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FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended March 31, 1996
Commission file number 1-1910
BALTIMORE GAS AND ELECTRIC COMPANY
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(Exact name of registrant as specified in its charter)
Maryland 52-0280210
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(State of incorporation) (IRS Employer Identification No.)
39 W. Lexington Street Baltimore, Maryland 21201
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code 410-783-5920
Not Applicable
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(Former name, former address and former fiscal year, if changed
since last report)
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months,
and (2) has been subject to such filing requirements for the past
90 days.
Yes X No
Common Stock, without par value - 147,527,114 shares outstanding
on April 30, 1996.
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BALTIMORE GAS AND ELECTRIC COMPANY
PART I. FINANCIAL INFORMATION
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
<TABLE>
<CAPTION>
Three Months Ended March 31,
1996 1995
(In Thousands, Except Per-Share Amounts)
<S> <C> <C>
Revenues
Electric $554,444 $507,825
Gas 219,264 152,784
Diversified businesses 87,622 57,198
Total revenues 861,330 717,807
Expenses Other Than Interest and Income Taxes
Electric fuel and purchased energy 153,852 147,454
Gas purchased for resale 129,028 81,803
Operations 132,168 131,535
Maintenance 34,440 36,881
Diversified businesses-selling,general,administrative 67,573 41,109
Depreciation and amortization 85,399 76,678
Taxes other than income taxes 57,555 54,125
Total expenses other than interest and income taxes 660,015 569,585
Income From Operations 201,315 148,222
Other Income
Allowance for equity funds used during construction 1,965 5,369
Equity in earnings of Safe Harbor Water Power Corp 1,123 1,108
Net other income and deductions (2,147) (2,611)
Total other income 941 3,866
Income Before Interest and Income Taxes 202,256 152,088
Interest Expense
Interest charges 52,718 54,978
Capitalized interest (3,152) (3,484)
Allowance for borrowed funds used during construction (1,063) (2,905)
Net interest expense 48,503 48,589
Income Before Income Taxes 153,753 103,499
Income Taxes
Current 46,899 (3,033)
Deferred 7,986 37,706
Investment tax credit adjustments (1,913) (2,027)
Total income taxes 52,972 32,646
Net Income 100,781 70,853
Preferred and Preference Stock Dividends 9,663 9,951
Earnings Applicable to Common Stock $91,118 $60,902
Average Shares of Common Stock Outstanding 147,527 147,527
Earnings Per Share of Common Stock $0.62 $0.41
Dividends Declared Per Share of Common Stock $0.39 $0.38
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been restated to conform with the current year's presentation.
</TABLE>
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PART I. FINANCIAL INFORMATION (Continued)
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
March 31 December 31,
1996* 1995
(In Thousands)
<S> <C> <C>
ASSETS
Current Assets
Cash and cash equivalents $ 116,890 $ 23,443
Accounts receivable (net of allowance for uncollectibles
of $16,995 and $16,390 respectively) 432,367 400,005
Fuel stocks 39,576 59,614
Materials and supplies 148,798 145,900
Prepaid taxes other than income taxes 27,918 60,508
Deferred income taxes 26,170 36,831
Trading securities 61,670 47,990
Other 16,325 31,487
Total current assets 869,714 805,778
Investments and Other Assets
Real estate projects 481,759 479,344
Power generation systems 363,373 358,629
Financial investments 202,851 205,841
Nuclear decommissioning trust fund 99,355 85,811
Net pension asset 70,220 60,077
Safe Harbor Water Power Corporation 34,331 34,327
Senior living facilities 16,860 16,045
Other 74,575 71,894
Total investments and other assets 1,343,324 1,311,968
Utility Plant
Plant in service
Electric 6,398,127 6,360,624
Gas 709,338 692,693
Common 527,384 522,450
Total plant in service 7,634,849 7,575,767
Accumulated depreciation (2,534,968) (2,481,801)
Net plant in service 5,099,881 5,093,966
Construction work in progress 240,410 247,296
Nuclear fuel (net of amortization) 126,993 130,782
Plant held for future use 25,870 25,552
Net utility plant 5,493,154 5,497,596
Deferred Charges
Regulatory assets (net) 607,952 637,915
Other deferred charges 68,354 63,406
Total deferred charges 676,306 701,321
TOTAL ASSETS $ 8,382,498 $ 8,316,663
* Unaudited
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current year's presentation.
</TABLE>
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PART I. FINANCIAL INFORMATION (Continued)
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
March 31 December 31,
1996* 1995
(In Thousands)
<S> <C> <C>
LIABILITIES AND CAPITALIZATION
Current Liabilities
Short-term borrowings $ 284,845 $ 279,305
Current portions of long-term debt, preferred stock,
and preference stock 195,082 146,969
Accounts payable 165,499 177,092
Customer deposits 27,568 26,857
Accrued taxes 62,459 8,244
Accrued interest 52,924 56,670
Dividends declared 67,198 67,198
Accrued vacation costs 35,955 33,403
Other 14,644 39,417
Total current liabilities 906,174 835,155
Deferred Credits and Other Liabilities
Deferred income taxes 1,308,214 1,311,530
Pension and postemployment benefits 156,233 148,594
Decommissioning of federal uranium enrichment facilities 43,694 43,695
Other 56,195 55,568
Total deferred credits and other liabilities 1,564,336 1,559,387
Capitalization
Long-term Debt
First refunding mortgage bonds of BGE 1,538,528 1,538,528
Other long-term debt of BGE 639,000 649,500
Long-term debt of Constellation Companies 561,141 546,903
Unamortized discount and premium (15,247) (15,708)
Current portion of long-term debt (109,897) (120,969)
Total long-term debt 2,613,525 2,598,254
Preferred Stock 59,185 59,185
Current portion of preferred stock (59,185) -
Total preferred stock - 59,185
Redeemable Preference Stock 268,000 268,000
Current portion of redeemable preference stock (26,000) (26,000)
Total redeemable preference stock 242,000 242,000
Preference Stock Not Subject to Mandatory Redemption 210,000 210,000
Common Shareholders' Equity
Common stock 1,425,645 1,425,805
Retained earnings 1,415,000 1,381,417
Net unrealized gain on available-for-sale securities 5,818 5,460
Total common shareholders' equity 2,846,463 2,812,682
Total capitalization 5,911,988 5,922,121
TOTAL LIABILITIES AND CAPITALIZATION $ 8,382,498 $ 8,316,663
* Unaudited
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current year's presentation.
</TABLE>
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PART I. FINANCIAL INFORMATION (Continued)
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
<TABLE>
<CAPTION>
Three Months Ended March 31,
1996 1995
(In Thousands)
<S> <C> <C>
Cash Flows From Operating Activities
Net income $100,781 $ 70,853
Adjustments to reconcile to net cash provided by
operating activities
Depreciation and amortization 100,141 92,102
Deferred income taxes 7,986 37,706
Investment tax credit adjustments (1,913) (2,017)
Deferred fuel costs 15,009 10,366
Accrued pension and postemployment benefits (3,174) (5,037)
Allowance for equity funds used during construction (1,965) (5,369)
Equity in earnings of affiliates and joint ventures (net) (1,038) 2,995
Changes in current assets, other than
sale of accounts receivable 19,978 30,893
Changes in current liabilities, other than
short-term borrowings 17,305 (43,687)
Other 3,331 10,124
Net cash provided by operating activities 256,441 198,929
Cash Flows From Financing Activities
Proceeds from issuance of
Short-term borrowings (net) 5,540 (35,900)
Long-term debt 21,729 10,641
Common stock (159) 14
Reacquisition of long-term debt (18,149) (5,789)
Common stock dividends paid (57,536) (56,060)
Preferred and preference stock dividends paid (9,663) (9,952)
Other (353) (748)
Net cash used in financing activities (58,591) (97,794)
Cash Flows From Investing Activities
Utility construction expenditures (69,655) (81,395)
Allowance for equity funds used during construction 1,965 5,369
Nuclear fuel expenditures (9,153) (6,576)
Deferred energy conservation expenditures (5,493) (10,226)
Contributions to nuclear decommissioning trust fund (12,260) (2,445)
Purchases of marketable equity securities (11,702) (4,395)
Sales of marketable equity securities 11,670 18,127
Other financial investments 5,524 5,041
Real estate projects (3,585) (11,266)
Power generation systems (10,116) (15,960)
Other (1,598) (1,868)
Net cash used in investing activities (104,403) (105,594)
Net Increase (Decrease) in Cash and Cash Equivalents 93,447 (4,459)
Cash and Cash Equivalents at Beginning of Period 23,443 38,590
Cash and Cash Equivalents at End of Period $116,890 $ 34,131
Other Cash Flow Information
Cash paid during the period for:
Interest (net of amounts capitalized) $ 52,391 $ 47,403
Income taxes $ (9,985) $ 153
See Notes to Consolidated Financial Statem
Certain prior-year amounts have been restated to conform with the current year's presentation.
</TABLE>
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Results for interim periods, which can be largely influenced
by weather conditions, are not necessarily indicative of results
to be expected for the year.
The preceding interim financial statements of Baltimore Gas
and Electric Company (BGE) and Subsidiaries (collectively, the
Company) reflect all adjustments which are, in the opinion of
Management, necessary for the fair presentation of the Company's
financial position and results of operations for such interim
periods. These adjustments are of a normal recurring nature.
BGE Financing Activity
There have been no issuances of long-term debt or equity
securities during the period from January 1, 1996 through the
date of this report.
In March 1996, the Company called for redemption of BGE's
entire class of Preferred Stock. The following is a summary of
the series redeemed:
Price
Shares Per Share
Series B, 4-1/2% Cumulative
Preferred Stock, $100 par value 222,921 $110
Series C, 4% Cumulative
Preferred Stock, $100 par value 68,928 $105
Series D, 5.40% Cumulative
Preferred Stock, $100 par value 300,000 $101
BGE may purchase First Refunding Mortgage Bonds of various
series in open market transactions, from time to time in the
future, depending upon market conditions and BGE's assessment of
optimal capital structure, including the mix of secured and
unsecured debt.
Diversified Business Financing Matters
See Management's Discussion and Analysis of Financial
Condition and Results of Operations - Diversified Businesses
Capital Requirements for additional information about the debt of
Constellation Holdings, Inc. and its subsidiaries.
Pending Merger with Potomac Electric Power Company
BGE, Potomac Electric Power Company (PEPCO), and
Constellation Energy Corporation (formerly named "RH Acquisition
Corp.") (CEC), have entered into an Agreement and Plan of Merger,
dated as of September 22, 1995 (the Merger Agreement). CEC was
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formed to accomplish the merger and its outstanding capital stock
is owned 50% by BGE and 50% by PEPCO. The Merger Agreement
provides for a strategic business combination that will be
accomplished by merging both BGE and PEPCO into CEC (the Merger).
The Merger, which was unanimously approved by the Boards of
Directors of BGE and PEPCO and approved by the shareholders of
both companies, is expected to close during 1997 after all other
conditions to the consummation of the Merger, including obtaining
applicable regulatory approvals, are met or waived. In
connection with the Merger, BGE common shareholders will receive
one share of CEC common stock for each BGE share and PEPCO common
shareholders will receive 0.997 of a share of CEC common stock
for each PEPCO share.
Preliminary estimates by the managements of PEPCO and BGE
indicate that the synergies resulting from the combination of
their utility operations could generate net cost savings of up to
$1.3 billion over a period of 10 years following the Merger.
These estimates indicate that about two-thirds of the savings
will come from reduced labor costs, with the remaining savings
split between nonfuel purchasing and corporate and administrative
programs. These savings are expected to be allocated among
shareholders and customers. This allocation will depend upon the
results of regulatory proceedings in the various jurisdictions in
which BGE and PEPCO operate their utility businesses. The
analyses employed in order to develop estimates of the potential
savings as a result of the Merger were necessarily based upon
various assumptions which involve judgments with respect to,
among other things, future national and regional economic and
competitive conditions, inflation rates, regulatory treatment,
weather conditions, financial market conditions, interest rates,
future business decisions and other uncertainties, all of which
are difficult to predict and many of which are beyond the control
of BGE and PEPCO. Accordingly, while BGE believes that such
assumptions are reasonable for purposes of the development of
estimates of potential savings, there can be no assurance that
such assumption will approximate actual experience or that all
such savings will be realized.
The reasons for the Merger, the terms and conditions
contained in the Merger Agreement, and other matters concerning
the Merger, PEPCO, and CEC are discussed in more detail in the
Registration Statement on Form S-4 (Registration No. 33-64799)
which is included as an exhibit to this Report on Form 10-Q by
incorporation by reference.
Environmental Matters
The Clean Air Act of 1990 (the Act) contains two titles
designed to reduce emissions of sulfur dioxide and nitrogen oxide
(NOx) from electric generating stations. Title IV contains
provisions for compliance in two separate phases. Phase I of
Title IV became effective January 1, 1995, and Phase II of Title
IV must be implemented by 2000. BGE met the requirements of
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Phase I by installing flue gas desulfurization systems and fuel
switching and through unit retirements. BGE is currently
examining what actions will be required in order to comply with
Phase II of the Act. However, BGE anticipates that compliance
will be attained by some combination of fuel switching, flue gas
desulfurization, unit retirements, or allowance trading.
At this time, plans for complying with NOx control
requirements under Title I of the Act are less certain because
all implementation regulations have not yet been finalized by the
government. It is expected that by the year 1999 these
regulations will require additional NOx controls for ozone
attainment at BGE's generating plants and at other BGE
facilities. The controls will result in additional expenditures
that are difficult to predict prior to the issuance of such
regulations. Based on existing and proposed ozone nonattainment
regulations, BGE currently estimates that the NOx controls at
BGE's generating plants will cost approximately $90 million. BGE
is currently unable to predict the cost of compliance with the
additional requirements at other BGE facilities.
BGE has been notified by the Environmental Protection Agency
and several state agencies that it is being considered a
potentially responsible party with respect to the cleanup of
certain environmentally contaminated sites owned and operated by
third parties. In addition, a subsidiary of Constellation
Holdings, Inc. has been named as a defendant in a case concerning
an alleged environmentally contaminated site owned and operated
by a third party. Cleanup costs for these sites cannot be
estimated, except that BGE's 15.79% share of the possible cleanup
costs at one of these sites, Metal Bank of America, a metal
reclaimer in Philadelphia, could exceed amounts BGE has
recognized by up to approximately $7 million based on the highest
estimate of costs in the range of reasonably possible
alternatives. Although the cleanup costs for certain of the
remaining sites could be significant, BGE believes that the
resolution of these matters will not have a material effect on
its financial position or results of operations.
Also, BGE is coordinating investigation of several former
gas manufacturing plant sites, including exploration of
corrective action options to remove tar. However, no formal legal
proceedings have been instituted against BGE. BGE has recognized
estimated environmental costs at these sites totaling $38.6
million as of March 31, 1996. These costs, net of accumulated
amortization, have been deferred as a regulatory asset. The
technology for cleaning up such sites is still developing, and
potential remedies for these sites have not been identified.
Cleanup costs in excess of the amounts recognized, which could be
significant in total, cannot presently be estimated.
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Nuclear Insurance
An accident or an extended outage at either unit of the
Calvert Cliffs Nuclear Power Plant could have a substantial
adverse effect on BGE. The primary contingencies resulting from
an incident at the Calvert Cliffs plant would involve the
physical damage to the plant, the recoverability of replacement
power costs, and BGE's liability to third parties for property
damage and bodily injury. BGE maintains various insurance
policies for these contingencies. The costs that could result
from a major accident or an extended outage at either of the
Calvert Cliffs units could exceed the coverage limits.
In addition, in the event of an incident at any commercial
nuclear power plant in the country, BGE could be assessed for a
portion of any third party claims associated with the incident.
Under the provisions of the Price Anderson Act, the limit for
third party claims from a nuclear incident is $8.92 billion. If
third party claims relating to such an incident exceed $200
million (the amount of primary insurance), BGE's share of the
total liability for third party claims could be up to $159
million per incident, that would be payable at a rate of $20
million per year.
BGE and other operators of commercial nuclear power plants
in the United States are required to purchase insurance to cover
claims of certain nuclear workers. Other non-governmental
commercial nuclear facilities may also purchase such insurance.
Coverage of up to $400 million is provided for claims against BGE
or others insured by these policies for radiation injuries. If
certain claims were made under these policies, BGE and all
policyholders could be assessed, with BGE's share being up to
$6.02 million in any one year.
For physical damage to Calvert Cliffs, BGE has $2.75 billion
of property insurance from industry mutual insurance companies.
If an outage at Calvert Cliffs is caused by an insured physical
damage loss and lasts more than 21 weeks, BGE has up to $473.2
million per unit of insurance, provided by an industry mutual
insurance company, for replacement power costs. This amount can
be reduced by up to $94.6 million per unit if an outage to both
units at Calvert Cliffs is caused by a singular insured physical
damage loss. If accidents at any insured plants cause a
shortfall of funds at the industry mutuals, BGE and all
policyholders could be assessed, with BGE's share being up to
$44.1 million.
Recoverability of Electric Fuel Costs
By statute, actual electric fuel costs are recoverable so
long as the Public Service Commission of Maryland (PSC) finds
that BGE demonstrates that, among other things, it has maintained
the productive capacity of its generating plants at a reasonable
level. The PSC and Maryland's highest appellate court have
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interpreted this as permitting a subjective evaluation of each
unplanned outage at BGE's generating plants to determine whether
or not BGE had implemented all reasonable and cost-effective
maintenance and operating control procedures appropriate for
preventing the outage. Effective January 1, 1987, the PSC
authorized the establishment of a Generating Unit Performance
Program (GUPP) to measure, annually, utility compliance with
maintaining the productive capacity of generating plants at
reasonable levels by establishing a system-wide generating
performance target and individual performance targets for each
base load generating unit. In future fuel rate hearings, actual
generating performance after adjustment for planned outages will
be compared to the system-wide target and, if met, should signify
that BGE has complied with the requirements of Maryland law.
Failure to meet the system-wide target will result in review of
each unit's adjusted actual generating performance versus its
performance target in determining compliance with the law and the
basis for possibly imposing a penalty on BGE. Parties to fuel
rate hearings may still question the prudence of BGE's actions or
inactions with respect to any given generating plant outage,
which could result in the disallowance of replacement energy
costs by the PSC.
Since the two units at BGE's Calvert Cliffs Nuclear Power
Plant utilize BGE's lowest cost fuel, replacement energy costs
associated with outages at these units can be significant. BGE
cannot estimate the amount of replacement energy costs that could
be challenged or disallowed in future fuel rate proceedings, but
such amounts could be material.
In October 1988, BGE filed its first fuel rate application
for a change in its electric fuel rate under GUPP. The resultant
case before the PSC covers BGE's operating performance in
calendar year 1987, and BGE's filing demonstrated that it met the
system-wide and individual nuclear plant performance targets for
1987. In November 1989, testimony was filed on behalf of the
Maryland People's Counsel (People's Counsel) alleging that seven
outages at the Calvert Cliffs plant in 1987 were due to
management imprudence and that the replacement energy costs
associated with those outages should be disallowed by the
Commission. Total replacement energy costs associated with the
1987 outages were approximately $33 million. On
January 23, 1995, the Hearing Examiner issued his decision in the
1987 fuel rate proceeding and found that the Company had met the
GUPP standard which establishes a presumption that BGE had
operated the plant at a reasonably productive capacity level.
However, the Order found that the presumption of reasonableness
would be overcome by a showing of mismanagement and that such a
showing was made with respect to the environmental qualifications
outage time. In mitigation for meeting the GUPP standard, the
Hearing Examiner disallowed replacement energy costs recovery for
15.5 days of the 66-day outage time. The Hearing Examiner's
Order was appealed to the PSC by both BGE and People's Counsel.
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If the PSC upholds the Hearing Examiner, the Company's earnings
would be impacted by approximately $4.5 million.
In May 1989, BGE filed its fuel rate case in which 1988
performance was examined. BGE met the system-wide and nuclear
plant performance targets in 1988. People's Counsel alleged that
BGE imprudently managed several outages at Calvert Cliffs, and
BGE estimates that the total replacement energy costs associated
with these 1988 outages were approximately $2 million. On
November 14, 1991, a Hearing Examiner at the PSC issued a
proposed Order, which became final on December 17, 1991 and
concluded that no disallowance was warranted. The Hearing
Examiner found that BGE maintained the productive capacity of the
Plant at a reasonable level, noting that it produced a near
record amount of power and exceeded the GUPP standard. Based on
this record, the Order concluded there was sufficient cause to
excuse any avoidable failures to maintain productive capacity at
higher levels.
During 1989, 1990, and 1991, BGE experienced extended
outages at its Calvert Cliffs Nuclear Power Plant. In the Spring
of 1989, a leak was discovered around the Unit 2 pressurizer
heater sleeves during a refueling outage. BGE shut down Unit 1
as a precautionary measure on May 6, 1989, to inspect for similar
leaks and none were found. However, Unit 1 was out of service
for the remainder of 1989 and 285 days of 1990 to undergo
maintenance and modification work to enhance the reliability of
various safety systems, to repair equipment, and to perform
required periodic surveillance tests. Unit 2, which returned to
service on May 4, 1991, remained out of service for the remainder
of 1989, 1990, and the first part of 1991 to repair the
pressurizer, perform maintenance and modification work, and
complete the refueling. The replacement energy costs associated
with these extended outages for both units at Calvert Cliffs,
concluding with the return to service of Unit 2, are estimated to
be $458 million.
In a December 1990 Order issued by the PSC in a BGE base
rate proceeding, the PSC found that certain operations and
maintenance expenses incurred at Calvert Cliffs during the test
year should not be recovered from ratepayers. The PSC found that
this work, which was performed during the 1989-1990 Unit 1 outage
and fell within the test year, was avoidable and caused by BGE
actions which were deficient.
The PSC noted in the Order that its review and findings on
these issues pertain to the reasonableness of BGE's test-year
operations and maintenance expenses for purposes of setting base
rates and not to the responsibility for replacement power costs
associated with the outages at Calvert Cliffs. The PSC stated
that its decision in the base rate case will have no res judicata
(binding) effect in the fuel rate proceeding examining the 1989-
1991 outages. The work characterized as avoidable significantly
increased the duration of the Unit 1 outage. Despite the PSC's
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statement regarding no binding effect, BGE recognizes that the
views expressed by the PSC make the full recovery of all of the
replacement energy costs associated with the Unit 1 outage
doubtful. Therefore, in December 1990, BGE recorded a provision
of $35 million against the possible disallowance of such costs.
BGE cannot determine whether replacement energy costs may be
disallowed in the present fuel rate proceeding in excess of the
provision, but such amounts could be material.
Subsequent Event
Subsequent to March 31, 1996, a subsidiary of Constellation
Holdings, Inc. realized an after-tax gain of approximately $15
million, or 10 cents per share, on the sale of its ownership
interest in a power sales contract. This gain will be reported
in earnings for the quarter ending June 30, 1996.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The financial condition and results of operations of
Baltimore Gas and Electric Company (BGE) and its subsidiaries
(collectively, the Company) are set forth in the Consolidated
Financial Statements and Notes to Consolidated Financial
Statements (Notes) sections of this Report. Factors significantly
affecting results of operations, liquidity, and capital resources
are discussed below.
RESULTS OF OPERATIONS FOR THE QUARTER ENDED MARCH 31, 1996
COMPARED WITH THE CORRESPONDING PERIOD OF 1995
Earnings per Share of Common Stock
Consolidated earnings per share were $.62 for the quarter
ended March 31, 1996 and $.41 for the quarter ended
March 31, 1995. The $.21 increase in earnings per share reflects
a higher level of earnings applicable to common stock. The
earnings per share are summarized as follows:
Quarter Ended
March 31
1996 1995
Utility operations $ .58 $ .38
Diversified businesses .04 .03
Total $ .62 $ .41
Earnings Applicable to Common Stock
Earnings applicable to common stock increased $30.2 million
during the first quarter of 1996 compared to last year as a
result of significantly higher earnings from utility operations
and slightly higher earnings from diversified businesses.
Earnings from utility operations increased during the first
quarter of 1996 primarily due to higher electric and gas system
sales resulting from the colder winter weather experienced in
1996 compared to the same period last year. The effect of weather
on utility sales is discussed on page 14.
The following factors influence BGE's utility operations
earnings: regulation by the Public Service Commission of Maryland
(PSC), the effect of weather and economic conditions on sales,
and competition in the generation and sale of electricity. The
gas base rate increase authorized by the PSC in November 1995
favorably affected utility earnings during the quarter ended
March 31, 1996. The electric fuel rate cases now pending before
the PSC discussed in Notes 1 and 12 of the Form 10-K for the year
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ended December 31, 1995 (Form 10-K) could also affect future
years' earnings.
Future competition may also affect earnings in ways that are
not possible to predict (see the discussion of "Response to
Regulatory Change" in the Form 10-K).
Earnings from diversified businesses, which primarily
represent the operations of Constellation Holdings, Inc. and its
subsidiaries (collectively, the Constellation Companies), BGE
Home Products & Services, Inc. and Subsidiary (HP&S), BGE Energy
Projects & Services, Inc. (EP&S) and BNG, Inc., increased
slightly during the quarter ended March 31, 1996 compared to the
corresponding period of 1995. Diversified businesses' earnings
are discussed on pages 20 through 22.
Effect of Weather on Utility Sales
Weather conditions affect BGE's utility sales. BGE measures
weather conditions using degree days. A degree day is the
difference between the average daily actual temperature and the
baseline temperature of 65 degrees. Colder weather during the
winter, as measured by greater heating degree days, results in
greater demand for electricity and gas to operate heating
systems. Conversely, warmer weather during the winter, measured
by fewer heating degree days, results in less demand for
electricity and gas to operate heating systems. Hotter weather
during the summer, measured by more cooling degree days, results
in greater demand for electricity to operate cooling systems.
Conversely, cooler weather during the summer, measured by fewer
cooling degree days, results in less demand for electricity to
operate cooling systems. The degree-days chart below presents
information regarding heating degree days for the quarters ended
March 31, 1996 and 1995.
Quarter Ended
March 31
1996 1995
Heating degree days............................. 2,625 2,240
Percent change compared to
prior period................................... 17.2%
BGE Utility Revenues and Sales
Electric revenues changed for the quarter ended
March 31, 1996 because of the following factors:
-14-
<PAGE>
Quarter Ended
March 31
1996 vs. 1995
(In millions)
System sales volumes $30.0
Base rates 5.2
Fuel rates 1.2
Revenues from system sales 36.4
Interchange and other sales 9.4
Other revenues 0.8
Total $46.6
Electric system sales represent volumes sold to customers within BGE's
service territory at rates determined by the PSC. These amounts
exclude interchange sales and sales to other utilities, which are
discussed separately. Following is a comparison of the changes in
electric system sales volumes:
Quarter Ended
March 31
1996 vs. 1995
Residential 15.2%
Commercial 3.7
Industrial 4.4
Total 8.6
Sales to residential customers increased compared to last
year due primarily to colder winter weather and greater usage per
customer. Sales to commercial customers increased compared to
last year due primarily to colder winter weather and a greater
number of customers, offset partially by lower usage per
customer. Sales to industrial customers increased compared to
last year due to an increase in the number of customers and
higher usage per industrial customer.
Base rates are affected by two principal items: rate orders
by the PSC and recovery of eligible electric conservation program
costs through the energy conservation surcharge. Base rates
increased for the quarter ended March 31, 1996 compared to last
year due to recovery of a higher level of eligible electric
conservation program costs.
Under the energy conservation surcharge, if the PSC
determines that BGE is earning in excess of its authorized rate
of return, BGE will have to refund (by means of lowering future
surcharges) a portion of energy conservation surcharge revenues
to its customers. The portion subject to the refund is
compensation for foregone sales from conservation programs and
incentives for achieving conservation goals and will be refunded
to customers with interest beginning in the ensuing July when the
annual resetting of the conservation surcharge rates occurs.
-15-
<PAGE>
Changes in fuel rate revenues result from the operation of
the electric fuel rate formula. The fuel rate formula is designed
to recover the actual cost of fuel, net of revenues from
interchange sales and sales to other utilities. (See Notes 1 and
12 of the Form 10-K.) Changes in fuel rate revenues and
interchange and other sales normally do not affect earnings.
However, if the PSC were to disallow recovery of any part of
these costs, earnings would be reduced as discussed in Note 12 of
the Form 10-K.
Fuel rate revenues were higher for the quarter ended
March 31, 1996 as compared to the same period in 1995 as a result
of increased electric system sales volumes, offset partially by a
lower fuel rate.
The fuel rate was lower for the quarter ended March 31, 1996
as compared to the same period last year because of a less costly
twenty-four month generation mix due to greater generation at the
Calvert Cliffs Nuclear Power Plant and the Brandon Shores Power
Plant. BGE expects electric fuel rate revenues to remain
relatively constant through 1996.
Interchange and other sales represent sales of BGE's energy
to the Pennsylvania - New Jersey - Maryland Interconnection
(PJM), a regional power pool of eight member companies including
BGE, and sales to other non-PJM utilities. These sales occur
after BGE has satisfied the demand for its own system sales of
electricity, if BGE's available generation is the least costly
available. Interchange and other sales increased for the quarter
ended March 31, 1996 compared to last year because BGE had a less
costly generation mix. This less costly generation mix was due
primarily to greater generation from the Brandon Shores Power
Plant and the Calvert Cliffs Nuclear Power Plant.
Gas revenues changed for the quarter ended March 31, 1996
because of the following factors:
Quarter Ended
March 31
1996 vs. 1995
(In millions)
Sales volumes $ 9.4
Base rates 8.3
Gas cost adjustment revenues 44.7
Revenues from system sales 62.4
Off-system Sales 3.7
Other revenues 0.4
Total $ 66.5
-16-
<PAGE>
Below is a comparison of the changes in gas sales volumes:
Quarter Ended
March 31
1996 vs. 1995
Residential 21.8%
Commercial 7.7
Industrial (6.5)
Total 10.5
Gas sales to residential customers increased during the
first quarter of 1996 as compared to the same period last year
due to colder winter weather, an increase in the number of
customers, and increased usage per customer. Sales to commercial
customers increased compared to last year due to colder winter
weather and an increase in the number of customers, offset
partially by lower usage per customer. Sales to industrial
customers decreased compared to last year due to decreased usage
per customer (including Bethlehem Steel) as a result of a greater
number of interruptions caused by the colder winter weather in
1996.
Base rates increased during the quarter ended March 31, 1996
compared to the same period last year primarily as a result of
the PSC's November 1995 rate order, which increased annual base
rate revenues by $19.3 million, including $2.4 million to recover
higher depreciation expense.
Changes in gas cost adjustment revenues result primarily
from the operation of the purchased gas adjustment clause,
commodity charge adjustment clause, and the actual cost
adjustment clause which are designed to recover actual gas costs.
(See Note 1 of the Form 10-K.) Changes in gas cost adjustment
revenues normally do not affect earnings. Gas cost adjustment
revenues increased for the quarter ended March 31, 1996 because
of higher prices for purchased gas and higher sales volumes
subject to gas cost adjustment clauses. Delivery service sales
volumes are not subject to gas cost adjustment clauses because
these customers purchase their gas directly from third parties.
Off-system gas sales volumes represent direct sales to end
users of natural gas outside of BGE's service territory and are
not subject to gas cost adjustment clauses. BGE began sales of
off-system gas during the first quarter of 1996. Pursuant to a
sharing arrangement approved by the PSC, the gross margin earned
on these sales reduces gas cost adjustment charges to customers
and increases income available to common shareholders.
-17-
<PAGE>
BGE Utility Fuel and Energy Expenses
Electric fuel and purchased energy expenses were as follows:
Quarter Ended
March 31
1996 1995
(In millions)
Actual costs $147.5 $138.6
Net recovery of costs
under electric fuel rate
clause (see Note 1 of
the Form 10-K) 6.4 8.9
Total $153.9 $147.5
Total electric fuel and purchased energy expenses increased
during the quarter ended March 31, 1996 as a result of increased
actual costs, offset partially by the operation of the electric
fuel rate clause. Actual electric fuel and purchased energy costs
increased for the quarter ended March 31, 1996 as a result of
higher net output of electricity generated and higher purchased
energy costs.
Purchased gas expenses were as follows:
Quarter Ended
March 31
1996 1995
(In millions)
Actual costs $126.9 $ 87.3
Net (deferral) recovery of costs
under purchased gas adjustment
clause (see Note 1 of the
Form 10-K) 2.1 (5.5)
Total $129.0 $ 81.8
Total purchased gas expenses increased for the quarter ended
March 31, 1996 compared to last year due to an increase in actual
gas costs and the operation of the purchased gas adjustment
clause. The increase in actual gas costs reflects substantially
higher gas prices and sales volumes during the first quarter of
1996 as compared to last year.
Purchased gas costs exclude gas purchased by delivery
service customers, including Bethlehem Steel, who obtain gas
directly from third parties.
-18-
<PAGE>
Other Operating Expenses
Operations and Maintenance expenses were essentially
unchanged during the quarter ended March 31, 1996 compared to
last year.
Depreciation and amortization expense increased $8.7 million
during the quarter ended March 31, 1996 compared to the same
period last year because of a higher level of depreciable plant
in service and higher amortization of energy conservation
surcharge costs.
Taxes other than income taxes increased $3.4 million during
the quarter ended March 31, 1996 compared to last year due to an
increase in property taxes resulting from plant additions during
1995 and higher gross receipts taxes in 1996 due to higher
revenues. In addition, payroll taxes increased during 1996 due to
increased incentive-based payouts and a 3% general wage increase
granted March 1, 1996.
Other Income and Expenses
The Allowance for Funds Used During Construction
(AFC)decreased $5.2 million for the quarter ended March 31, 1996
due primarily to a significant reduction in construction work in
progress and a lower gas AFC rate. The reduction in construction
work in progress resulted from both a lower level of new
construction activity and the placement of several projects in
service during the past year.
Interest charges decreased $2.3 million for the quarter
ended March 31, 1996 due primarily to the maturity of long-term
debt as well as lower interest rates as compared to last year,
offset partially by a higher level of debt outstanding.
Income tax expense increased $20.3 million for the quarter
ended March 31, 1996 due primarily to higher taxable income from
utility operations and diversified businesses.
-19-
<PAGE>
Diversified Businesses Earnings
Earnings per share from diversified businesses were:
Quarter Ended
March 31
1996 1995
Constellation Holdings, Inc.
Power generation systems $.04 $.02
Financial investments .01 .02
Real estate development and
senior living facilities (.01) (.01)
Total Constellation Holdings, Inc. .04 .03
Other Subsidiaries .00 .00
Total diversified businesses $.04 $.03
The Constellation Companies' power generation systems
business includes the development, ownership, management, and
operation of wholesale power generating projects in which the
Constellation Companies hold ownership interests, as well as the
provision of services to power generation projects under
operation and maintenance contracts. Power generation systems
earnings increased for the quarter ended March 31, 1996 due
primarily to higher equity earnings from the Constellation
Companies' energy projects. See the discussion of the gain to be
reported in earnings for the quarter ending June 30, 1996 under
the heading Subsequent Event on page 12 of this report.
The Constellation Companies' investment in wholesale power
generating projects includes $198 million representing ownership
interests in 16 projects that sell electricity in California
under Interim Standard Offer No. 4 (SO4) power purchase
agreements. Under these agreements, the projects supply
electricity to purchasing utilities at a fixed rate for the first
ten years of the agreements and thereafter at fixed capacity
payments plus variable energy rates based on the utilities'
avoided cost for the remaining term of the agreements. Avoided
cost generally represents a utility's next lowest cost generation
to service the demands on its system. These power generation
projects are scheduled to convert to supplying electricity at
avoided cost rates in various years beginning in late 1996
through the end of 2000. As a result of declines in purchasing
utilities' avoided costs subsequent to the inception of these
agreements, revenues at these projects based on current avoided
cost levels would be substantially lower than revenues presently
being realized under the fixed price terms of the agreements. At
current avoided cost levels, the Constellation Companies could
experience reduced earnings or incur losses associated with these
projects, which could be significant. While nine projects
transition from fixed to variable energy rates in the 1996
through 1998 timeframe, revenues from the other projects having
SO4 contracts are expected to continue to increase during this
-20-
<PAGE>
period tending to offset revenue declines on the nine projects.
Six of the seven largest revenue producing projects will not make
the transition to variable energy rates until the 1999-2000
timeframe such that any material reductions in revenues would not
be anticipated until the years 2000 and 2001. The Constellation
Companies are investigating and pursuing alternatives for certain
of these power generation projects including, but not limited to,
repowering the projects to reduce operating costs, changing
fuels, renegotiating the power purchase agreements, restructuring
financings, and selling its ownership interests in the projects.
Two of these wholesale power generating projects, in which the
Constellation Companies' investment totals $33 million, have
executed agreements with Pacific Gas & Electric (PG&E) providing
for the curtailment of output through the end of the fixed price
period in return for payments from PG&E. The payments from PG&E
during the curtailment period will be sufficient to fully
amortize the existing project finance debt. However, following
the curtailment period, the projects remain contractually
obligated to commence production of electricity at the avoided
cost rates, which could result in reduced earnings or losses for
the reasons described above. The Company cannot predict the
impact that these matters regarding any of the 16 projects may
have on the Constellation Companies or the Company, but the
impact could be material.
Earnings from the Constellation Companies' portfolio of
financial investments include capital gains and losses,
dividends, income from financial limited partnerships, and income
from financial guaranty insurance companies. Financial
investment earnings were lower for the quarter ended
March 31, 1996 because the quarter ended March 31, 1995 included
capital gains realized from a financial limited partnership.
The Constellation Companies' real estate development
business includes land under development; office buildings;
retail projects; commercial projects; an entertainment, dining
and retail complex in Orlando, Florida; a mixed-use planned-unit-
development; and senior living facilities. The majority of these
projects are in the Baltimore-Washington corridor. They have been
affected adversely by the oversupply of and limited demand for
land and office space due to modest economic growth and corporate
downsizings. Earnings from real estate development and senior
living facilities for the quarter ended March 31, 1996 are
essentially unchanged from the prior year.
The Constellation Companies' real estate portfolio has
experienced continuing carrying costs and depreciation.
Additionally, the Constellation Companies have been expensing
rather than capitalizing interest on certain undeveloped land for
which substantially all development activities have been
suspended. These factors have affected earnings negatively and
are expected to continue to do so until the levels of undeveloped
land are reduced. Cash flow from real estate operations has been
insufficient to cover the debt service requirements of certain of
-21-
<PAGE>
these projects. Resulting cash shortfalls have been satisfied
through cash infusions from Constellation Holdings, Inc., which
obtained the funds through a combination of cash flow generated
by other Constellation Companies and its corporate borrowings.
To the extent the real estate market continues to improve,
earnings from real estate activities are expected to improve
also.
The Constellation Companies' continued investment in real
estate projects is a function of market demand, interest rates,
credit availability, and the strength of the economy in general.
The Constellation Companies' Management believes that although
the real estate market has improved, until the economy reflects
sustained growth and the excess inventory in the market in the
Baltimore-Washington corridor goes down, real estate values will
not improve significantly. If the Constellation Companies were to
sell their real estate projects in the current depressed market,
losses would occur in amounts difficult to determine. Depending
upon market conditions, future sales could also result in losses.
In addition, were the Constellation Companies to change their
intent about any project from an intent to hold to an intent to
sell, applicable accounting rules would require a write-down of
the project to market value at the time of such change in intent
if market value is below book value.
The earnings of other subsidiaries, which include HP&S,
EP&S, and BNG, Inc., were essentially unchanged during the
quarter ended March 31, 1996 compared to last year.
Environmental Matters
The Company is subject to increasingly stringent federal,
state, and local laws and regulations relating to improving or
maintaining the quality of the environment. These laws and
regulations require the Company to remove or remedy the effect on
the environment of the disposal or release of specified
substances at ongoing and former operating sites, including
Environmental Protection Agency Superfund sites. Details
regarding these matters, including financial information, are
presented in the Environmental Matters section on pages 7 and 8
of this Report.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity
For the twelve months ended March 31, 1996, the Company's
ratio of earnings to fixed charges and ratio of earnings to
combined fixed charges and preferred and preference dividend
requirements were 3.47 and 2.72, respectively.
-22-
<PAGE>
Capital Requirements
The Company's capital requirements reflect the capital-
intensive nature of the utility business. Actual capital
requirements for the three months ended March 31, 1996, along
with estimated annual amounts for the years 1996 through 1998,
are reflected below.
Three Months Ended
March 31 Calendar Year Estimate
1996 1996 1997 1998
(In millions)
Utility Business:
Construction expenditures
(excluding AFC)
Electric $ 42 $ 231 $205 $212
Gas 14 68 73 67
Common 11 41 47 46
Total construction expenditures 67 340 325 325
AFC 3 11 10 10
Nuclear fuel (uranium purchases
and processing charges) 9 45 45 44
Deferred energy conservation
expenditures 5 34 25 27
Retirement of long-term debt
and redemption of preferred
and preference stock 11 160 164 125
Total utility business 95 590 569 531
Diversified Businesses:
Retirement of long-term debt 7 55 131 157
Investment requirements 20 108 71 82
Total diversified businesses 27 163 202 239
Total $122 $ 753 $771 $770
BGE Utility Capital Requirements
BGE's construction program is subject to continuous review
and modification, and actual expenditures may vary from the
estimates above. Electric construction expenditures include the
installation of the second of two 5,000 kilowatt diesel
generators at Calvert Cliffs Nuclear Power Plant scheduled to be
placed in service in 1996 and improvements in BGE's existing
generating plants and its transmission and distribution
facilities. Future electric construction expenditures do not
include additional generating units.
During the twelve months ended March 31, 1996, the internal
generation of cash from utility operations provided 104% of the
funds required for BGE's capital requirements exclusive of
retirements and redemptions of debt and preference stock. During
the three-year period 1996 through 1998, the Company expects to
provide through utility operations 115% of the funds required for
BGE's capital requirements, exclusive of retirements and
redemptions.
-23-
<PAGE>
Utility capital requirements not met through the internal
generation of cash are met through the issuance of debt and
equity securities. The amount and timing of issuances and
redemptions depends upon market conditions and BGE's actual
capital requirements. From January 1, 1996 through the date of
this Report, there were no issuances of debt or equity
securities. During the same period, BGE redeemed, or announced
the redemption of, $37 million principal amount of debt and $61
million par value of preferred and preference stock outstanding.
All outstanding preferred stock was called for redemption as
described on page 6 under the heading "BGE Financing Activity".
At the date of this Report, BGE's securities ratings are as
follows:
Standard Moody's
& Poors Investors Duff & Phelps
Rating Group Service Credit Rating Co.
Senior Secured Debt A+ A1 AA-
(First Mortgage Bonds)
Unsecured Debt A A2 A+
Preference Stock A "a2" A
The Constellation Companies' capital requirements are
discussed below in the section titled "Diversified Businesses
Capital Requirements - Debt and Liquidity." The Constellation
Companies are exploring expansion of their energy, real estate
service, and senior living facility businesses. Expansion may be
achieved in a variety of ways, including without limitation
increased investment activity and acquisitions. The Constellation
Companies plan to meet their capital requirements with a
combination of debt and internal generation of cash from their
operations. Additionally, from time to time, BGE may make loans
to Constellation Holdings, Inc., or contribute equity to enhance
the capital structure of Constellation Holdings, Inc.
Historically, Constellation's energy projects have been in
the United States. Over the last year, Constellation has pursued
energy projects in Latin America. As of March 31, 1996, one of
the Constellation Companies had invested about $14.6 million and
committed another $8.4 million in power projects in Latin
America. Constellation's future energy business expansion may
include domestic and international projects.
Diversified Businesses Capital Requirements
Debt and Liquidity
The Constellation Companies intend to meet capital
requirements by refinancing debt as it comes due and through
internally generated cash. These internal sources include cash
that may be generated from operations, sale of assets, and cash
-24-
<PAGE>
generated by tax benefits earned by the Constellation Companies.
In the event the Constellation Companies can obtain reasonable
value for real estate properties, additional cash may become
available through the sale of projects (for additional
information see the discussion of the real estate business and
market on pages 21 and 22 under the heading "Diversified
Businesses Earnings"). The ability of the Constellation
Companies to sell or liquidate assets described above will depend
on market conditions, and no assurances can be given that such
sales or liquidations can be made. Also, to provide additional
liquidity to meet interim financial needs, CHI has a $75 million
revolving credit agreement of which $5 million was outstanding at
the date of this Report.
Investment Requirements
The investment requirements of the Constellation Companies
include its portion of equity funding to committed projects under
development, as well as net loans made to project partnerships.
Investment requirements for the years 1996 through 1998 reflect
the Constellation Companies' estimate of funding for ongoing and
anticipated projects and are subject to continuous review and
modification. Actual investment requirements may vary
significantly from the estimates on page 23 because of the type
and number of projects selected for development, the impact of
market conditions on those projects, the ability to obtain
financing, and the availability of internally generated cash.
The Constellation Companies have met their investment
requirements in the past through the internal generation of cash
and through borrowings from institutional lenders.
-25-
<PAGE>
PART II. OTHER INFORMATION
ITEM 1. Legal Proceedings
Asbestos
Since 1993, BGE has been served in several actions
concerning asbestos. The actions are collectively titled In re
Baltimore City Personal Injuries Asbestos Cases in the Circuit
Court for Baltimore City, Maryland. The actions are based upon
the theory of "premises liability," alleging that BGE knew of and
exposed individuals to an asbestos hazard. The actions relate to
two types of claims.
The first type, direct claims by individuals exposed to
asbestos, were described in a Report on Form 8-K filed August 20,
1993. BGE and approximately 70 other defendants are involved.
Approximately 516 non-employee plaintiffs each claim $6 million
in damages ($2 million compensatory and $4 million punitive).
BGE does not know the specific facts necessary for BGE to assess
its potential liability for these type claims, such as the
identity of the BGE facilities at which the plaintiffs allegedly
worked as contractors, the names of the plaintiffs' employers,
and the date on which the exposure allegedly occurred.
The second type are claims by one manufacturer - Pittsburgh
Corning Corp. - against BGE and approximately eight others, as
third-party defendants. These claims relate to approximately
1,500 individual plaintiffs. BGE does not know the specific
facts necessary for BGE to assess its potential liability for
these type claims, such as the identity of BGE facilities
containing asbestos manufactured by the two manufacturers, the
relationship (if any) of each of the individual plaintiffs to
BGE, the settlement amounts for any individual plaintiffs who are
shown to have had a relationship to BGE, and the dates on
which/places at which the exposure allegedly occurred.
Until the relevant facts for both type claims are
determined, BGE is unable to estimate what its liability, if any,
might be. Although insurance and hold harmless agreements from
contractors who employed the plaintiffs may cover a portion of
any ultimate awards in the actions, BGE's potential liability
could be material.
Environmental Matters
The Company's potential environmental liabilities and
pending environmental actions are listed in Item 1. Business -
Environmental Matters of the Form 10-K.
-26-
<PAGE>
PART II. OTHER INFORMATION (Continued)
ITEM 4. Submission of Matters to a Vote of Security Holders
On March 29, 1996, BGE held a special meeting of
shareholders. At that meeting, the following matters were voted
upon:
1. The proposed merger of BGE with Potomac Electric Power
Company was approved. Common and preference shareholders
were entitled to vote. With respect to holders of BGE
common stock, the number of affirmative votes cast for the
proposed merger was 110,871,295, the number of negative
votes cast for the proposed merger was 2,454,946, and the
number of abstentions was 1,440,297. With respect to
holders of BGE preference stock, the number of affirmative
votes cast for the proposed merger was 3,834,731, the number
of negative votes cast for the proposed merger was 61,384,
and the number of abstentions was 5,677. With respect to
holders of the aggregate of both classes of stock, the
number of affirmative votes cast for the proposed merger was
114,706,026, the number of negative votes cast for the
proposed merger was 2,516,330, and the number of abstentions
was 1,445,974.
2. The proposal to implement a Long-Term Incentive Plan for the
new company was approved. Only common shareholders were
entitled to vote. With respect to holders of common stock,
the number of affirmative votes cast for the proposal was
95,237,374, the number of negative votes cast for the
proposal was 14,676,425, and the number of abstentions was
4,857,127.
-27-
<PAGE>
PART II. OTHER INFORMATION (Continued)
ITEM 6. Exhibits and Reports on Form 8-K
(a) Exhibit No. 2* Registration
Statement on Form S-4 of
Constellation Energy Corporation,
as amended, which became effective
February 9, 1996, Registration No.
33-64799.
Exhibit No. 12 Computation of
Ratio of Earnings to Fixed Charges
and Computation of Ratio of
Earnings to Combined Fixed Charges
and Preferred and Preference
Dividend Requirements.
Exhibit No. 27 Financial Data
Schedule.
*Incorporated by Reference.
(b) Reports on Form 8-K for the quarter ended March 31,
1996:
Date Filed Items Reported
February 6, 1996 Item 5. Other Events
Item 7. Financial Statements
and Exhibits
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act
of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned thereunto duly authorized.
BALTIMORE GAS AND ELECTRIC COMPANY
(Registrant)
Date May 14, 1996 /s/ C.W. Shivery
C. W. Shivery, Vice President
on behalf of the Registrant and
as Principal Financial Officer
-28-
<PAGE>
EXHIBIT INDEX
Exhibit
Number
2* Registration Statement on
Form S-4 of Constellation Energy
Corporation, as amended, which became
effective February 9, 1996,
Registration No. 33-64799.
12 Computation of Ratio of
Earnings to Fixed Charges and
Computation of Ratio of Earnings to
Combined Fixed Charges and Preferred and
Preference Dividend Requirements.
27 Financial Data Schedule.
*Incorporated by Reference.
-29-
<PAGE>
EXHIBIT 12
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND
COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND
PREFERRED AND PREFERENCE DIVIDEND REQUIREMENTS
<TABLE>
<CAPTION>
12 Months Ended
March December December December December December
1996 1995 1994 1993 1992 1991
(In Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
Net Income $ 367,934 $ 338,007 $ 323,617 $ 309,866 $ 264,347 $ 233,681
Taxes on Income 192,761 172,388 156,702 140,833 105,994 88,041
Adjusted Net Income $ 560,695 $ 510,395 $ 480,319 $ 450,699 $ 370,341 $ 321,722
Fixed Charges:
Interest and Amortization of
Debt Discount and Expense and
Premium on all Indebtedness $ 204,732 $ 206,666 $ 204,206 $ 199,415 $ 200,848 $ 213,616
Capitalized Interest 14,717 15,050 12,427 16,167 13,800 20,953
Interest Factor in Rentals 1,931 2,099 2,010 2,144 2,033 1,801
Total Fixed Charges $ 221,380 $ 223,815 $ 218,643 $ 217,726 $ 216,681 $ 236,370
Preferred and Preference
Dividend Requirements: (1)
Preferred and
Preference Dividends $ 40,289 $ 40,578 $ 39,922 $ 41,839 $ 42,247 $ 42,746
Income Tax Required 20,843 20,434 19,074 18,763 16,729 15,916
Total Preferred and Preference
Dividend Requirements $ 61,132 $ 61,012 $ 58,996 $ 60,602 $ 58,976 $ 58,662
Total Fixed Charges and
Preferred and Preference
Dividend Requirements $ 282,512 $ 284,827 $ 277,639 $ 278,328 $ 275,657 $ 295,032
Earnings (2) $ 767,358 $ 719,160 $ 686,535 $ 652,258 $ 573,222 $ 537,139
Ratio of Earnings to Fixed Charges 3.47 3.21 3.14 3.00 2.65 2.27
Ratio of Earnings to Combined Fixed
Charges and Preferred and Preference
Dividend Requirements 2.72 2.52 2.47 2.34 2.08 1.82
</TABLE>
(1)Preferred and preference dividend requirements consist of an amount equal to
the pre-tax earnings that would be required to meet dividend requirements on
preferred stock and preference stock.
(2)Earnings are deemed to consist of net income that includes earnings of BGE's
consolidated subsidiaries, equity in the net income of BGE's unconsolidated
subsidiary, income taxes (including deferred income taxes and investment tax
credit adjustments), and fixed charges other than capitalized interest.
<TABLE> <S> <C>
<ARTICLE> UT
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> MAR-31-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 5,493,154
<OTHER-PROPERTY-AND-INVEST> 1,343,324
<TOTAL-CURRENT-ASSETS> 869,714
<TOTAL-DEFERRED-CHARGES> 676,306
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 8,382,498
<COMMON> 1,425,645
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 1,415,000
<TOTAL-COMMON-STOCKHOLDERS-EQ> 2,846,463
242,000
210,000
<LONG-TERM-DEBT-NET> 2,613,525
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 284,845
<LONG-TERM-DEBT-CURRENT-PORT> 109,897
85,185
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,990,583
<TOT-CAPITALIZATION-AND-LIAB> 8,382,498
<GROSS-OPERATING-REVENUE> 861,330
<INCOME-TAX-EXPENSE> 52,972
<OTHER-OPERATING-EXPENSES> 660,015
<TOTAL-OPERATING-EXPENSES> 712,987
<OPERATING-INCOME-LOSS> 148,343
<OTHER-INCOME-NET> 941
<INCOME-BEFORE-INTEREST-EXPEN> 149,284
<TOTAL-INTEREST-EXPENSE> 48,503
<NET-INCOME> 100,781
9,663
<EARNINGS-AVAILABLE-FOR-COMM> 91,118
<COMMON-STOCK-DIVIDENDS> 57,536
<TOTAL-INTEREST-ON-BONDS> 52,718
<CASH-FLOW-OPERATIONS> 256,441
<EPS-PRIMARY> .62
<EPS-DILUTED> .62
</TABLE>
