits - collected from customers. We reduce deferred fuel costs as we As described in Note 1, deferred investment tax credits are - collect them fro,n customers. investment tax credits associated with our regulated utility - We show our deferred fuel costs in the following table. business. Under federal income tax regulations, we do not deduct deferred investment tax credits from rate base. Nota 8. Pension, Postratirement, Other Postemployment, and Employee Savings Plan Benefits We o' fer pension, postretirement, other postemployment, and We show the components of total net pension cost in the f employee savings plan benefits. We describe each of these following table. We do not include the cost of term nation bene-separately below, fits described in Note 7 in net pension cost. Year Ended December 31, 1997 1996 1995 Ponolon BeneRts (in millions) W3 sponsor several defined benefit pension plans for our Service costbenefits . employees. A defined benefit plan specifies the amount of bene. fits a plan participant is to receive using information about the earned during the period $16.8 . $16.1 $11.4 participant. Our largest plan covers nearly all BGE employees and Interest cost on projected certain employees of our subsidiaries. Our Lther plans, which are benefit obligation 61.3 59.9 58.4 not material in amount, provide supplemental benefits to certain Actual retum on plan assets (130.0) (57.7) (150.5) key employees. Our employees do not contribute to these plans. Net amortization and deferral 70.0 2.1 94.7 Gen rally, we calculate the benef'ts under these plans based on Total net pension cost 18.1 20.4 14.0 r age, years of service, and pay. Amount capitalized as Sometimes we amend the plans retroactively. These retroactive construction cost J 2.5) (2.4) (1.4) plan amendments require us to recalculate benefits related to Total net pension cost participants' past service. We amortize the chango in the benefit charged to expense $15.6 $18.0 $12.6 costs from these plan amendments on a straignt-line basis over the average remaining service period of active employees. We Postretirement BeneRts . fund the plans by contributing at least the minimum amount We sponsor defined benefit postretirement health care and life required under Internal Revenue Service regulations. We calcu-insurance plans which cover nearly all BGE employees and Lt3 the amount of funding using an actuarial method called the certain employees of our subsidiaries. Generally, we calculate the projected unit credit cost method. The assets in all of the plans benefits under these plans based on age, years of service, and at December 31,1997 were mostly marketable equity and fixed pens!on benefit leveh. We do not fund these plans. income securities, and group annuity contracts. We show the funded status of all of the plans in the following table. tions to cover a portion of the plan costs. Contributions for At December SL - 1997 1996 employees who retire after June 30,1992 are calculated based (In millions) on age and years of service. The amount of retiree contributions a Vestsd benefit obligation $ 702.0 $695.6 increase based on expected increases in medical costs. For the life insurance plan, retirees do not make contributions to cover a Nonvested benefit obligation 40.0 18.0 portion of the plan costs. Accumulated benefit obligation 742.0 713.6 Projected benefits related to Effective January 1,1993, we adopted Statement of Financial increase in future compensation levels 160.0 1 12 l Accounting Standards No.106, Employers' Accounting for Projected benefit obligation 902.0 846.3 Postretirement Benefits Other Than Pensions. The adoption of Plan assets at fair value _(912.3) (792.5) that statement caused: Projected benefit obligation less plan assets (10.3) 53.8 m a transition obligation, which we are amortizing over 20 Unrecognized prior service cost (19.4) (21.9) years, and Unrecognized net loss (84.2) (117.2) e an increase in annual postretirement benefit costs, which ' Unamortized net asset from we discuss later in this note. adoption of FASB Statement No. 87 0.9 0.8 Accrued pension asset $(113.0) $ (84.5) 46 Bammore Gas and Electric Company and Subsidiaries

For our diversified businesses, we expense all postretirement Other Postemployment Benefits benefit costs. For our regulated utility business, we accounted for We provide the following postemployment benefits: the increase in annual postretirement benefit costs under two Maryland PSC rate orders: a health and life insurance benefits to our employees and certain employees of our subsidiaries who are found to e In an April 1993 rate order, the Maryland PSC allowed us to be disabled under our Disability insurance Plan, and expense onehalf and defer, as a regulatory asset (see Note 5). the other half of the increase in annual postretirement benefit m income replacement payments for employees found to be costs related to our utility business. disabled before November 1995 (payments for employees found to be disabled after that date are paid by an e in a November 1995 rate order, the Maryland PSC allowed insurance company, and the cost is paid by employees), us to expense all of the increase in annual postretirement benefit costs related to our gas business. The liability for these benefits totaled $45.4 million as of December 31,1997 and $50.8 million as of December 31,1996. Beginning in 1998, the Maryland PSC authorized us to: Effective December 31,1993, we adopted Statement of a expense all of the increase in annual postretirement benefit Financial Accounting Standards No.112. Employers' Accounting e costs related to our electric business, and for Postemployment Benefits. The portion of the liability a amortize the regulatory asset for postretirement benefit attributable 6 to regulated activities as of December 31,1993 was costs related to our utility business over 15 years, deferred as a regulatory asset (see Note 5), consistent with the The Maryland PSC authorized us to reflect these changes in our Maryland PSC's orders for postretirement benefits (desenbed current electric base rates and will adjust our gas base rates to earlier in this note). We wi!I amortize the regulatory asset over recover the higher costs that will be recognized in 1998. 15 years beginning in 1998. The Maryland PSC authorized us to reflect this change in our current electric base rates and will Our treatment of the increase in annual postretirement benefit adjust our gas base rates to recover the higher costs that will be costs meets guidelines estactished by the Emerging issues Task recognized in 1998. Force of the Financial Accounting Standards Board for deferring postretirement benefit costs as a regulatory asset. ssu p ns amMWM@Whp% We show the components of the accumulated postretirement postretirement, and other postemployment benefit liabilities. benefit obligation and a reconciliation of these amounts to the accrued postretirement benefit liability in the following table. At_ December 31, 1997 _ 1996_ Discount rate At December 31, 1997 1996 Pension and postretirement benefits 7.25% 7.5% Health Life Health Life Other postemployment benefits 6.0 6.0 Care Insurance Care insurance Average increase in Accumulated postretirement (in mi# ions) future compensation levels 4.0 4.0 benefit obligation: Expected long-term rate of Retirees $164.5 $47.3 $163.9 $45.5 return on assets 9.0 9.0 Active employees 87.7 20.8 82.4 19.3 We assumed the health care inflation rates to be: Total accumulated post-retirement benefit obligation 252.2 68.1 246.3 64.8 e in 1997,6.0% for both Medicare +1igible retirees and Unrecognized transition es nd cwed W Mcam, and obligation (132.2) (38.4) (141.1) (41.0) e in 1998,8.0% for Medicare-eligible retirees and 9.5% for Unrecognized net loss _(3.8) (7.1) (7.4) (5.7) Accrued postretirement After 1998, we assumed both rates will decrease by 0.5% annu-benefit liability $116.2 $22.6 $ 97.8 $18.1 ally to a rate of 5.5% in the years 2003 and 2006. A one-percent increase in the health care inflation rate fium the assumed rates We show the components of net postretirement benefit cost in would increase the accumulated postretirement benefit obligation the following table. We do not include the cost of termination by approximately $40 million as of December 31,1997 and benefits described in Note 7 in net postretirement benefit cost. would increase the combined service and interest costs of the postretirement benefit cost by approximately $4 million annually. Year ended December 31, 1997 1996 1995 Employee Savings Plan Benefits "N Service cost-benefits earned We also sponsor a defined contribution savings plan that is during the period S 5.4 $ 5.5 $ 3.9 offered to all eligible BGE employees and certain employees of Interest cost on accumulated post our subsidiaries. In a defined contribution plan, the benefits a retirement benefit obligation 21.8 21.9 21.2 p rtic(pant is to receive result from regular contnbutions to Amortization of transition obligation 11.4 11.4 11.4 p rticipant account. Under this plan, we make matching Net amortization and deferral 0.1 0.2 (0.11 contributions to participant accounts. We made matching contributions to this plan of: Total nei postretirement benefit cost 38.7 39.0 36.4 Amount capita lized a $8.5 million in 1997, as construction cost (7.6) (6.2) (5.3) m $9.4 million in 1996, and Amount deferred _(7.2) [7.4_lj8.0j u S8.5 million in 1995. Total net postretirement benefit _ cost charged to expense $23.9 $25.4 $23.1 Batt rnore Gas and Electne Cornpany and Subsidiaries 47

Nota 7. Termination Benefits Tenninstion Benefits Offered in 1992 Termination Benefits Offered in 1993 We offered a Voluntary Special Early Retirement Program to We offered a second Voluntary Special Ear!y Retirement Program ' eligible employees who retired from February 1,1992 through to eligible employees who retired as of February 1,1994. The April 1,1992. The termination benefits of this program cost $6.6 termination benefits of this program consisted mostly of million and consisted mostly of an enhanced pension benefit. We enhanced pension and postretirement benefits. As part of this are amortizing the cost of these benefits over a five-year period program, we accomplished further employee reductions by in accordance with tho Maryland PSC's April 1993 order. eliminating positions, and offering additional benefits to employees affected by the eliminations. We deferred $88.3 million of the costs of this program that were attributable to regulated activities. We are amortizing these costs over a five-year period, consistent with the Maryland PSC's previous orders. Note 8. Short-Term Borrowings Summary of Short-Term Borrowings We had unused bank lines of credit supporting our commercial Our shortterm borrowings include bank loans, commercial paper paper notes of $231 rnillion at December 31,1997 and notes, and bank lines of credit. Short-term borrowings mature $203 million at December 31,1996. These amounts do not within one year from the date of the financial statements. We pay include unused revolving credit agreements of $100 million at commitment fees to banks for providing us lines of credit. When December 31,1997 and $150 million at December 31,1996 ' we borrow under the lines of credit, we pay market interest rates. that are discussed in Note 9. We summarize our short-term borrowings in the following table. At December 31, 1997 1996 Our weighted average effective interest rates for short-term (in millions) borrowings were as follows: BGE's bank loans 8.8 Year ended December 31, 1997 1996 BGE's commercial paper notes 316.1 324.4 Total short-term borrowings $316.1 $333.2 Bank loans 5.00% 4.93% Commercial Paper Notes 5.66 5.53 Nets 9. WTerm Debt Long-term debt matures more than one year from the date of the m 5M% installment Series, due 2002 a 6H% Series, due 2003 financial statements. We summarize our long-term debt in the m 8.40% Series, due 1999 m 6%% Series. due 2003 Consolidated Statements of Capitalization on page 36. As you a 5M% Series, due 2000 m 5M% Series, due 2004 read this section, it may be helpful to refer to those statements. m 8X% Series, due 2001 m 7M% Series, due 2007 We discuss BGE's, the Constellation Holdings Companies', and a 7%% Series, due 2002 m 6%% Series, due 2008 other diversified businesses' long-term debt separately below. We must pay principal on the 5M% installment Series as follows: BGE's Long-Term Debt Year (in millions) BQE's Mrst Rehmdirng Mortgage Bonds BGE's first refunding mortgage bonds are secured by a mortgage 1998 and 1999 $ 0.7 lien on nearly all of our assets, includng all utility properties and 2000 and 2001 0.9 franchises and our subsidiary capital stock. Our subsidiary 2002 6.7 caprtal stock pledged under the mortgage includes that of: Holders of the Remarketed Floating Rate Series Due a c Constellation Holdings,Inc., September 1,2006 have the option to require BGE to C Constellation Energy Solutions, Inc., repurchase their bonds at face value on September 1 of each ' o BGE Home Products & Services, Inc., and year. BGE is required to repurchase and retire at par any bonds that are not remarketed or purchased by the remarketing agent. O Safe Harbor Water Power Corporation. BGE also has the option to redeem all or some of these bonds BGE is required to make an annual sinking fund payment each at face value each September 1. August i to the mortgage trustee. The amount of the payment is equal to 1% of the highest principal amount of bonds outstand; rig BGE*s & WTm M during the preceding 12 months. The trustee uses these funds to BGE has $100 million of revolving credit agreements with several retire bonds from any series through repurchases or calls for banks that are available through 2000. At December 31,1997, early redemption. However, the trustee cannot call the follow,ng BGE had no outstanding borrowings under these agreements. i bonds for early redemption: These banks charge us commitment fees based on the daily average of the unborrowed amount, and we pay market interest } rates on any borrowings. These agreements also serve as back-up credit support for BGE's commercial paper notes, as described in Note 8 46-Baltimore Gas and Electric Company and Subsidianes

We show the weighted-average interest rates and maturity Other Diversified Businesses' Long Tctm Debt 1 dates for BGE's fixedrate medium-term notes outstanding at ComfortLink, a general partnership in which BGE is a partner, December 31,1997 in the following table. has a $50 million unsecured revolving credit agreement that matures September 26,2001. Under the terms of the agree-Weighted-Average ment, ComfortLink has the option to obtain loans at various Series interest Rate Maturity Dates rates for terms up to nine months. ComfortLink pays a facility fee B 8.43% 1998 2006 on the total amount of the commitment. At December 31,1997, C 7.15% 1998-2003 ComfortLink had $22 million outstanding under this agreement. D 6.36% 1998-2006 E 6.70% 2006-2012 Constellation Energy Source has a $10 million revoMng credrt agreement that matures February 1,2000. At December 31,1997, Some of the mediunkterm notes include a "put option." These Constellation Energy Source had no outstanding borrowings under put options allow the holders to se!! their notes back to BGE on this agreement. the put option dates at a price equal to 100% of the principal amount. The following is a summary of mediurn-term notes with Maturities of Long-Term Debt put options. All of our long-term borrawings mature on the following schedule { Series E Notes Principal Put Option Dates (includes sinking fund requirements): 1 (In millions) Dwersified k

ygg, gag gu,,nesses

} 6.75% due 2012 $60.0 June 2002 and 2007 (in millions) 6.75% due 2012 $25.0 June 2004 and 2007 1998 $ 93.6 $155.3 6.73% due 2012 $25.0 June 2004 and 2007 1999 334.5 131.9 2000 253.8 244.5 Constellation Holdings Companies' Long-Term Debt 2001 198.6 185.0 RevoMang Credit Agreement 2002 156.2 ' 2.8 The Constellation Holdings Companies have a $75 million unse-Thereafter 1,455.4 39.9 cured revolving credit agreement that matures December 9,1999, Total long-term debt j which they use to provide liquidity for general corporate purposes, at December 31,1997 $2.492.1 $759.4 The Constellation Holdings Companies pay a commitment fee based on the daily average of the unborrowed portion of the commitment. At December 31,1997, the Constellation Holdings At December 31,1997, BGE had long-term loans totaling $255 Companies had no outstanding borrowings under this agreement. million that mature after 2002 that lenders could potentially require us to repay early. Of this amount, $145 million could poten-Mgage and Constmet/on Loans tially be repaid in 1998, $60 million could be repaid in 2002, and $50 million could be repaid thereafter. We have the abUity and The Constellation Holdings Companies' mortgage and construc-intent to refinance such debt by issuing medium-term notes or by tion loans and other collateralized notes have varying terms. The following mortgage notes require monthly principal and interest borrowing under our revoMng credit agreements, if necessary. Weighted Average Interest Rates for Variable Rate Debt o 7.90% due in 2000 a 7.357% due in 2009 Our weighted average interest rates for variable rate debt were: j 0 8.00% due in 2001 a 9.65% due in 2028 l o 7.50% due in 2005 Year ended December 31, 1997 1996 The 8.00% mortgage note due in 2003 requires interest BGE i payments until maturity. nie variable rate mortgage notes require Floating rate series mortgage bonds 6.11% 5.87% periodic payment of principal and interest. The 8.00% mortgage Remarketed floating rate note due in 2033, requires interest payments initially then series mortgage bonds 5.75 5.63 monthly principal and interest payments. Medium-term notes, series D 5.78 Pollution control loan 3.63 3.49 (Jnsecured Notes Port facilities loan 3.71 3.59 The unsecured notes mature on the following schedule: Adjustable rate pollution control loan 3.90 3.90 Amount Economic development loan 3.69 3.57 (in millions) Variable rate pollution control loan 3.73 7.05% due April 22,1998 $ 25.0 l 7.06% due September 9,1998 20.0 Constellation Holdings Companies 8.48% due October 15,1998 75.0 Loaris under credit agreement 5.99 6 08 7.30% due April 22,1999 90.0 Mortgage and construction loans 8.73% due October 15,1999 15.0 and other collaterals 2ed notes 8.10 8.33 l 7.125% due March 13,2000 15.0 Other Diversified Businesses l 7.55% due April 22,2000 35.0 Loans under credit agreement 6.04 6.13 7.50% due May 5,2000 139.0 7.43% due September 9,2000 30.0 7.66% due May 5,2001 135.0 8.00% due December 31,2000 0.1 Total unsecured notes at December 31,1997 $579.1 Baltimore Gas and Dectric company and Subsidiaries 49

1 Note 10. Fedeemable Preferencs stock Priority The following table summarizes the annual required redemptions . For the payment of dividends and in the event of liquidation of of all redeemable preference stock. l BGE, we rank preference stock prior to common stock. We rank Year l Lil preference stock ecually. (In millions) 1998 $ 23.0 $1nking Fund Redemptions 1999 10.0 Rensdred Sinking Fund Redemptions 2000. 10.0 Some of our preference stock issues have annual sinking fund 2001 3.0 requir:ments. Under those requirements, we must redeem - 2002 3.0 some of our preference stock at $100 per share annually. We Thereafter 64.0 summarize the redemptions required in the following table. Total required redemptions $113.0 Beginning Serics Shares Yoar Optional Sinking Fund Redemptions \\ . 7.50%,1986 Series 15,000 1992 For each series, we have the option to redeem shares in addition j 6.75%,1987 Series 15,000 1993 to the annual sinking fund requirements. Each year, we may t redeem an amount up to the required annual number of sinking 8.625%,1990 Series 130,000 1996 fund shares at $100 per share. 7.85%,1991 Series 70,000 1997 Other Redemptions We also i ave the option to fully redeem the 7.50%,1986 Series, and the 6,iS%,1987 Series, at the prices shown in the Consolidated Statements of Capitalization on page 37. Nota 11. Leases Thers are two types of leases--operating and capital. Capital incoming Lease Rentals I;ases qualify as sales or purchases of property and are Some Constellation Holdings Companies, as landlords, lease reported in the Consolidated Balance Sheets. All other leases office and retail space to others. These operating leases expire tre operating leases and are reported in the Consolidated over periods ranging from one to 20 years, and have options to Stit:ments of income. We present information about our renew. At December 31,1997, the Constellation Holdings operating leases below. Companies had property under operating leases with a net book value of $184.9 million. Outgoing Lease Payments At December 31,1997, tenants owed the Constellation Holdings We, es lessee, lease some facilities and equipment used in our Companies future minimum rentals under operating leases as follows: business. The lease agreements expire on various dates and have various renewal options. We expense all lease payments Year associated with our regulated utility operations. (in millions) 1998 $ 17,9 Lease expense was: 1999 18.1 .o $9.5 million in 1997, 2000 17.7 o $11.6 million in 1996, and 2001 16.2 0 $12.2 million in 1995. 2002 14.6 Thereafter 63.1 At December 31,1997, we owed future minimum payments for Total future minimum lease rentals $147.6 long-term noncancellable operating leases as follows: . Year (In millions) 1998 $ 5.9 1999 3.6 -2000 3.3 '2001 2.8 ~2002 2.3 Therstfter 5.6 Total future minimum lease payments $23.5 50 Baltirnore Gas and Electric Company and Subsidiaries

Not312. Commitments Gurrantees, ard Conting2ncito l' Commitments Termination of Proposed Merger With j. We have made substantial commitments in connecton with our Potomac Electric Power Company t utility construction program for future years. In addition, we have As previously disclosed, in September 1995 we signed an agree-i entered into three long-term contracts for the purchase of electric ment with Potomac Electric Power Company to merge together gerarating capacity and energy. The contracts expire in 2001, into a new company, Constellation Energy Corporation, after all 2013, and 2023. We made payments under these contracts of: necessary regulatory approvals were received. In December 1997, o $65.6 million in 1997, both companies mutually terminated the merger agreement. o $64.2 million in 1996, and Accordingly, in 1997, we wrote off $57.9 million of costs related to the merger. We have reported the write-off as " writeoff of a $68.4 million in 1995. merger costs" in our Consolidated Statements of Income. This At December 31,1997, we estimate our future payments for writestf reduced after-tax earnings by $37.5 million, l capacity and energy that we are obligated to buy under these contracts to be: Environmental Matters y, Clean Air (in millions) The Clean Air Act of 1990 contains two titles designed to reduce emissions of sulfur dioxide and nitrogen oxide (NOx) from electric 1998 $ 81.4 generating stations - Title IV and Title 1. 1999 92.2 l 2000 92.8 Title IV addresses emissions of sulfur dioxide. Compliance is l 2001 63.2 required in two phases: l 2002 42.1 e Phase i became etfective January 1,1995 We met the Thereafter 765.3 requirements of this phase by installing flue gas desulfurization Total estimated future payments for systems (scrubbers), switching fuels, and retinng some units. apacity and energy under long-term contracts $1.137.0 m Phase il must be implemented by 2000. We are currently examining what actions we should take to comply with this Some Constellation Holdings Companies have committed to phase, We expect to meet the compliance requirem;nts contribute additional capita and to make additional loans to through some cornbination of installing flue gas desulfurizar l - some affiliates, joint ventures, and partnerships in which they tion systems (scrubbers), switching fuels, retiring some I have an interest. At December 31,1997, the total amount of units, or allowance trading. investrnent requirements committed to by the Constellation Holdings Companies was $35 million. Title I addresses emissions of NOx, but the regulations of this title have not been finalized by the govemment. As a result, our in December,1994, BGE sad BGE Home Products & Services plans for complying with this title are less certain. By 1999 the entored into agreements with a financial institution to sell on an regulations require more NOx controls for ozone attainment at ~ ongoing basis an undivided interest in a designated pool of our generating plants. The additional controls will result in more customer receivables. Under the agreements, BGE can sell up to expenditures, but it is difficult to estimate the level of those i a total of $40 million, and GGE Home Products & Services can expenditures since the regulations have not been finalized. l sell up to a total of $50 million. Under the terms of the agree-However, based on existing and proposed regulations, we l ments, the buyer of the receivables has limited recourse against currently estimate that the additional controls at our generating h l BGE and has rio recourse against BGE Home Products & plants will cost approximately $90 million, j Services. BGE and BGE Home Products & Services have in July 1997, the government published new National Ambient recorded a reserve for credit losses. At December 31,1997's Air Quality Standards for very fine particulate and redaed BGE had sold $35 million and BGE Home Products & Service had sold $47 million of receivables under these agreements. standards for ozone attainment. These standards may require Increased controls at our fossil generating plants in the future. Cuarantees We cannot estimate the cost of these increased controls at this i l BGE guarantees two thirds of certain debt of Safe Harbor Water time because the states, including Maryland, still need to l* Power Corporation. The maximum amount of our guarantee is detcrmine what reductions in pollutants will be necessary to $23 million. At December 31,1997, Safe Harbor Water Power meet the federal standards. Corporation had outstand M debt of $30 million of which i~ $20 million is guaranteet Oy BGE. Waste Disposal l The Environmental Protection Agency and several state agencies i BGE also issued an $11 million guaranty for debt under the have notif'ed us that we are considered a potential!y responsible l rsvolving credit agreement of Constellation Energy Source. At party with respe 't o the cleanup of certain environmentally Dec:mber 31,1997. Constellation Energy Source had no coatamin6ted situ, owned and operated by others. We cannot outstanding borrowings under this agreement. estimate the cleanup costs for all of these sites. We can, At December 31,1997, the Constellation Holdings Companies had however, estimate that our 15.79% share of the possible guiranteed outstanding loans end letters of credit of certain power cleanup costs at one of these sites, Metal Bank of America generation and real estate projects totaling $46 million. Also, the (a metal reclaimer in Philadelphia) could be approximately Constellation Holdings Companies guarantee certain other borrow. $7 million higher than amounta we have recorded. This ings of various power generation and real estate projects. estimate is based on the nighest es'imate of costs in the range of reasonably postible alternative. The cleanup costs We assess the risk of material loss from tl ese guarantees for some of the remaining sites to be minimal. Baltimore Gas and Electric company and Subsidianes 51 4

could be significant, but we do not expect them '.o have a As an operator of a commercial nuclear power plant in the IJnited material effect on our financial position or results of operations. States, we are required to purchase insurance to cover radiation iriury claims of certain nuclear workers. On January 1,1998, a new Also, we are investigating several sites where gas was insurance policy became effective for all operators requir!ng manufactured in the past. The investigation of these sites coverage for current operations. Waiving the right to make additional includes reviewing possible actions to remove coal tar. In late claims under the old policy was a condition for acceptance under December 1996, we signed a consent order with the Maryland the new policy. We describe both the old and new policies below. Department of the Environment that requires us to implement r: medial action plans for contamination at and around the Spring a BGE nuclear worker claims reported on or after Gardens site. We have submitted the required remedial action January 1,1998 are covered by a new insurance policy plans and the Maryland Department of the Environment is in the with an annual industry aggregate limit of $200 million process of reviewing them. Based on several remedial action for radiation injury claims against all operators insared options for all sites, the costs we consider to be probable to by this policy. r:medy the contamination are estimated to total $50 million in a All nuclear worker claims reported prior to January 1,1998 nominal dollars (including inflation). We have recorded these are still covered by the old insurance policies, insureds costs as a liability on our Consolidated Balance Sheets and have under the old policies, with no current operations, are not d:ferred these costs, net of accumulated amortization and required to purchase the new policy desenbed above, and tmounts we expect to recove from insurance companies, as a may still make claims against the old policies for the next regulatory asset. We discust. this further in Note 5. We are also 10 years, if radiation injury claims under these old policies r: quired by accounting rules to disclose additional costs we exceed the policy reserves, all policyholders could be considir to be less likely than probable costs, but still " reason-assessed, with our share being up to $6.3 million. ably possible" of being incur ed at these sites. Because of the if cl ims under these polices exceed the coverage limits, the provi-r:sults of studies at these sees, it is reasonably possible that these additional costs could t xceed the amount we recognized by sions of the Price Anderson Act (discussed above) would apply, approximately $48 million in rominal dollars ($11 million in current dollars, plus the impt :t of inflation at 3.1% over a period Recoverability of Electric Fuel Costs of up to 60 years). By law, we are allowed to recover our cost of electric fuel as long as the Maryland PSC finds that, among other things, we have Nucleor Insurance kept the productive capacity of our generating plants at a If there were an accident or an extended outage at either unit of reasonable level. To do this, the Maryland PSC will perform an Calvert Cliffs, it could have a substantial adverse financial effect evaluation of each outage (other than regular maintenance on BGE. The primary contingencies that would result from an inck outages) at our generating plants. The evaluation will determine dent at Calvert Cliffs could include: if we used all reasonable and costeffective maintenance and a the physical damage to the plant, o the recoverability of replacement power costs, and Effective January 1,1987, the Maryland PSC established a a our liability to third parties for property damage and Generating Unit Performance Program to measure, annually, bodily injury. whether we, and other utilities, have maintained the productive capacity of our generating plants at reasonable levels. To do this, We have insurance policies that cover these contingencies, but the program uses a system-wide generating performance target the policies have certain exclusions. Furthermore, the costs that and an individual performance target for each base load gener-could resutt from a covered major accident or a covered extended ating unit. In fual rate hearings, actual generating performance outage at either of the Calvert Cliffs units could exceed our insur-adjusted for planned outages will be compared first to the ance coverage limits, systentwide target. If that target is met, it should mean that the requirements of Maryland law have been met, if the system-wide j For physical damage to Cuvert Cliffs, we have $2.75 billion of target.is not met, each unit's adjusted actual generating perfor-l property insurance from an industry mutual insurance company, mance will be compared to its individual performance target to If an outage at either of the two units at Calvert Cliffs is caused determine if the requirements of Maryland law have been met by an insured physical damage loss and lasts more than 17 and, if not, to determine the basis fur possibly impos!ng a wecks, we have insurance coverage for replacement power costs i up to $487.2 million per unit, provided by an industry mutual pena!ty on BGE. Even if we meet these targets, other parties to i insurance company. This amount can be reduced by up to $94.6 fuel rate hearings may still question whether we used all teason-able and costeffective procedures to try to prevent an outage if million per unit if an outage to both units at the plant is caused the Maryland PSC decides that we were deficient in some way, by a single insured physical damage loss. If accidents at any insured plants cause a shortfall of funds at the industry mutual, the Maryland PSC may not allow us to recover the cost of replacement energy. all policyholders could be assessed with our share being up to $31 million. The two units at Calvert Cliffs use the cheapest fuel. As a result, l In addition we, as well as others, could be charged for a portion the costs of replacement energy associated with outages at these j of Eny third party claims associated with a nuclear incident at units can be significant. We cannot estimate the amount of replacement energy costs that could be challenged or disallowed in any commercial nuclear power plant in the country. Under the provisions of the Price Anderson Act, the limit for third party future fuel rate proceedings, but such amounts could be material, claims from a nuclear incident is $8.92 billion. if third party claims exceed $200 million (the amount of primary insurance), our share of the total liability for third party claims could be up to $159 million per incident. That amount would be payable at a I rate of $20 million per year. l l I 52 Battarnore Gas and Dectric Company arid Subudianes l 4 a

During 1989 through 1991 we had extended outages at Calvert Holdings Companies' eamings could be affected significantly. Cliffs. These outages drove up fuel costs, and resulted in fuel However, the California projects that make the highest revenues rate proceedings before the Maryland PSC for several years, in will transition to variable rates in 1999 and 2000. As a result, these proceedings, the Maryland PSC considered whether any we do not expect the Constellation Holdings Companies to have portion of the extra fuel costs should be charged to BGE instead significantly lower earnings due to the transition to variable rates of passed on to customers, before 2000, in December 1996, we settled the proceedings by agreeing nct The Constellation Holdings Companies are pursuing alternatives to bill our customers for $118 million of electric replacement for some of these power generation projects including: energy costs associated with these outages. All costs associated with the outages in excess of $118 million have already been a mpowering the projects to reduce operating costs, collected from customers through the fuel rate. In 1990, we a changing fuels to reduce operating costs, wrote off $35 million of these costs. In 1996, we wrote off the a renegotiating the power purchase agreements to improve remaining $83 million plus $5.6 million of related financing the terms, charges. The 1996 writeoffs, together, reduced after-tax a restructuring f;nancings to improve the financing terms, and earnings by $57.6 million. a selling its ownership interests in the projects. Also in 1996, we wrote off $6.8 million of fuel costs related to We cannot predict the financial effects of the switch from fixed to earlier outages that were disallowc ^ by the Maryland PSC. This variable rates on the Constellation Holdings Companies or on write-off reduced 1996 after-tax earnings by $4.5 million. BGE, but the effects could be material. We have reported all of the 1996 writeoffs as " disallowed replace-ment energy costs" in our Consolidated Statements of Income. Constellation Real Estate Most of the Constellation Holdings Companies' real estate pr jects are in the Baltimore-Washington corridor. The area has Cahmia h Nh 4hs The Constellation Holdings Companies have $261 million invested had a surplus of available land and office space in recent years, dunng a time of low economic growth and corporate downsizings. in 16 projects that sell electricity in California under power The projects have been economically hurt by these conditions. I purchase agreements called

Interim Standard Offer No. 4" agreements. Earnings from these projects were $37.3 million, The Constellation Holdings Companies' real estate portfolio has or $.25 per share, in 1997.

continued to incur carrying costs and depreciation over the years. Additionally, the Constellation Holdings Companies have been Under these agreernents, the projects supply electricity to utilit/ charging interest payments to expense rather than capitalizing companies Lt: them for some undeveloped land where development activities o a fixed rate for capacity and energy for the first 10 years of have stopped. These carrying costs, depreciation, and interest the agreements, and expenses have decreased earnings and are expected to continue O a fixed rate for capacity plus a variable rate for energy to do so. based on the utilities' avoided cost for the remaining term Cash flow from real estate operations has not been enough to of the agreements, make the monthly loan payments on some of these projects. Generally, a " capacity rate" is paid to a power plant for its avaig Cash shortfalls have been covered by cash from Constellation i abilhy to supply electricity, and an

energy rate" is paid for the Holdings. Constellation Holdings obtained those funds from the i

electricity actually generated. " Avoided cost" generally is the cost cash flow from other Constellation Holdings Companies and of a U1lity's cheapest next-available source of generation to through additional borrowing, servi'e the demands on its system. We consider market demand, interest rates, the availability of We use the term transition period to describe the timeframe financing, and the strength of the economy in general when l when the 10-year periods for fixed energy rates expire for these making decisions about our real estate investments. We believe l 16 power generation projects and they begin supplying electricity that until the economy shows sustained growth and there is more at variable rates. The transition period for some of the projects demand for new development, our real estate values will not began in 1996 and will continue for the remaining projects improve much, if we were to sell our real estate projects in the through 2000. At the date of this report, six projects had already current market, we would have losses, although the amount of transitioned to variable rates and three other projects will trant p the losses is hard to predict. ( tion in 1998. The remaining seven projects will transition in 1999 Management's current real estate strategy is to hold each real or 2000, estate project until we can realize a reasonable value for it. The projects that have already transitioned to variable rates have Management evaluates strategies for all its businesses, including had lower revenues under variable rates than they did under fixed real estate, on an ongoing basis. We anticipate that competing rates. However, we have not yet experienced total lower eamings demands for our financial resources and changes in the utility from the Califomia projects because the combined revenues from industry will cause us to evaluate thoroughly all diversified busi the remaining projects, which continued to supply electricity at ness strategies on a regular basis so we use capital and other fixed rates, were high enough to offset the lower revenues from resources in a manner that is most beneficial. Depending on the variable-rate projects. When the remaining projects transition market conditions in the future, we could also have losses on to variable rates, we expect the revenues from those projects to any future sales. also be lower than they are under fixed rates. It is difficult to estk mate how much lower the revenues may be, but the Constellation Baltimore Gas and Electnc Company and Subsidianes 53

lt may be helpful for you to understand when we ara requirrd, by a a $14.1 million after-tax write down of the investment in cccounting rules, to writa down the value of a reti estate invest. Church Street Station-an entertainment, dining, and retail ment to market value. A write down is required in either of two complex in Orlando, Florida-which occurred because the cases. The first is if we change our intent about a project from Constellation Holdings Companies have now decided to sell En latent to hold to an intent to sell and the market value of that rather than keep the project, and projrct is below book value. The second is if the expected cash a a $31.9 million after-tax write-down of the investment in flow from the pro;ect is less than the investment in the project. Piney Orchard-a mixed-use, planned unit development-which occurred because the expected cash flow from the In 1997, the Constellation Holdings Companies recorded the project was less than the Constellation Holdings following write downs of their investments in two projects: Companies investment in the project. Nots 13. Fair Value of Mnarclal instruments We show the carrying amounts and fair values of financial instru-Investments and Other Assets ments included in our Consolidated Balance Sheeti, b the following PracticaWe to Estimate Fair Melee table, and we describe some of the items separately below, investments and other assets include Investments in common l At December 31, 1997 1996 and preferred securities, which are classified as financial invest-ments in our Consolidated Balance Sheets, and the nuclear carrying Fair carrying Fair Amount value Amount value decommissioning trust fund. We base the fair value of invest-(in millions) ments and other assets on quoted market prices where available. C:sh and cash equivalents $182.8 $182.8 $66.7 $66.7 Net accounts receivable 419.8 41$.8 419.5 419.5 Not PracticaWe to Estimate Fair lelue Other current assets 128.8 128.8 75.0 75.0 it was not practicable to estimate the fair value of the ' investments and other Constellation Holdings Companies' investments in: assets for which it is: a several financial partnerships that invest in nonpublic Practicable to debt and equity securities, estimate fair value 197.4 198.8 184.5 185.7 e several partnerships that own solar powered energy Not practicable to production facilities, and 62.2 a a company involved in developing international power estimate fair value 57.5 Short-term borrowings 318.1. 318.1 333.2 333.2 projects. Current portions of long-term debt and preference stock 271.9 271.9 280.8 280.8 investments are difficult to predict. We report these investments ren bilities 4 9 Deferred credits and The investments in financial partnerships totaled $43.6 million at other liabilities 9.8 9.8 December 31,1997 and $48.1 million at December 31,1996, Long-term debt 2,988.9 3,089.8 2,758.8 2,767.7 representing ownership interests up to 10E The total assets of R:deemable preference all of these partnerships totaled $6 billion at December 31,1996 stock ' 90.0 93.5 134.5 141.6 (which is the latest information avallable). The investments in solar powered energy production facility Other Currnnt Assets and Other Current 1. labilities partnerships totaled $10.9 million at December 31,1997 and The financial instruments included in other current assets are $11.0 million December 31,1996, representing ownership trading securities and miscellaneous loans receivable of the interests up to 12E The total assets of all of these partnerships Constsilation Holdings Companies. The financial instrument 9 totaled $39.8 million at December 31,1996 (which is the latest included in other current liabilities are the total current liabilities information Wallable), from our Consolidated Balance Sheets excluding short-term borrowings, current portions of long-term debt and preference 1.ong-Term Debt and Preference Stock stock, accounts payable, and accrued vacation costs. The We estimate the fair value of flxed rate long-term debt and carrying amounts of current assets and current liabilities are the redeemable preference stock using quoted market prices where . Same Es their fair values because these instruments have short available or by dmcounting remaining cash flows at current maturities. market rates. The carrying amount of variable-rate long-term debt approximates fair value. Guarantees it was not practicable to determine the fair value of certain loan guarantees of BGE and the Constellation Holding? Companies. BGE guaranteed outstanding debt of $20 million at December 31,1997 and $21 million at December 31,1996. The Constellation Holdings Companies guaranteed outstanding debt totaling $43 million at December 31,1997 and $47 million at December 31,1996. We do not anticipate that we will need to fund these guarantees. 54 Bartimore Gas and Electnc Company and Subsidiar6es x

Noto 14. Quarterly Financirl Etats (Unaudited) Our quarterly financial information has not been audited but, in management's opinion, includes all adjustments necessary for a fair presentation. Our utility business is seasonal in nature with the peak sales periods generally occurring duririg the summer and winter months. Accordingly, comparisons among quarters of a year may nu epresent overall trends and changes in operations. 1997 Quarterly Data 1996 Quarterly Data Eamvigs Earmngs Earmngs Earmngs income Appicable Per Share trcome Appicable Per Share from heet to Common of Common From Peet to Common of Common Revenues Operatens income Stock Stock Amenues Operatens income Stock Stock (In millions, except per-share amounts) (In millions, except per-share amounts) Quarter Ended: Quarter Ended: March 31 $ 887.7 $183.9 $ 72.1 $ 64.2 $0.43 March 31 $ 861.3 $201.3 $100.8 $ 91.1 $0.62 e June 30 746.4 78.8 15.0 7.1 0.05 June 30 731.7 148.6 64.5 52.4 0.36 September 30 860.8 321.0 171.4 164.4 1.11 September 30 826.0 275.7 146.5 137.9 0.93 December 31 312.7 159.9 24.3 18.4 0.12 December 31 734.2 43.9 (1.0) (9.1) (0.06) Year Ended: Year Ended: December 31 $3,307.6 $723.6 $282.8 $254.1 $1.72 December 31 $3.153.2 $669.5 $310.8 $272.3 $1.85 Our first quarter results include a $12.0 million after-tax write-Our second quarter results include a: down, by the Constellation Holdings Companies, of an investment in a real estate project (see Note 22). a $4.5 million aftertax writeoff of disallowed replacement energy costs (see Note 12). Our second quarter resu'ts include a $31.9 million after-tax write-a $14.6 million after-tax gain on the sale by a Constellation down, by the Constellation Holdings Companies, of an investment partnership of a power purchase agreement (see Note 3). In a real estate project (see Note 12). m $7.0 million after-tax write-off of the Constellation Holdings I Our fourth quarter results include a: Companies' investment in two geothermal wholesale power i generating projects (see Note 3). l c $37.5 million aftertax writeoff of merger costs (see Note 12). m $3.0 million after-tax write off, by the Constellation Holdings a $2.1 million after-tax write down, by the Constellation Companies, of development costs for a coalfired power Holdings Companies, of an investment in a real estate project (see Note 3). project (see Note 12). Our third quarter results include a $6.2 million aftertax write off by the Constellation Holdings Companies of a portion of a solar I power project investment (see Note 3). Our fourth quarter results include a $57.6 million after-tax write-off of disallowed replacement energy costs (see Note 12). l The sum of the quarterly eamings per share amounts may not equal the total for the year due to the effects of rounding. t l l l i Bittimore Gas and Electric Company and SubSidianes 55

Conrds cf Dirccters Caltimore Gas and Electric Company l Christian H. Poindexter Jerome W. Geckle 59, Chairman of the Board and -ig 68, Retired Chairman of the Board, Chief Executive Officer, BGE j.l ' ' j PHH Corporation 2 ? Freeman A. Hrabowskilli H. Furlong Baldwin f 66, Chairman of the Board and d D 47, President, University of Maryland, Chief Executive Officer, j Baltimore County Mercantile Bankshares Corporation Beverly B. Byron Nancy Lampton ,o 65, Former Congresswoman, 55, Chairman and Chief Executive Officer, J U.S. House of Representatives Ari.arican Life and Accident Insurance Company of Kentucky a

1 J. Owen Cole George V. McGowan

68. Director, First Maryland Bancorp; 70, Former Chairman of the Board and Chief Executive Officer, BGE Chairman, First National Bank of Maryland f ~

Trust Committee (1 gs 9 Dan A. Colussy p ""r*ts George L. Russell, Jr., Esq. I 66, Former Chairman of the Board and 7 68, Partner, Piper & Marbury Chief Executive Officer, UNC, incorporated q (- 1. t Michael D. Sullivan Edward A. Crooke {[w ~]$3 58, Chairman of the Board, ff 59, President and w 1 Chief Operating Officer, BGE t Golf America Stores, Inc. I' [j[ ( r l James R. Curtiss, Esq. 44, Partner, Winston & Strawn h 7J 56 Daltimore Gas and Electnc Company and Subsidianes

Constellation Enterprises *,Inc.* Constellation Energy Solutions, Inc.*

Comadttees of the bee Board Edward A. Crooke 59, Chairman of the Board; Audit Committee President and Chief Operating Officer, BGE J. Owen Cole, Chairman Beverly B. Byron Bruce M. Ambler e

Freeman A. Hrabowski Ill 58, President and Chief Executive Officer, George L. Russell, Jr. Constellation Holdings H. Furlong Baldwin Committee on Management a 66, Chairman of the Board and Chief Executive Officer, Jerome W. Geckle, Chairman Mercantile Bankshares Corporation J. Owen Cole Dan A. Colussy Roger W. Gak Michael D. Sullivan 51, President, Washington International Energy Group Committee on Nuclear Power Jerome W. Geckle Dan A. Colussy, Chairman 68, Retired Chairmar of the Board, PHH Corporation Beverly B. Byron James R. Curtiss I George V. McGowan 70, Retired Cochairman and Chief Operating Officer, Ernst & Young 1.ong-Range Strategy Committee George V. McGowan H. Furlong Baldwin, Chairman 70, Former Chairman of the Board and James R. Curtiss Chief Executive Officer, BGE E*' Christian H. Poindexter e ecM Nancy Lampton 59, Chairman of the Bordd and Chief Executive Officer, BGE Michael D. Sullivan Mayo A. Shattuck 111 43, C& Chairman and CoChief Executive Officer, Exec'.:tive Committee BT Alex. Brown, Inc. George V. McGowan, Chairman Charles W. Shivery H. Furlong Baldwin 52, President, Constellation Energy Solutions: Edward A. Crooke President and Chief Executive Officer, Freeman A. Hrabowski til Constellation Power Source Christian H. Poindexter George L. Russell, Jr.

Constellation Enterprises, Inc. was established on Committee on Workplace Diverstty January 23,1998, as a holding company for Constellation Beverly B. Byron, Chairwoman Holdings, Inc. and BGE Home Products & Services, Inc.

James R. Curtiss Freeman A. Hrabowski Ill

*In 1997 Constellation Energy Solutions, Inc. became the Nancy Lampton holding company for Constellation Power Source, Inc.,

Constellation Energy Source, Inc., and Constellation Energy Projects & Services. Inc. i l BIftimore Gas and Dectric Company and Subsidiaries 57

~ Officers Baltimore Gas and Electric E,ornpany Constellation Enterprises, Inc. Christian H. Poindexter Constellation Holdings cr-.-- *:: 59, Chairman of the Board end Chief Executive Officer Edward A. Crooke Edward A.Crooke 59, Chairman of the Board, Constellation Holdings 59, President and Chief Operating Officer Bruce M. Ambler Robert E. Denton 58, President end Chief Executive Officer, 55, Senior Vice President, Generation Constellation Holdings Thomas F. Brady Randall M. Griffin 48, Vice President, Customer Service & Distribution 53, President, Constellation Real Estate Group David A. Brune Ronald F. Watson 57, Vice President, Finance & Accounting: 49, President, Constellation Health Services Chief Financial Officer and Secretary Steven D. Kesler Charles H. Cruse 46, President, Constellation Investments 53, Vice President, Nuclear Energy John F. Nalter Carserlo Doyle 63, Pr sident, Constellation Power 55, Vice President, Electric Interconnection & Transmission Robert E. Windham Frank O. Heintz 55, President, Church Street Station 53, Vice President, Gas Sharon S. Hostetter BGE Home Products & Services, Inc. 53, Vice President, Marketing & Sales Edward A. Crooke Ronald W. Lowman 59, Chairman of the Board 53, Vice President, Fossil Energy William H. Munn Gregory C. Martin 50, President and Chief Executive Officer 49, Vice President, General Services Unda D. Miller 47, Vice President, Management Services Constellation Energy Solutions, Inc. and Subsidiaries S F. WW Edward A. Crooke 45, Vice President 59, Chairman of the Board, Constellation Energy Solutions Richard M. Bange, Jr. Charles W. Shivery 53, Controller and Ass. tant Secretary is

52. President, Constellation Energy Solutions; Thomas E. Rustin, Jr.

President and Chief Executive Officer, 43, Treasurer and Assistant Secretary Constellation Power Source Diane L Featherstone 44, President, Constellation Energy Source Stephen F. Wood 45, President, Constellation Energy Projects & Services 58 Baltimore Gas and Electric Company and subsidianes

Hve-Yxr Stati;tisci Summ:ry 1997 1996 1995 1994 1993 conunon stock pata Quarterly Esmirnge Per Share First Quarter $0.43 $0.62 $0.41 $0.49 $0.38 Second Quarter 0.05 0.36 0.28 0.39 0.31 Third Quarter 1.11 0.93 1.04 0.79 1.01 Fourth Quarter 0.12 (0.06) 0.29 0.26 0.14 o Total $1.72 $1.85 $2.02 $1.93 $1.85 DivMende Dividends Declared Per Share $1.63 $1.59 $1.55 $1.51 $1.47 Dividends Paid Per Share 1.62 1.58 1.54 1.50 1.46 Dividend Payout Ratio Reported 94.8% 85.9% 76.7% 78.2% 79.5% Excluding nonrecurring charges to earnings 71.5% 70.0% ' 76.7% 78.2% 79.5% Market Prices High $34'4e $29*h $29 $254 $27h 2 2 Low 24*A 25 22 20 4 22 4 2 8 j 1 2 2 8 Close 34 4 26'A 28 4 22 4 25A j cas tal structure f e Consolidated l Long-Term Debt 48.0% 45.0% 42.8% 46.1% 47.4% Short-Term Debt 4.7 5.1 4.4 1.0 ) Preferred and Preference Stock 4.8 6.5 8.5 8.9 9.2 j Common Shareholders' Equity 42.5 43.4 44.3 44.0 43.4 l Utility Only Long-Term Debt 45.4% 42.5% 40.4% 43.5% 44.5% Short-Term Debt 5.8 6.1 5.2 1.2 Preferred and Preference Stock 5.9 7.8 10.0 10.6 10.9 Common Shareholders' Equity 42.9 43.6 44.4 44.7 44.6 i The sum of the quarterly earnings per share amounts may not equal the total for the year due to the effects of rounding and changes in the average number of shares outstanding thraghout the year. e The quarterly eamirigs per sharo amounts include certain onetime adjustments as shown in Note 14 to the Consolidated Financial I Statements. B:ttimore Gas and Dectnc Company and Subsidiaries 59 1 l 1 ______________-___A

Shrrcholder Inform tien Common Stock Dividends and Price Ranges 1997 1996 j Dividend Price Dividend Price Declared High Low Declarad High Low First Quarter $.40 $28 $26% $.39 $29% $26% Second Quarter .41 27 24% .40 28% 25% Third Quarter .41 28hs 26 .40 28% 25 25 hs .40 28h 25h Fourth Quarter .41 34b 2 Total $1.63 $1.59 Dividend Policy Annual Meeting The common stock is entitled to dividends when and as declared The annual meeting of shareholders will be held at 10 a.m. by the Board of Directors. There are no limitations in ary inden-on Friday, April 24,1998, at the Morris Mechanic Theatre, ture or other agreements on payment of dividends. Holders of 1 North Charles Street (entrance on Hopkins Plaza), Baltimore, preferred stock (first) and holders of preference stock (next), Maryland 21201, however, are entitled to receive, when and as declared from the surplus or net profits, cumulative yearly dividends at the fixed Form 10 K preferential rate specified for each series and no more, payable Upon written request, the company will fumish, without charge, quarterly. They are also entitled to receive, when due, the applio-a copy of its Annual Report on Form 10-K, including financial able preference stock redemption payments before any dividend statements, after it is filed with the Securities and Exchange on the common stock shall be paid or set apart. Dividends have Commission in March 1998. Requests should be addressed been paid on the common stock continuously since 1910. Future to David A. Brune, Chief Financial Officer and Secretary, dividends depend upon future earnings, the financial condition of Vice President, Finance & Accounting, P.O. Box 1475, the company, and other factors. Quarterly dividends were Baltimore, Maryland 21203-1475. declared on the common stock during 1997 and 1996 in the amounts shown above. Auditors Coopers & Lybrand L.L.P. Contnen Stock Dividend Dates Executive Offices Record dates are normally on the 10th of March, June, Gas and Electric Building September, and December. Quarterly dividends are es M w customarily mailed to each shareholder on or about th Baltimore, Maryland 21201 ist of April, July, October, and January. Mail: P.O. Box 1475 Baltimore, Maryland 212031475 Dividend Reinvestment and Stock Purchase Plan The company's Dividend Reinvestment and Stock Purchase Plan provides an opportunity for holders of the company s common S aWae2MwelmM stock to acquire additional shares of such stock in a convenient ahu MeE and economical manner. Participants in the plan may reinvest fem w h mttem M call M 2a@lh cash dividends on all or a portion of their shares of common i ese@th m m MlWee tele @e Mm stock and/or make optional cash payments. The following toll-free telephone numbers are available Stock Trading during our business hours,8 a.m. to 4:45 p.m.: The cornpany's common stock, which is traded under the Baltimore Metropolitan Area 410 783-5920 ticker symbol BGE, is listed on the New York, Chicago, and Within Maryland 1-800-492-2861 Pacific stock exchanges, and has unlisted trading privileges on Outside of Maryland 1-800L2584499 the Boston, Cincinnati, and Philadelphia exchanges. As of Letters should be addressed to: December 31,1997, there were 73,694 common shareholders Baltimore Gas and Electric Company of record. Shareholder Services P.O. Box 1642 Tran for Agent and Registrar B ltimore, Maryland 21203-1642 Harris Trust and Savings Bank Chicago, Illinois 60 Battirnore Gas and Dectne company and subsidianes

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