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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES AND EXCHANGE ACT OF 1934
For the fiscal year ended 1-1910
December 31, 1993 Commission file number
------------------------
BALTIMORE GAS AND ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
MARYLAND 52-0280210
(State of incorporation) (I.R.S. Employer Identification No.)
GAS AND ELECTRIC BUILDING, CHARLES
CENTER, 21201
BALTIMORE, MARYLAND (Zip Code)
(Address of principal executive offices)
410-783-5920
(Registrant's telephone number, including area code)
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
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New York Stock Exchange, Inc.
Common Stock -- Without Par Value Chicago Stock Exchange, Inc.
Pacific Stock Exchange, Inc.
Preferred Stock, Series B 4 1/2%, Cumulative,
$100 Par Value New York Stock Exchange, Inc.
Preferred Stock, Cumulative, $100 Par Value:
Series C 4%
Series D 5.40%
Preference Stock, Cumulative, $100 Par Value: Philadelphia Stock Exchange, Inc.
7.78%, 1973 Series
7.50%, 1986 Series
6.75%, 1987 Series
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
Not Applicable
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 __.
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K (Section 229.405 of this chapter) is not contained herein,
and will not be contained, to the best of registrant's knowledge, in definitive
proxy or information statements incorporated by reference in Part III of this
Form 10-K or any amendment to this Form 10-K. /X/
Aggregate market value of Common Stock, without par value, held by
non-affiliates as of February 28, 1994 was approximately $3,395,220,704 based
upon New York Stock Exchange composite transaction closing price.
COMMON STOCK, WITHOUT PAR VALUE -- 146,446,343 SHARES OUTSTANDING ON FEBRUARY
28, 1994.
DOCUMENTS INCORPORATED BY REFERENCE
PART OF FORM 10-K DOCUMENT INCORPORATED BY REFERENCE
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III Definitive Proxy Statement for the Annual Meeting of Shareholders of
Baltimore Gas and Electric Company to be held on April 20, 1994
(Proxy Statement).
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TABLE OF CONTENTS
PAGE
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PART I
Item 1 -- Business
General...................................... 1
Capital Requirements......................... 2
Rate Matters................................. 3
Nuclear Operations........................... 4
Load Management, Energy, and Capacity
Purchases.................................... 5
Fuel for Electric Generation................. 6
Gas Operations............................... 7
Environmental Matters........................ 8
Electric Operating Statistics................ 11
Gas Operating Statistics..................... 12
Franchises................................... 13
Diversified Businesses....................... 13
Employees.................................... 15
Item 2 -- Properties................................... 16
Item 3 -- Legal Proceedings............................ 16
Submission of Matters to a Vote of Security
Item 4 -- Holders...................................... 17
Executive Officers of the Registrant
(Instruction 3 to Item 401(b) of Regulation
Item 10 -- S-K)......................................... 18
PART II
Market for Registrant's Common Equity and
Item 5 -- Related Stockholder Matters.................. 19
Item 6 -- Selected Financial Data...................... 20
Management's Discussion and Analysis of
Financial Condition and Results of
Item 7 -- Operations................................... 21
Financial Statements and Supplementary
Item 8 -- Data......................................... 29
Changes in and Disagreements with Accountants
Item 9 -- on Accounting and Financial Disclosure....... 56
PART III
Directors and Executive Officers of the
Item 10 -- Registrant................................... 56
Item 11 -- Executive Compensation....................... 56
Security Ownership of Certain Beneficial
Item 12 -- Owners and Management........................ 56
Certain Relationships and Related
Item 13 -- Transactions................................. 56
PART IV
Exhibits, Financial Statement Schedules and
Item 14 -- Reports on Form 8-K.......................... 56
Signatures........................................................... 66
PART I
ITEM 1. BUSINESS
Baltimore Gas and Electric Company and Subsidiaries are herein collectively
referred to as the Company. The Company is engaged in utility operations and
related businesses through Baltimore Gas and Electric Company (BGE). The Company
is engaged in diversified businesses primarily through BGE's wholly owned
subsidiary, Constellation Holdings, Inc. and its subsidiaries (collectively, the
Constellation Companies).
BGE was incorporated under the laws of the State of Maryland on June 20,
1906, and is primarily engaged in the business of producing, purchasing, and
selling electricity, and purchasing, transporting, and selling natural gas
within the State of Maryland. BGE is qualified to do business in the District of
Columbia where its federal affairs office is located. BGE is qualified to do
business in the Commonwealth of Pennsylvania where it is participating in the
ownership and operation of two electric generating plants as described under
ITEM 2. PROPERTIES -- ELECTRIC. BGE also owns two-thirds of the outstanding
capital stock, including one-half of the voting securities, of Safe Harbor Water
Power Corporation (Safe Harbor), a hydroelectric producer on the Susquehanna
River at Safe Harbor, Pennsylvania. (SEE ITEM 2. PROPERTIES -- ELECTRIC.) BNG,
Inc. is a wholly owned subsidiary of BGE which invests in natural gas reserves.
Other business of BGE includes the sale and service of gas and electric
appliances; BGE intends to emphasize this business in the future and will form a
subsidiary during 1994 to direct this effort. For financial information by
segment of operation see NOTE 2 TO CONSOLIDATED FINANCIAL STATEMENTS.
BGE furnishes electric and gas retail services in the City of Baltimore and
in all or part of nine counties in Central Maryland. The electric service
territory includes an area of approximately 2,300 square miles with an estimated
population of 2,602,000. The gas service territory includes an area of
approximately 625 square miles with an estimated population of 1,963,000. There
are no municipal or cooperative bulk power markets within BGE's service
territory.
Electric utilities presently face competition in the construction of
generating units to meet future load growth and in the sale of electricity in
the bulk power markets. On March 25, 1993, the Public Service Commission of
Maryland (PSC) issued BGE a Certificate of Public Convenience and Necessity
authorizing BGE to construct a 140-megawatt combustion turbine at its Perryman
site. The PSC further required BGE to implement a competitive bidding program
for the selection of a third-party power supplier for the increment of electric
generating capacity needed after the Perryman combustion turbine. BGE announced
March 11, 1994 that PECO Energy won the competitive bidding with a proposal to
supply 140 megawatts for 25 years beginning June 1, 1997. Electric and gas
utilities also face the future prospect of competition for electric and gas
sales to retail customers. It is not possible to predict the ultimate effect
competition will have on BGE's earnings in future years.
As discussed throughout this report, the two units at BGE's Calvert Cliffs
Nuclear Power Plant are its principal generating facilities and have the lowest
fuel cost in BGE's system. An extended shutdown of either of these Units could
have a substantial adverse effect on the Company's business and financial
condition. Furthermore, BGE does not consider it possible to obtain insurance
adequate to cover all the costs that could result from a major incident or an
extended outage at either of the Calvert Cliffs Units. (SEE NUCLEAR OPERATIONS
AND NOTE 13 TO CONSOLIDATED FINANCIAL STATEMENTS for information regarding prior
outages at the Plant.)
The Constellation Companies' businesses are discussed under DIVERSIFIED
BUSINESSES on page 13 and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS (MD&A).
The percentages of Operating Revenues and Operating Income attributable to
electric, gas, and diversified operations are set forth below:
OPERATING REVENUES OPERATING INCOME*
------------------------- -------------------------
ELECTRIC GAS DIVERSIFIED ELECTRIC GAS DIVERSIFIED
------- -- ---------- ------- -- ----------
1993..................... 79% 16% 5% 83% 7 % 10%
1992..................... 79 16 5 81 9 10
1991..................... 81 15 4 87 8 5
1990..................... 79 17 4 77 10 13
1989..................... 76 20 4 78 11 11
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*net of income taxes
BGE currently derives approximately 23% of electric revenues and 42% of gas
revenues from customers located in the City of Baltimore and 77% and 58%,
respectively, from outside the City of Baltimore. No single customer's electric
revenues exceed 4% of total electric revenues and no single customer's gas
revenues exceed 4% of total gas revenues.
1
The disparity between the percentage of gas operating revenues in relation
to the percentage of gas operating income as compared to the same percentages
for electric operations is due to BGE's level of investment and its fuel costs
in each of these segments. BGE's operating revenue amounts represent recovery of
all fuel and operating expenses plus a return on its investment in the business.
BGE's net investment for ratemaking purposes in the electric business is $4.5
billion while the comparable investment in its gas business is less than $450
million. Thus, operating revenues include a much greater return component for
electric operations than gas operations. Also, as can be seen by referring to
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA, CONSOLIDATED STATEMENTS OF
INCOME on page 30, gas purchased for resale as a percentage of gas revenues
(56%) is greater than electric fuel and purchased energy as a percentage of
electric revenues (25%). It should be noted that both purchased gas costs and
electric fuel costs are passed through to the customer with no mark-up for
profit. The combined effects of these factors yield the observed relationship
between operating revenues and income for electric and gas operations.
CAPITAL REQUIREMENTS
The Company's actual capital requirements for 1991 through 1993, along with
estimated amounts for 1994 through 1996, are set forth below:
1991 1992 1993 1994 1995 1996
--------- --------- --------- --------- --------- ---------
(IN MILLIONS)
Utility Business
Construction expenditures (excluding AFC)
Electric..................................................... $ 328 $ 292 $ 360 $ 345 $ 319 $ 300
Gas.......................................................... 43 36 51 54 60 56
Common....................................................... 48 39 44 51 46 44
--------- --------- --------- --------- --------- ---------
Total construction expenditures.............................. 419 367 455 450 425 400
AFC (a)........................................................ 37 22 23 34 35 25
Deferred nuclear expenditures (b).............................. 23 16 14 12 -- --
Deferred energy conservation
expenditures (b).............................................. 3 20 33 48 45 40
Nuclear fuel (uranium purchases and processing charges)........ 2 40 47 42 46 51
Retirement of long-term debt and redemption of preference stock
(c)........................................................... 339 486 907 36 281 98
--------- --------- --------- --------- --------- ---------
Total utility business......................................... 823 951 1,479 622 832 614
--------- --------- --------- --------- --------- ---------
Diversified Businesses........................................... 276 198 300 72 141 97
--------- --------- --------- --------- --------- ---------
Total........................................................ $ 1,099 $ 1,149 $ 1,779 $ 694 $ 973 $ 711
--------- --------- --------- --------- --------- ---------
--------- --------- --------- --------- --------- ---------
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(a) Allowance for Funds Used During Construction (AFC) is accrued for all
construction projects with a construction period of more than one month
beginning January 1, 1992. (SEE NOTE 1 TO CONSOLIDATED FINANCIAL STATEMENTS
for a discussion of AFC.)
(b) See NOTE 5 TO CONSOLIDATED FINANCIAL STATEMENTS for a discussion of
deferred nuclear expenditures and deferred energy conservation
expenditures.
(c) The 1994 amount does not reflect the early redemption of the following
bonds: the 7 1/4% Series due April 15, 2001 First Refunding Mortgage Bonds
which were redeemed effective March 11, 1994, at 101.88% of principal, and
the 7% Series due 1998 First Refunding Mortgage Sinking Fund Bonds which
will be redeemed effective April 18, 1994, at 101.11% of principal.
BGE's actual capital requirements may vary from the estimates set forth
above because of a number of factors such as inflation, economic conditions,
regulation, legislation, load growth, environmental protection standards, and
the cost and availability of capital. The Constellation Companies' capital
requirements for diversified businesses may vary from the estimates set forth
above due to a number of factors including market and economic conditions and
are discussed in detail under MD&A -- DIVERSIFIED BUSINESSES CAPITAL
REQUIREMENTS on page 28.
BGE's estimated construction, nuclear fuel, deferred nuclear expenditures,
and deferred energy conservation expenditures are expected to amount to
approximately $2.1 billion, $250 million, $12 million, and $200 million,
respectively, for the five-year period 1994-1998. Electric construction
expenditures reflect the installation of two 5,000 kilowatt diesel generators at
Calvert Cliffs Nuclear Power Plant, scheduled to be placed in service in 1995;
the construction of a 140-megawatt combustion turbine at Perryman, scheduled to
be placed in service in
2
1995, which the PSC authorized in an order dated March 25, 1993; and
improvements in BGE's existing generating plants and its transmission and
distribution facilities. Future electric construction expenditures do not
include additional generating units in light of the competitive bidding process
established by the PSC as discussed on page 1. The Company estimates currently
that expenditures for compliance with the sulfur dioxide provisions of the Clean
Air Act of 1990 will total approximately $55 million through 1995.
During the period January 1, 1989 through December 31, 1993, BGE expended
$2,299 million for gross additions to utility plant or approximately 32% of its
total utility plant (exclusive of nuclear fuel) at December 31, 1993. During the
same period, a total of $272 million of utility plant was retired. Nuclear fuel
expenditures include uranium purchases and processing charges.
BGE presently estimates that approximately $750 million will be required for
retirements and redemptions of long-term debt (including sinking fund payments)
and BGE preference stock during the five-year period 1994-1998.
For further information with respect to capital requirements and for a
discussion of internal generation of cash, see ITEM 7. MD&A -- LIQUIDITY AND
CAPITAL RESOURCES.
RATE MATTERS
ELECTRIC AND GAS BASE RATE DECISION
On April 23, 1993, the PSC issued an Order (the 1993 Rate Order) authorizing
BGE annualized electric and gas base rate increases of $84.9 million and $1.6
million, respectively. The increases are equivalent to 4.5% and 0.4% of total
electric and gas revenues, respectively. In granting the increases, the PSC
provided a return on BGE's higher level of electric and gas rate base and
recognized increases in electric operating expenses associated primarily with
maintaining and improving system reliability. This was partially offset by a
reduction in the authorized rate of return to 9.40% from the 9.94% rate of
return previously authorized.
The 1993 Rate Order also provided for recovery of one-half of the annual
level of the increase in postretirement benefit costs under Statement of
Financial Accounting Standards No. 106. The PSC directed BGE to defer the
remainder of the annual increase in these costs for inclusion in BGE's next base
rate proceeding and provided that costs deferred during the intervening period
will be amortized over a fifteen-year period beginning in 1998.
ENERGY CONSERVATION SURCHARGE
The PSC approved a base rate surcharge effective July 1, 1992 which provides
for the recovery of deferred energy conservation expenditures, a return thereon,
lost revenues, and incentives for achievement of predetermined goals for certain
conservation programs subject to an earnings test. The compensation for foregone
sales due to conservation programs and the incentives for achieving conservation
goals must be refunded to customers if BGE is earning in excess of its
authorized rate of return, as determined by the PSC. (See discussion in ITEM 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS.) The surcharge is reset on July 1 of each
year.
ELECTRIC FUEL RATE PROCEEDINGS
By statute, electric fuel costs are recoverable if the 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
appelate court have 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. The PSC has
established a Generating Unit Performance Program (GUPP) to measure annual
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. As a
result, actual generating performance, after adjustment for planned outages, is
compared to the system-wide target and, if met, should signify compliance 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. Failure to meet these targets requires BGE
to demonstrate that the outages causing the failure are not the result of
mismanagement. 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 a disallowance of replacement energy costs. BGE is
involved in fuel rate proceedings annually where issues concerning individual
plant outages can be raised. Recovery of a portion of replacement energy costs
has been denied in past proceedings and BGE cannot estimate the amount that
could be denied in future fuel rate proceedings, but such amounts could be
material. (See NUCLEAR OPERATIONS.)
BGE is required to submit to the PSC the actual generating performance data
for each calendar year 45 days after year end. The PSC reviews BGE's performance
for each calendar year in the first fuel rate proceeding initiated following the
submission of the actual generating performance data for that year. BGE must
initiate fuel
3
rate proceedings in any month following a month during which the calculated fuel
rate decreased by more than 5% and may initiate fuel rate proceedings in any
month following a month during which the calculated fuel rate increased by more
than 5%.
NUCLEAR OPERATIONS
Discussed below are certain events relating to the operations of the Calvert
Cliffs Nuclear Power Plant (the Plant) during the period 1987 to the present
including issues involving the possible disallowance of replacement energy costs
incurred during unplanned outages at the Plant. All outstanding issues will be
resolved in fuel rate proceedings before the PSC which are conducted in
accordance with the procedures outlined above under RATE MATTERS -- ELECTRIC
FUEL RATE PROCEEDINGS.
OPERATIONS IN 1987
The Plant generated 10,069,576 megawatt hours (MWH) in 1987 which resulted
in a capacity factor of 70%. In October 1988, BGE filed a fuel rate application
for a change in its electric fuel rate under GUPP, which covered BGE's operating
performance in 1987. This was the first proceeding filed under this program and
BGE's filing demonstrated that it met the system-wide and individual plant
performance targets for 1987, including the performance target for the Plant.
BGE believes, therefore, it is entitled to recover all fuel costs incurred in
1987 without any disallowances. However, People's Counsel alleges that a number
of the outages at the Plant (including the 66-day outage described below) were
due to management imprudence and requests that the PSC disallow recovery of the
associated replacement energy costs which BGE estimates to be approximately $33
million. (See NOTE 13 TO CONSOLIDATED FINANCIAL STATEMENTS.) This matter is
awaiting a decision by a hearing examiner.
In late March, 1987, the Nuclear Regulatory Commission (NRC) conducted an
inspection of the Plant for the purpose of examining BGE's compliance with
environmental qualification requirements mandated by NRC regulations. These
regulations require the establishment of a qualification file for the purpose of
demonstrating proof of operability of designated electric equipment regarded as
important to safety. This written proof of operability is related to the ability
of the equipment to function under harsh environments, such as extreme
temperatures, humidity, and radiation. The NRC's inspections revealed cable
splices that were lacking required documentation demonstrating compliance with
NRC regulations. The inspection results from Unit 2, which was shut down for
maintenance and refueling at the time of inspection, indicated a sufficient
number of equipment qualification problems that BGE shut down Unit 1 on April 1,
1987, in order to inspect for similar nonqualified electrical connections.
Subsequently, BGE identified an additional problem regarding the certification
of piping system fasteners with mechanical safety requirements. The fasteners
must be certified as meeting specified American Society of Mechanical Engineers
requirements; however, BGE was unable to document that all of the fasteners in
question had been certified. BGE received a notice of violation from the NRC in
connection with the environmental qualifications problem and paid civil
penalties in the amount of $300,000. In addition, the Calvert Cliffs Units were
out of service for a total of 66 days in order to document compliance with these
environmental and mechanical qualification requirements.
OPERATIONS IN 1988
The Plant generated 11,733,900 MWH in 1988 which resulted in a capacity
factor of 81%. BGE filed a fuel rate application under GUPP in May, 1989 in
which it demonstrated that it met the system-wide and individual plant
performance targets for 1988. People's Counsel alleged that BGE imprudently
managed several outages at the Plant and requested that the PSC disallow
recovery of $2 million of replacement energy costs. 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.
OPERATIONS IN 1989 TO 1991 -- EXTENDED OUTAGE
The Plant generated 2,719,197 MWH in 1989 and 1,251,416 MWH in 1990. 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 at that
time. 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 remained out of service until May 4, 1991 to complete
repair of 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. This estimate is based on a
computer simulation comparing the actual operating conditions during the
extended outages with operating conditions assuming the Plant ran at its
targeted capacity factor.
4
The extended outages experienced at the Plant are being reviewed by the PSC
in the 1989-1991 fuel rate proceeding, and People's Counsel and others have
challenged recovery of some part of the associated replacement energy costs. In
the PSC's Rate Order issued in BGE's 1990 Base Rate Case, it found that $4
million of operations and maintenance expenses incurred by BGE during the
1989-1990 outages at the Plant should not be recoverable from customers. The PSC
concluded that the related work, which was performed at Unit 1 during the
1989-1990 outage, was avoidable and caused by Company actions which were
deficient. The work characterized as avoidable had a significant impact on the
duration of the Unit 1 outage. The PSC's Order stated that its conclusions in
this proceeding did not have a binding effect in the fuel rate proceeding on the
recoverability of Calvert Cliffs' replacement energy costs. However, BGE
believes that it is doubtful that the PSC will authorize recovery of the full
amount of replacement energy costs presently under investigation. Based on a
review of the circumstances surrounding the extended outages by BGE personnel as
well as independent consultants, in 1990 BGE recorded a provision of $35 million
against the possible disallowance of such costs. However, BGE cannot determine
whether replacement energy costs may be disallowed in the 1989-1991 fuel rate
proceeding in excess of the provision, but such amounts could be material.
On March 15, 1994, the PSC Staff and the Office of People's Counsel filed
testimony in the 1989-1991 fuel rate proceedings. The PSC Staff concluded that
approximately 46% of the outage time was unreasonably incurred and that
approximately $200 million of replacement energy costs should be disallowed.
People's Counsel concluded that approximately $400 million of the replacement
energy costs should be disallowed. BGE is tentatively scheduled to file rebuttal
testimony in mid-August of 1994 at which time it will vigorously contest the
findings of Staff and People's Counsel. Further hearings in this matter are not
scheduled until mid-year of 1995.
As previously reported, in December 1988, the NRC categorized the Plant as
one requiring close monitoring and increased NRC attention. The NRC did so
following certain events that the NRC indicated raised questions about the
effectiveness of past corrective action regarding engineering and technical
areas and the overall approach to safety at the Plant. Details of such events
were described in the Report on Form 10-K for the year ended December 31, 1990
in the section titled "Nuclear Operations" on pages 4 through 7. In February
1992, the NRC removed the Plant from its list of nuclear plants categorized as
requiring close monitoring as a result of improved performance in previously
identified problem areas and the demonstration of a sustained period of safe
operation.
OPERATIONS IN 1991 AFTER THE EXTENDED OUTAGE
The Plant generated 9,036,100 MWH in 1991, which resulted in a capacity
factor of 63%. BGE filed a fuel rate application under GUPP in June 1992,
however, the Hearing Examiner has determined that the 1991 case will not be
addressed until the case covering the extended outage has been resolved.
OPERATIONS IN 1992
The Plant generated 10,663,950 MWH in 1992, which resulted in a capacity
factor of 74%. BGE's fuel rate application under GUPP for 1992 demonstrated that
the Plant exceeded its individual plant performance targets and that system-wide
performance exceeded targeted levels. There are no contested performance issues
based on 1992 performance.
OPERATIONS IN 1993
The Plant generated 12,300,816 MWH in 1993, which resulted in a capacity
factor of 85%. BGE's fuel rate application under GUPP for 1993 demonstrated that
the Plant exceeded its individual plant performance targets and that system-wide
performance exceeded targeted levels.
LOAD MANAGEMENT, ENERGY, AND CAPACITY PURCHASES
BGE has implemented various active load management programs designed to be
used when system operating conditions require a reduction in load. These
programs include customer-owned generation and curtailable service for large
commercial and industrial customers, air conditioning control which is available
to residential and commercial customers, and residential water heater control.
The load reductions typically have been invoked on peak summer days; the summer
peak capacity impact for 1994 from active load management is expected to be
approximately 470 megawatts (MW). Cost recovery for these load management
programs is attained through the inclusion in rate base of capital investments
and the appropriate expenses (including credits on customer bills) for recovery
in base rate proceedings.
The generating and transmission facilities of BGE are interconnected with
those of neighboring utility systems to form the Pennsylvania-New
Jersey-Maryland Interconnection (PJM). Under the PJM agreement, the
interconnected facilities are used for substantial energy interchange and
capacity transactions as well as emergency assistance. In addition, BGE enters
into short-term capacity transactions at various times to meet PJM obligations.
5
BGE has an agreement with Pennsylvania Power & Light Company (PP&L) to
purchase a mix of energy and capacity from June 1, 1990 through May 31, 2001.
This agreement, which has been accepted by the Federal Energy Regulatory
Commission, is designed to help maintain adequate reserve margins through this
decade and provide flexibility in scheduling power plant additions for the
latter half of the 1990s. The PP&L agreement entitles BGE to 5.94% of the energy
output, and net capacity (currently 124 MW), of PP&L's nuclear Susquehanna Steam
Electric Station from October 1, 1991 to May 31, 2001 and also enables BGE to
treat a portion of PP&L's capacity as BGE's capacity for purposes of satisfying
BGE's installed capacity requirements as a member of the PJM. BGE is not
acquiring an ownership interest in any of PP&L's generating units. PP&L will
continue to control, manage, operate, and maintain that station and all other
PP&L-owned generating facilities. BGE's firm capacity purchases at December 31,
1993 represented 170 MW of rated capacity of Bethlehem Steel Corporation's
Sparrows Point complex, 57 MW of rated capacity of the Baltimore Refuse Energy
Systems Company, and 124 MW of base load capacity from PP&L.
Also, on March 11, 1994, BGE announced that PECO Energy won a competitive
bid for additional capacity with a proposal to supply 140 megawatts for 25 years
beginning June 1, 1997. BGE anticipates submitting a contract for approval to
the PSC in the Spring of 1994.
FUEL FOR ELECTRIC GENERATION
Information regarding BGE's electric generation by fuel type and the cost of
fuels in the five-year period 1989-1993 is set forth in the following tables:
AVERAGE COST OF FUEL CONSUMED
GENERATION BY FUEL TYPE ( CENTS PER MILLION BTU)
--------------------------------------------- ----------------------------------------------
1993 1992 1991 1990 1989 1993 1992 1991 1990 1989
----- ----- ----- ----- ----- ------ ------ ------ ------ ------
Nuclear (a)................... 43% 40% 33% 5% 10% 53.01 45.54 48.64 54.86 50.43
Coal.......................... 55 54 44 44 46 151.85 154.76 160.74 154.56 154.31
Oil........................... 3 1 5 7 10 253.36 254.19 284.87 319.44 281.54
Hydro & Gas................... 3 3 4 6 5 -- -- -- -- --
----- ----- ----- ----- -----
104 98 86 62 71
Interchange/Purchases (b)..... (4) 2 14 38 29
----- ----- ----- ----- -----
100% 100% 100% 100% 100%
----- ----- ----- ----- -----
----- ----- ----- ----- -----
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(a) Nuclear fuel costs provide for disposal costs associated with long-term
off-site spent fuel storage and shipping, currently set by law at one mill
per kilowatt-hour of nuclear generation (approximately 10 cents per
million Btu) and for contributions to a fund for decommissioning and
decontaminating the Department of Energy's uranium enrichment facility.
(SEE FUEL FOR ELECTRIC GENERATION -- NUCLEAR.)
(b) Net purchases from (sales to) others.
COAL: BGE obtains a large amount of its coal under supply contracts with
mining operators. The remainder of its coal requirements are obtained through
spot purchases. BGE believes that it will be able to renew such contracts as
they expire or enter into similar contractual arrangements with other coal
suppliers. BGE's Brandon Shores Units 1 and 2 have a total annual requirement of
approximately 3,200,000 tons of coal (combined) with a sulfur content of less
than approximately 0.8%. The average delivered costs per ton paid by BGE for
Brandon Shores coal for the years 1989 through 1993 were $40.17, $39.00, $39.80,
$39.98, and $39.49, respectively. BGE's Crane Units 1 and 2 have a total annual
requirement of about 700,000 tons of coal (combined) with a sulfur content of
less than approximately 2.4% and a low ash melting temperature. The average
delivered costs per ton paid by BGE for coal at Crane for the years 1989 through
1993 were $42.62, $40.45, $38.88, $38.37, and $37.25, respectively. BGE's Wagner
Units 2 and 3 have a total annual requirement of approximately 1,000,000 tons of
coal (combined) with a sulfur content of no more than 1%. The average delivered
costs per ton paid by BGE for coal at Wagner for the years 1989 through 1993
were $41.45, $41.28, $44.49, $43.19, and $40.62, respectively.
Coal deliveries to BGE's coal burning facilities are made by rail and barge.
The coal used by BGE is produced from mines located in central and northern
Appalachia.
BGE has a 20.99% undivided interest in the Keystone coal-fired generating
plant and a 10.56% undivided interest in the Conemaugh coal-fired generating
plant. The bulk of the annual coal requirements for the Keystone plant is under
contract from Rochester and Pittsburgh Coal Company. The Conemaugh plant
purchases coal from local suppliers on the open market. The average delivered
costs per ton for coal for these plants for the years 1989 through 1993 were
$33.62, $36.69, $33.07, $31.53, and $32.42, respectively.
OIL: Under normal burn practices, BGE's requirements for residual fuel oil
amount to approximately 1,000,000 barrels of low-sulfur oil per year. Deliveries
of residual fuel oil are made directly into BGE barges from
6
the suppliers' Baltimore Harbor marine terminal for distribution to the various
generating plant locations. The average delivered prices per barrel paid by BGE
for residual fuel oil for the years 1989 through 1993 were $17.65, $20.24,
$15.53, $17.25, and $15.69 respectively.
NUCLEAR: The supply of fuel for nuclear generating stations involves the
acquisition of uranium concentrates, its conversion to uranium hexafluoride,
enrichment of uranium hexafluoride, and the fabrication of nuclear fuel
assemblies. Information is set forth below with respect to fuel for Calvert
Cliffs Units 1 and 2:
Uranium Concentrates: BGE has, either in inventory or under contract, sufficient
quantities of uranium concentrates to meet approximately 80% of
its requirements through 1997 and approximately 50% of its
requirements for 1998.
Conversion: BGE has contractual commitments providing for the conversion of
uranium concentrates into uranium hexafluoride which will meet
100% of BGE's requirements through 1995 and approximately 40% of
its requirements from 1996 through 1998.
Enrichment: BGE has a contract with the Department of Energy for the enrichment
of 100% of BGE's enrichment requirements through 1995 and 70% of
its requirements from 1996 through 1998.
Fuel Assembly BGE has contracted for the fabrication of fuel assemblies for
Fabrication: reloads it requires through 1996.
Under the Nuclear Waste Policy Act of 1982 (the 1982 Act), spent fuel
discharged from nuclear power plants, including Calvert Cliffs, is required to
be placed into a federal repository. Such facilities do not currently exist,
and, consequently, must be developed and licensed. BGE cannot now predict when
such facilities will be available, although the 1982 Act obligates the federal
government to accept spent fuel starting in 1998. While BGE cannot now predict
what the ultimate cost will be, the 1982 Act assesses a one mill per
kilowatt-hour fee on nuclear electricity generated and sold. At anticipated
operating levels, it is expected that this fee will be approximately $11 million
for Calvert Cliffs each year.
The Energy Policy Act of 1992 (the 1992 Act) contains provisions requiring
domestic utilities to contribute to a fund for decommissioning and
decontaminating the Department of Energy's (DOE) uranium enrichment facilities.
These contributions are generally payable over a fifteen-year period with
escalation for inflation and are based upon the amount of uranium enriched by
DOE for each utility. The 1992 Act provides that these costs are recoverable
through utility service rates as a cost of fuel. Information about the cost of
decommissioning is discussed in NOTE 1 TO THE CONSOLIDATED FINANCIAL STATEMENTS
on page 39 under the heading "UTILITY PLANT, DEPRECIATION AND AMORTIZATION, AND
DECOMMISSIONING."
Maryland law makes it unlawful to establish within the State a facility for
the permanent storage of high-level nuclear waste, unless otherwise expressly
required by federal law. BGE has received a license from the NRC to operate its
new on-site independent spent fuel storage facility. BGE now has storage
capacity at Calvert Cliffs that will accommodate spent fuel from operations
through the year 2006. In addition, BGE can expand its temporary storage
capacity to meet future requirements until federal storage is available.
Expenditures for nuclear fuel are discussed in MD&A -- LIQUIDITY AND CAPITAL
RESOURCES on page 28. Capital requirements for nuclear fuel returned to normal
levels in 1992. The 1991 level was abnormally low due to the accumulation in
inventory of nuclear fuel purchased and processed over the period of extended
outages at Calvert Cliffs during 1989-1991. The 1991 level reflects the use of
nuclear fuel from such inventoried stocks rather than new purchases.
GAS: BGE has a firm natural gas transportation entitlement of 3,500
dekatherms a day to provide ignition and banking at certain power plants. Gas
for electric generation is purchased as needed in the spot market using
interruptible transportation arrangements. Certain gas fired units can use
residual fuel oil as an alternative.
GAS OPERATIONS
BGE distributes natural gas purchased directly from several producers and
marketers. Transportation to BGE's city gate for these purchases is provided by
Columbia Gas Transmission Corporation (Columbia), CNG Transmission Corporation
(CNG), and Transcontinental Gas Pipe Line Corporation under various
transportation agreements. BGE has upstream transportation capacity under
contract on Tennessee Gas Pipeline Company, Texas Eastern Transmission
Corporation, Columbia Gulf Transmission Company and ANR Pipeline Company (ANR).
BGE has storage service agreements with Columbia, CNG and ANR. The
transportation and storage agreements are on file with the Federal Energy
Regulatory Commission (FERC).
7
BGE's current pipeline firm transportation entitlements to serve its firm
loads are 473,597 dekatherms (DTH) per day during the winter period and 291,231
DTH per day during the summer period. BGE uses the firm transportation capacity
to move gas from the Gulf of Mexico, Louisiana, south central regions of Texas
and Canada to BGE's city gate. The gas is subject to a mix of long and
short-term contracts that are managed to provide economic, reliable and flexible
service. Additional short-term contracts or exchange agreements with other gas
companies can be arranged in the event of short term emergencies.
To supplement BGE's gas supply at times of heavy winter demands and to be
available in temporary emergencies affecting gas supply, BGE has propane air and
liquefied natural gas facilities. The liquefied natural gas facility consists of
a plant for the liquefaction and storage of natural gas with a storage capacity
of 1,000,000 DTH and an installed daily capacity of 281,760 DTH. The propane air
facility consists of a plant with a mined cavern and refrigerated storage
facilities having a total storage capacity equivalent to 1,000,000 DTH and a
daily capacity of 91,600 DTH. BGE has under contract sufficient volumes of
propane for the operation of the propane air facility and is capable of
liquefying sufficient volumes of natural gas during the summer months for
operation of its liquefied natural gas facility during winter periods.
BGE offers gas for sale to its residential, commercial and industrial
customers on a firm and interruptible basis. BGE also provides its large
commercial and industrial customers with a transportation service across its
distribution system so that these customers may make direct purchase and
transportation arrangements with suppliers and pipelines. A transportation fee
is charged by BGE that is equivalent to its operating margin on gas it sells to
similar customers for the service from the city gate to the customer's facility.
This program enables BGE to maintain throughput at a level which assures that
fixed costs are spread over the maximum number of DTH. BGE is authorized by the
PSC to provide a balancing service for its transportation customers.
Future purchased gas costs are expected to increase due to transition costs
incurred by BGE gas pipeline suppliers in implementing FERC Order No. 636. These
transition costs, if approved by the PSC and FERC, will be passed on to BGE
customers through the purchased gas adjustment clause.
ENVIRONMENTAL MATTERS
The Company is subject to regulation with regard to air and water quality,
waste disposal, and other environmental matters by various federal, state, and
local authorities. Certain of these regulations require substantial expenditures
for additions to utility plant and the use of more expensive low-sulfur fuels.
While the Company cannot now precisely estimate the total effect of existing and
future environmental regulations and standards upon its existing and proposed
facilities and operations, the necessity for compliance with existing standards
and regulations has caused BGE to increase capital expenditures by approximately
$223 million during the five-year period 1989-1993. It is estimated that the
capital expenditures necessary to comply with such standards and regulations
will be approximately $37 million, $15 million, and $21 million for 1994, 1995,
and 1996, respectively.
AIR: The Federal Clean Air Act (the Act) mandates health and welfare
standards for concentrations of air pollutants. The State of Maryland is charged
by the Act with the responsibility for setting limits on all major sources of
these pollutants in the State so that these standards are not exceeded. Except
for Crane Units 1 and 2, BGE's generating units are limited to burning fuel
(coal or oil) with sulfur content of 1% or below. All units are limited to
emitting particulate matter at or below 0.02 grains per standard cubic foot of
exhaust gas for oil fired units and 0.03 grains per standard cubic foot for coal
fired units. Brandon Shores, a newer plant, is subject to more stringent
standards for sulfur dioxide (1.2 pounds per million Btu), and nitrogen dioxide
(0.7 pounds per million Btu). The Crane Units must meet limits of 3.5 pounds per
million Btu for sulfur dioxide, which is equivalent to a coal sulfur content of
approximately 2.4%. BGE is in compliance with existing air quality regulations.
Under a consent order with the Maryland Department of the Environment (MDE)
relating to such regulations, BGE is operating two of four units at its
Riverside facility at reduced capacity until these units are retired during
1994. The fifth Riverside unit was retired in 1991.
The Clean Air Act amendments of 1990 require sulfur dioxide emission
reductions at Crane and the jointly owned Conemaugh plant by 1995 and additional
controls at other coal plants to be in place by 2000. BGE presently plans to
achieve emission reduction at Crane by conversion to low-sulfur coal. The
capital costs for equipment changes at the Crane plant are estimated to be
approximately $7 million. Scrubbers are being installed at both units of the
Conemaugh plant, in which BGE has a 10.56% undivided ownership interest. BGE
estimates that its share of the costs of the scrubbers will be approximately
$42.7 million. In addition, BGE anticipates incurring other Clean Air Act costs
of approximately $10 million for various equipment such as continuous emission
monitors and precipitator upgrades by 2000.
At this time, plans for complying with nitrogen oxide (NOx) control
requirements under the Act are less certain because all implementation
regulations have not yet been finalized by the government. It is expected that
8
by the year 2000 these regulations will require additional NOx controls for
ozone non-attainment at BGE's generating plants and 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
non-attainment regulations, BGE currently estimates that the NOx controls at
BGE's generating plants will cost approximately $70 million. BGE is currently
unable to predict the cost of compliance with the additional requirements at
other BGE facilities.
WATER: The discharge of effluents into the navigable waters of the State of
Maryland is regulated by the MDE, in accordance with the National Pollutant
Discharge Elimination System (NPDES) permit program, established pursuant to the
Federal Clean Water Act. At the present time, all of BGE's steam electric
generating plants have the required NPDES permits.
MDE water quality regulations require, among other things, specifying
procedures for determining compliance with State water quality standards. These
procedures require extensive studies involving sampling and monitoring of the
waters around affected generating plants. Under current regulations, the State
of Maryland may require changes in plant operations. At this time BGE is
performing studies to determine whether any modifications will be required to
comply with these new regulations.
WASTE DISPOSAL: The United States Environmental Protection Agency (EPA) has
promulgated regulations implementing those portions of the Resource Conservation
and Recovery Act which deal with management of hazardous wastes. These
regulations, and the Hazardous and Solid Waste Amendments of 1984, designate
certain spent materials as hazardous wastes and establish standards and permit
requirements for those who generate, transport, store, or dispose of such
wastes. The State of Maryland has adopted similar regulations governing the
management of hazardous wastes, which closely parallel the federal regulations.
BGE has implemented procedures for compliance with all applicable federal and
state regulations governing the management of hazardous wastes. Certain high
volume utility wastes such as fly ash and bottom ash have been exempted from
these regulations. The Company currently utilizes almost all of its coal fly ash
and bottom ash as structural fill material in a manner approved by the State of
Maryland. The remainder of the coal ash is sold to the construction industry for
a number of approved applications.
The Federal Comprehensive Environmental Response, Compensation and Liability
Act (Superfund statute) establishes liability for the cleanup of hazardous
wastes found contaminating the soil, water, or air. Those who generated,
transported or deposited the waste at the contaminated site are each jointly and
severally liable for the cost of the cleanup, as are the current property owner
and their predecessors in title at the time of the contamination. In addition,
many states have enacted laws similar to the Superfund statute.
On October 16, 1989, the EPA filed a complaint in the U.S. District Court
for the District of Maryland under the Superfund statute against BGE and seven
other defendants to recover past and future expenditures associated with cleanup
of a site located at Kane and Lombard Streets in Baltimore. The State of
Maryland intervened by filing a similar complaint in the same case and court on
February 12, 1990. The complaints allege that BGE arranged for its fly ash to be
deposited on the site. The litigation is currently stayed pending settlement
discussions among all parties. Additional investigation was initiated on the
remainder of the site by the MDE for the EPA but was never completed. BGE and
three other defendants agreed to complete the remedial investigation and
feasibility study of groundwater contamination around the site in a July 1993
consent order. The remedial action, if any, for the remainder of the site will
not be selected until these investigations are concluded. Therefore, neither the
total site cleanup costs, nor BGE's share, can presently be estimated.
In the early 1970's, BGE shipped an unknown number of scrapped transformers
to Metal Bank of America, a metal reclaimer in Philadelphia. Metal Bank's scrap
and storage yard has been found to be contaminated with oil containing high
levels of PCBs (PCBs are hazardous chemicals frequently used as a fire-resistant
coolant in electrical equipment). On December 7, 1987, the EPA notified BGE and
other utilities that they are considered potentially responsible parties (PRPs)
with respect to the cleanup of the site. A remedial investigation and
feasibility study by BGE and the other PRPs is in progress. The investigation
costs are estimated to be about $6 million. BGE's share of the investigation
costs is estimated to be approximately 15.8%, or $1 million, based on an
allocation formula applied to the PRP group. The total cleanup costs are not yet
known so BGE's potential liability cannot be estimated, but such liability could
be material.
During the early 1970's, BGE disposed of a small amount of low-level nuclear
waste at a site in Morehead, Kentucky, known as Maxey Flats. This site was found
to have been operated improperly. As a result, low-level radioactive
contaminants have been found to be leaking from the site. On November 26, 1986,
the EPA notified BGE that it is one of approximately 800 PRPs. A remedial
investigation and feasibility study was completed by BGE and other PRPs. The EPA
has issued its Record of Decision, recommending a natural stabilization remedy.
The cost estimate for this remedy is currently estimated to be approximately $60
million for all PRPs. BGE's
9
volumetric share of the waste on-site is 0.0103 percent of the total, based upon
BGE's records of waste shipped to the site compared to the total recorded waste.
BGE's potential liability cannot be estimated, but such liability is not likely
to be substantial because its volumetric share of the waste on-site is so small.
From 1985 until 1989, BGE shipped waste oil and other materials to the
Industrial Solvents and Chemical Company in York County, Pennsylvania for
disposal. The Pennsylvania Department of Environmental Resources (Pennsylvania
Department) subsequently investigated this site and found it to be heavily
contaminated by hazardous wastes. The Pennsylvania Department notified BGE on
August 15, 1990, that it and approximately 1,000 other entities were PRPs with
respect to the cost of all remedial activities to be conducted at the site. No
remedial investigation or feasibility study has been undertaken, but the PRPs
agreed to perform waste characterization at the site in a July 1993 consent
order. Also, the PRPs agreed to remove and dispose of specified numbers of drums
and tanks of waste in a December 1993 consent order. BGE's share of the
liability at this site currently is estimated to be approximately 2.39%, but
this may change as additional information about the site is obtained. The actual
cost of remedial activities has not been determined. As a result of these
factors, BGE's potential liability cannot presently be estimated. However, such
liability could be material.
On March 9, 1993 BGE was served in litigation instituted by the EPA in the
United States District Court for the Eastern District of Pennsylvania involving
contamination of the Douglassville site in Berks County, Pennsylvania. BGE was
named as a third party defendant based upon allegations that BGE had contracted
with A&A Waste Oils, an original defendant, to dispose of oils and lubricants.
BGE was dismissed as a party to this litigation in August, 1993.
In the early part of the century, predecessor gas companies (which were
later merged into BGE) manufactured coal gas for residential and industrial use.
The residue from this manufacturing process was coal tar, previously thought to
be harmless but now found to contain a number of chemicals designated by the EPA
as hazardous substances. BGE is coordinating an investigation of these former
coal gas plant sites, including exploration of corrective action options to
remove coal tar, with the MDE. No formal legal proceedings have been instituted
with respect to these sites. The technology for cleaning up such sites is still
developing, and potential remedies for these sites have not been identified. As
explained in NOTE 13 TO THE CONSOLIDATED FINANCIAL STATEMENTS on page 52, a
liability of $25.4 million was accrued in 1993 regarding future estimated
expenditures at these sites. Any cleanup costs for these sites in excess of the
amount accrued, which could be significant in total, cannot presently be
estimated.
10
ELECTRIC OPERATING STATISTICS
YEAR ENDED DECEMBER 31,
-------------------------------------------------------------------------
1993 1992 1991 1990 1989
------------- ------------- ------------- ------------- -------------
Electric Output (In Thousands) -- MWH:
Generated....................................... 28,907 25,626 22,767 15,193 18,296
Purchased (A)................................... 2,627 4,323 5,522 11,859 8,959
------------- ------------- ------------- ------------- -------------
Subtotal.................................... 31,534 29,949 28,289 27,052 27,255
Less Interchange Sales.......................... 4,149 3,180 1,167 1,088 595
------------- ------------- ------------- ------------- -------------
Total Output................................ 27,385 26,769 27,122 25,964 26,660
------------- ------------- ------------- ------------- -------------
------------- ------------- ------------- ------------- -------------
Power Generated and Purchased at Times of Peak
Load (MW) (one hour):
Generated by Company............................ 5,245 3,679 4,948 3,032 2,954
Net Purchased (A)............................... 631 1,879 962 2,445 2,350
------------- ------------- ------------- ------------- -------------
Peak Load (B)................................... 5,876 5,558 5,910 5,477 5,304
------------- ------------- ------------- ------------- -------------
------------- ------------- ------------- ------------- -------------
Annual System Load Factor (%)..................... 55.2 54.8 52.4 54.1 57.4
Revenues (In Thousands)
Residential..................................... $ 931,643 $ 839,954 $ 882,591 $ 718,032 $ 648,883
Commercial...................................... 869,829 842,694 850,038 758,573 668,819
Industrial...................................... 199,042 201,950 212,864 194,951 191,796
------------- ------------- ------------- ------------- -------------
System Sales.................................... 2,000,514 1,884,598 1,945,493 1,671,556 1,509,498
Interchange Sales............................... 91,543 64,323 23,845 26,629 17,802
Other........................................... 23,098 19,002 25,187 14,268 19,867
------------- ------------- ------------- ------------- -------------
Total....................................... $ 2,115,155 $ 1,967,923 $ 1,994,525 $ 1,712,453 $ 1,547,167
------------- ------------- ------------- ------------- -------------
------------- ------------- ------------- ------------- -------------
Sales (In Thousands) -- MWH:
Residential..................................... 10,614 9,735 10,097 9,283 9,451
Commercial...................................... 12,395 11,909 11,707 11,352 11,079
Industrial...................................... 3,763 3,663 3,708 3,743 4,261
------------- ------------- ------------- ------------- -------------
System Sales.................................... 26,772 25,307 25,512 24,378 24,791
Interchange Sales............................... 4,149 3,180 1,166 1,088 595
------------- ------------- ------------- ------------- -------------
Total....................................... 30,921 28,487 26,678 25,466 25,386
------------- ------------- ------------- ------------- -------------
------------- ------------- ------------- ------------- -------------
Customers
Residential..................................... 968,212 956,570 939,734 930,880 913,910
Commercial...................................... 100,820 99,673 98,254 96,567 95,102
Industrial...................................... 3,800 3,761 3,584 3,526 3,132
------------- ------------- ------------- ------------- -------------
Total....................................... 1,072,832 1,060,004 1,041,572 1,030,973 1,012,144
------------- ------------- ------------- ------------- -------------
------------- ------------- ------------- ------------- -------------
Average Cost of Fuel Consumed ( CENTS per million
Btu)............................................. 112.77 110.20 127.89 177.00 167.34
------------- ------------- ------------- ------------- -------------
------------- ------------- ------------- ------------- -------------
BGE achieved an all-time peak load of 6,038 megawatts on January 19, 1994.
- --------------------------
(A) Includes purchases from Safe Harbor Water Power Corporation, a
hydroelectric company, of which the Company owns two-thirds of the capital
stock.
(B) See page 5 for a discussion of active load management programs which may
be activated at times of peak load.
In 1993, BGE changed its classification of commercial and industrial
customers to present this information on a basis which is more consistent with
predominant industry practices. Prior-year amounts have been reclassified to
conform to the current year's presentation.
11
GAS OPERATING STATISTICS
YEAR ENDED DECEMBER 31,
---------------------------------------------------------------
1993 1992 1991 1990 1989
----------- ----------- ----------- ----------- -----------
Gas Output (In Thousands) -- DTH:
Purchased.................................................. 71,204 70,208 63,159 59,470 70,063
LNG Withdrawn from Storage................................. 725 742 551 333 789
Produced................................................... 259 92 17 5 736
----------- ----------- ----------- ----------- -----------
Total Output........................................... 72,188 71,042 63,727 59,808 71,588
Delivery Service Gas
Delivered (A).............................................. 38,521 41,048 40,503 43,377 44,696
----------- ----------- ----------- ----------- -----------
Total.................................................. 110,709 112,090 104,230 103,185 116,284
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
Peak Day Sendout (DTH)....................................... 657,700 609,200 610,200 653,900 663,200
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
Capability on Peak Day (DTH)................................. 847,000 847,000 817,000 853,000 761,000
Revenues (In Thousands)
Residential................................................ $ 265,601 $ 242,737 $ 220,653 $ 218,967 $ 242,389
Commercial
Excluding Delivery Service............................... 121,832 112,147 96,189 89,573 112,630
Delivery Service......................................... 3,287 3,591 3,031 3,304 4,409
Industrial
Excluding Delivery Service............................... 22,250 21,123 14,855 32,439 18,363
Delivery Service......................................... 12,920 14,290 14,288 17,851 22,661
Other...................................................... 9,959 9,049 9,179 11,285 11,349
----------- ----------- ----------- ----------- -----------
Total.................................................. $ 435,849 $ 402,937 $ 358,195 $ 373,419 $ 411,801
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
Sales (In Thousands) -- DTH:
Residential................................................ 40,029 39,042 36,519 35,026 39,806
Commercial
Excluding Delivery Service............................... 23,830 23,478 20,687 18,164 21,964
Delivery Service......................................... 7,428 7,102 6,433 5,872 5,778
Industrial
Excluding Delivery Service............................... 5,298 5,314 3,605 7,305 3,697
Delivery Service......................................... 31,390 33,638 34,240 34,720 39,452
----------- ----------- ----------- ----------- -----------
Total.................................................. 107,975 108,574 101,484 101,087 110,697
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
Customers
Residential................................................ 491,165 486,863 482,085 482,680 482,538
Commercial................................................. 37,518 37,000 36,561 35,953 35,970
Industrial................................................. 1,353 1,412 1,385 1,401 1,398
----------- ----------- ----------- ----------- -----------
Total.................................................. 530,036 525,275 520,031 520,034 519,726
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
BGE achieved an all-time peak day sendout of 762,000 DTH on January 19, 1994.
- --------------------------
(A) Represents gas purchased by alternate fuel customers directly from
suppliers for which BGE receives a fee for transportation through its
system ("delivery service"). (SEE MD&A -- RESULTS OF OPERATIONS.)
In 1993, BGE changed its classification of commercial and industrial
customers to present this information on a basis which is more consistent with
predominant industry practices. Prior-year amounts have been reclassified to
conform to the current year's presentation.
12
FRANCHISES
BGE has nonexclusive electric and gas franchises to use streets and other
highways which are adequate and sufficient to permit BGE to engage in its
present business. All such franchises, other than the gas franchises in
Manchester, Hampstead, Perryville, Sykesville, Havre de Grace, and Montgomery
and Frederick Counties, are unlimited as to time. The gas franchises for these
jurisdictions expire at various times from 1994 to 2020, except for Havre de
Grace which has the right, exercisable at twenty-year intervals from 1907, to
purchase all of BGE's gas properties in that municipality. Conditions of the
franchises are satisfactory. BGE also has rights-of-way to maintain 26-inch
natural gas mains across certain Baltimore City owned property (principally
parks) which expire in 1999 and 2004, each subject to renewal during the last
year thereof for an additional period of 25 years on a fair revaluation of the
rights so granted. Conditions of the grants are satisfactory.
Franchise provisions relating to rates have been superseded by the Public
Service Commission Law of Maryland.
DIVERSIFIED BUSINESSES
GENERAL
Diversified businesses consist of the operations of the Constellation
Companies and BNG, Inc.
The Constellation Companies' businesses are concentrated in three major
areas -- power generation projects, financial investments, and real estate
projects (including senior living facilities). A significant portion of the
Constellation Companies' activities are conducted through joint ventures in
which they hold varying ownership interests.
The Constellation Companies hold up to a 50% ownership interest in 24 power
generating projects in operation or under construction accounting for $285
million of the Constellation Companies' assets. One of these power generation
construction projects is the Puna project, which is discussed on page 14. These
projects, all of which either are qualifying facilities under the Public Utility
Regulatory Policies Act of 1978 or are otherwise exempt from the Public Utility
Holding Company Act of 1935, are of the following types and aggregate generation
capacities: coal 160 MW, solar 170 MW, geothermal 121 MW, waste coal 182 MW,
wood burning 70 MW, and hydro 30 MW. In addition, another $6 million has been
spent on projects in development. The Constellation Companies also participate
in the operation and maintenance of 23 power generation projects existing or
under construction, 10 of which are projects in which the Constellation
Companies hold an ownership interest. Financial investments account for $213
million of the Constellation Companies' assets. These assets include $91 million
in internally and externally managed securities portfolios, $83 million in
monoline financial guaranty (credit enhancement) companies, and $39 million in
tax-oriented transactions. Real estate projects account for $489 million of the
Constellation Companies' assets. These projects include raw land, office
buildings, retail, and commercial projects, an entertainment, dining, and retail
complex in Orlando, Florida, a mixed-use planned unit development, and senior
living facilities. The majority of the real estate projects are in the
Baltimore-Washington area and have been adversely affected by the depressed real
estate and economic market.
The Constellation Companies' investment in wholesale power generating
projects includes $163 million representing ownership interests in 16 projects
which sell electricity in California under Interim Standard Offer No. 4 power
purchase agreements. Under these agreements, the properties supply electricity
to purchasing utilities at a fixed energy rate for the first ten years of the
agreements and at 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 after these agreements were signed, 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. If
current avoided cost levels were to continue into 1996 and beyond, the
Constellation Companies could experience reduced earnings or incur losses
associated with these projects, which could be significant. The Constellation
Companies are investigating alternatives for certain of these power generation
projects including, but not limited to, repowering the projects to reduce
operating costs, renegotiating the power purchase agreements, and selling their
ownership interests in the projects. The Company cannot predict the impact these
matters may have on the Constellation Companies or the Company, but the impact
could be material.
The Constellation Companies contributed approximately $12 million, or 4% to
the Company's 1993 after-tax earnings, a decrease from the contribution of
approximately $15 million in 1992. For additional information about the
Constellation Companies, see MD&A -- RESULTS OF OPERATIONS -- DIVERSIFIED
BUSINESSES EARNINGS (which includes the Constellation Companies' earnings
information broken down by line of business) and MD&A -- LIQUIDITY AND CAPITAL
RESOURCES -- DIVERSIFIED BUSINESSES CAPITAL REQUIREMENTS.
13
BNG, Inc. is a wholly owned subsidiary of BGE which invests in natural gas
reserves. BNG owns gas producing properties in West Virginia, the output of
which is sold to BGE for the life of the reserves under a contract on file with
the PSC.
PUNA PROJECT
As discussed in previous filings made by the Company under the Securities
Exchange Act of 1934, the Constellation Companies have a 49% ownership interest
in a joint venture, Puna Geothermal Venture (PGV). PGV developed and is
operating a 25-megawatt geothermal energy project on the island of Hawaii (the
Big Island) in the State of Hawaii (the Puna project). Construction of the Puna
project was scheduled to be completed during 1991; however, it began generating
electricity on April 22, 1993. PGV sells the electricity it generates to Hawaii
Electric Light Company, Inc. ("Hawaii Electric") under a power purchase
agreement that calls for the supply by PGV of at least 22 megawatts.
Through the date of this Report, the Constellation Companies' investment in
the Puna project was $81.7 million. In addition, the Constellation Companies
have loaned $5 million (including accrued interest) to the other partner in PGV
for use in funding venture costs. PGV has outstanding a $93.4 million
construction loan. In connection with the construction loan, Constellation
Investments, Inc. (CII) provided a guarantee to the lending institution that
requires the Constellation Companies to put up to $15 million of equity into the
Puna project in certain events. The lender has the right to call the guarantee
but has not done so. Negotiations are ongoing with the project lenders to
convert the construction loan to permanent financing.
The diversified businesses section of the capital requirements chart on page
15 includes $15 million for the year 1994 relating to the Puna project. Of this
amount, approximately $14 million is additional equity that the Constellation
Companies will be required to contribute to PGV under the CII guarantee, and
approximately $1 million is additional costs relating to the project. In
addition, the Constellation Companies may need to fund $3 million to $20 million
during 1994 that is not included in the capital requirements chart to deal with
the problem with the production wells described below.
The Company cannot predict the impact that the matters involving the Puna
project discussed below may have on the Constellation Companies or the Company,
but such impact could be material.
PGV currently has two production wells that provide steam to power the
project. Recently, one of the production wells changed from a steam dominated
resource to a brine dominated resource. The result is that the well produces
considerably more fluid to inject back into the ground. If the second production
well also changes from steam dominated to brine dominated, PGV will have
insufficient injection capacity to handle the resulting increase in fluid volume
and this may affect the project's ability to generate the megawatts required
under the power purchase agreement. Studies are underway to determine both the
likelihood of the second production well changing to brine dominated and the
need for additional injection or production wells. The studies have not reached
a point where a prediction about the outcome can be made.
On April 13, 1993, Hawaii Electric filed suit, HAWAII ELECTRIC LIGHT
COMPANY, INC. v. PUNA GEOTHERMAL VENTURE COMPANY, INC., Civil No. 93-234 (3rd
Circuit Ct., Hawaii), seeking to require PGV to pay contractual penalties of
$7.5 million (for delays in the scheduled delivery of power to Hawaii Electric)
and seeking to require PGV to pay consequential damages. PGV asserts that the
delay was caused by a "force majeure" event. A tentative settlement has been
agreed to which requires no additional capital contributions from the
Constellation Companies.
PGV intervened in WAO KELE O PUNA, ET AL. v. WAIHEE, ET AL., Civil No.
91-3553-10 (1st Circuit Court, Hawaii) on the grounds that plaintiffs improperly
are seeking to include the Puna project in an existing suit against the State of
Hawaii and the County regarding an unrelated project. If plaintiffs succeed, the
State and the County could be enjoined from any further permit review and
issuance and from monitoring activity for the Puna project, effectively shutting
down the Puna project. The Constellation Companies understand that the unrelated
project has been cancelled, but the effect, if any, on this lawsuit are
uncertain.
During 1993, EPA informed PGV that it was investigating the circumstances
regarding two air releases of hydrogen sulfide from the Puna project's well
drilling activities. EPA issued a final preliminary assessment report giving the
PGV site a low priority for further assessment action based on the fact there is
no residual hydrogen sulfide problem at the site to be remediated.
The Constellation Companies' partner in the Puna project continues to
experience financial difficulties. The partner has not been meeting its funding
obligation to PGV for over two years. Also, the partner is currently in default
under the $5 million loan it obtained from the Constellation Companies. On
February 22, 1994, the Constellation Companies reached tentative agreement with
the partner and certain of the partner's direct and
14
indirect shareholders which would result in recapitalization of the project, and
repayment of the $5 million loan to Constellation. This agreement is subject to
project lender approval and certain approvals by shareholders of the partner.
There are no assurances that these approvals will be obtained.
CAPITAL REQUIREMENTS
Capital requirements for diversified businesses for 1991 through 1993, along
with estimated amounts for 1994 through 1996, are set forth below:
1991 1992 1993 1994 1995 1996
---- ---- ---- ---- ---- ----
(IN MILLIONS)
Retirement of long-term
debt......................... $167 $118 $222 $ 9 $ 81 $ 77
Investment requirements....... 109 80 78 63 60 20
---- ---- ---- ---- ---- ----
Total diversified
businesses................. $276 $198 $300 $ 72 $141 $ 97
---- ---- ---- ---- ---- ----
---- ---- ---- ---- ---- ----
The investment requirements shown above include the Constellation Companies'
portion of equity funding to committed projects under development as well as net
loans made to project partnerships. The investment requirements for past periods
reflect actual funding of projects, whereas investment requirements for the
years 1994-1996 reflect the Constellation Companies' estimate of funding during
such periods for ongoing and anticipated projects. Also, guarantees of $36
million may be called which are not included above. For more information see
SCHEDULE VII -- GUARANTEES OF SECURITIES OF OTHER ISSUERS.
Estimates of the Constellation Companies' investment requirements are
subject to continuous review and modification. Actual investment requirements
may vary significantly from the amounts above due to 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' investment requirements have been
met in the past through the internal generation of cash and through borrowings
from institutional lenders.
See NOTES 3 AND 4 TO CONSOLIDATED FINANCIAL STATEMENTS AND MD&A -- LIQUIDITY
AND CAPITAL RESOURCES -- DIVERSIFIED BUSINESSES CAPITAL REQUIREMENTS for
additional information about diversified activities.
EMPLOYEES
As of December 31, 1993, BGE employed 9,028 people for its utility
operations. Additionally, 135 people were employed by the Constellation
Companies. The Constellation Companies' amount excludes the approximately 800
employees at an entertainment, dining, and retail complex in Orlando, Florida
and 55 employees of two wholly owned subsidiaries operating two power generation
facilities. The number of employees at BGE's utility operations is 7,941 as of
the date of this report as a result of the various employee reduction programs
initiated in 1993. See NOTE 7 TO CONSOLIDATED FINANCIAL STATEMENTS.
15
ITEM 2. PROPERTIES
ELECTRIC: The principal electric generating plants of BGE are as follows:
INSTALLED GENERATION (MWH)
CAPACITY ----------------------
PLANT LOCATION (MW) PRIMARY FUEL 1993 1992
- ------------------------ ------------------------ ------------ ------------ ---------- ----------
(AT DECEMBER 31, 1993)
Steam
Calvert Cliffs Calvert County, MD 1,660 Nuclear 12,300,816 10,663,950
Brandon Shores Anne Arundel County, MD 1,288 Coal 7,584,610 6,793,320
Herbert A. Wagner Anne Arundel County, MD 991 Coal/Oil/Gas 2,953,056 2,348,466
Charles P. Crane Baltimore County, MD 380 Coal 2,102,530 1,818,747
Gould Street Baltimore City, MD 104 Oil 162,160 63,612
Riverside Baltimore County, MD 277 Oil/Gas 81,710 102,215
Westport Baltimore City, MD 127 Oil 33,717 44,332
Jointly Owned -- Steam
Keystone Armstrong and Indiana 359(A) Coal 2,497,351 2,500,289
Counties, PA
Conemaugh Indiana County, PA 181(A) Coal 1,147,729 1,262,146
Combustion Turbine
Notch Cliff Baltimore County, MD 128 Gas 12,276 11,281
Perryman Harford County, MD 208 Oil 11,320 5,320
Westport Baltimore City, MD 121 Gas 9,863 7,905
Riverside Baltimore County, MD 173 Oil/Gas 6,632 2,510
Philadelphia Road Baltimore City, MD 64 Oil 2,537 1,174
Charles P. Crane Baltimore County, MD 14 Oil 386 253
Herbert A. Wagner Anne Arundel County, MD 14 Oil 172 178
------------ ---------- ----------
Totals 6,089 28,906,865 25,625,698
------------
------------ ---------- ----------
---------- ----------
- ----------------------------------
(A) BGE-owned proportionate interest and entitlement. These totals include
diesel capacity of 2 megawatts and 1 megawatt for Keystone and Conemaugh,
respectively.
BGE also owns two-thirds of the outstanding capital stock of Safe Harbor
Water Power Corporation, and is currently entitled to 277 megawatts of the rated
capacity of the Safe Harbor Hydroelectric Project. Safe Harbor is operated under
a FERC license which expires in the year 2030.
GAS: BGE has propane air and liquefied natural gas facilities as described
in Gas Operations on page 7.
GENERAL: All of the principal plants and other important units of BGE
located in Maryland are held in fee except that several properties (not
including any principal electric or gas generating plant or the principal
headquarters building owned by BGE in downtown Baltimore) in BGE's service area
are held under lease arrangements. The leased spaces are used for various
office, service and/or retail merchandising purposes. Electric transmission and
electric and gas distribution lines are constructed principally (a) in public
streets and highways pursuant to franchises or (b) on permanent fee simple or
easement rights-of-way secured for the most part by grants from record owners
and as to a relatively small part by condemnation.
BGE's undivided interests as a tenant in common in the properties acquired
for the Keystone and Conemaugh Plants located in Pennsylvania are held in fee by
BGE, subject to minor defects and encumbrances which do not materially interfere
with the use of the properties by BGE.
All of BGE's property referred to above is subject to the lien of the
Mortgage securing BGE's First Refunding Mortgage Bonds.
ITEM 3. LEGAL PROCEEDINGS
ASBESTOS
During 1993, BGE was 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. The 260 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.
16
The second type are claims by two manufacturers -- Owens Corning Fiberglass
and Pittsburgh Corning Corp. -- against BGE and approximately eight others, as
third-party defendants. These relate to approximately 1,500 individual
plaintiffs who have settled with the manufacturers. 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.
See ITEM 1. BUSINESS -- RATE MATTERS, NUCLEAR OPERATIONS, ENVIRONMENTAL
MATTERS, DIVERSIFIED BUSINESSES -- PUNA PROJECT, and NOTE 13 TO CONSOLIDATED
FINANCIAL STATEMENTS.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not Applicable.
17
ITEM 10. EXECUTIVE OFFICERS OF THE REGISTRANT
Executive Officers of the Registrant are:
OTHER OFFICES OR POSITIONS
NAME AGE PRESENT OFFICE HELD DURING PAST FIVE YEARS
- ----------------------------- --- --------------------------------------------- ---------------------------------------------
Christian H. Poindexter 55 Chairman of the Board (A) Vice Chairman of the Board
(Since January 1, 1993) President, Constellation
Holdings, Inc.
Edward A. Crooke 55 President (B) President, Utility Operations
(Since September 1, 1992)
Bruce M. Ambler 54 President President, Constellation
Constellation Holdings, Inc. Development, Inc.
(Since August 1, 1989) Vice President, Constellation Holdings, Inc.
George C. Creel 60 Senior Vice President Senior Vice President
Generation Vice President, Nuclear Energy
(Since January 1, 1993) Vice President, Fossil Energy
Thomas F. Brady 44 Vice President Vice President
Customer Service and Customer Service and
Distribution Accounting
(Since July 1, 1993) Vice President, Accounting and
Economics
Herbert D. Coss, Jr. 59 Vice President Vice President
Marketing and Gas Electric Interconnection and
Operations Transmission
(Since January 1, 1994) Vice President, Interconnection
and Operations
Vice President, General Services
Robert E. Denton 50 Vice President Plant General Manager, Calvert Cliffs
Nuclear Energy Nuclear Power Plant
(Since September 1, 1992) Manager, Calvert Cliffs Nuclear Power Plant
Manager, Quality Assurance and Staff
Services
Carserlo Doyle 49 Vice President Manager, Telecommunications
Electric Interconnection Principal Engineer
and Transmission
(Since January 1, 1994)
Jon M. Files 58 Vice President Vice President, Management and Staff
Management Services Services
(Since September 1, 1989)
Ronald W. Lowman 49 Vice President Manager, Fossil Engineering
Fossil Energy Manager, Fossil Engineering
(Since January 1, 1993) Services
Manager, Generation
Maintenance
G. Dowell Schwartz, Jr. 57 Vice President Manager, Auditing
General Services
(since April 1, 1990)
Charles W. Shivery 48 Vice President Vice President
Finance and Accounting, Corporate Finance,
Chief Financial Officer Treasurer and Secretary
and Secretary Treasurer and Secretary and
(Since July 1, 1993) Manager, Finance
Joseph A. Tiernan 55 Vice President Vice President,
Corporate Affairs Corporate Administration
(Since February 1, 1993) Vice President, Nuclear Energy
- --------------------------
(A) Chief Executive Officer, Director, and member of the Executive Committee.
(B) Chief Operating Officer, Director, and member of the Executive Committee.
18
Officers of the Registrant are elected by, and hold office at the will of,
the Board of Directors and do not serve a "term of office" as such. There is no
arrangement or understanding between any officer and any other person pursuant
to which the officer was selected.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
STOCK TRADING
BGE's Common Stock, which is traded under the ticker symbol BGE, is listed
on the New York, Chicago, and Pacific stock exchanges, and has unlisted trading
privileges on the Boston, Cincinnati, and Philadelphia exchanges.
As of February 28, 1994, there were 82,321 common shareholders of record.
DIVIDEND POLICY
The Common Stock is entitled to dividends when and as declared by the Board
of Directors. There are no limitations in any indenture or other agreements on
payment of dividends; however, holders of Preferred Stock (first) and holders of
Preference Stock (next) are entitled to receive, when and as declared, from the
surplus or net profits, cumulative yearly dividends at the fixed preferential
rate specified for each series and no more, payable, quarterly, and to receive
when due the applicable Preference Stock redemption payments, before any
dividend on the Common Stock shall be paid or set apart.
Dividends have been paid on the Common Stock continuously since 1910. Future
dividends depend upon future earnings, the financial condition of the Company
and other factors. Quarterly dividends were declared on the Common Stock during
1993 and 1992 in the amounts set forth below.
COMMON STOCK DIVIDENDS AND PRICE RANGES
1993 1992
------------------------- -------------------------
PRICE* PRICE*
DIVIDEND ---------------- DIVIDEND ----------------
DECLARED HIGH LOW DECLARED HIGH LOW
-------- ------- ------- -------- ------- -------
First Quarter................. $ .36 $26 3/8 $22 3/8 $ .35 $23 1/8 $19 3/4
Second Quarter................ .37 26 5/8 23 7/8 .36 22 5/8 19 7/8
Third Quarter................. .37 27 1/2 25 1/8 .36 24 3/8 21 1/2
Fourth Quarter................ .37 26 7/8 23 1/2 .36 24 1/8 21 3/4
-------- --------
Total..................... $ 1.47 $ 1.43
-------- --------
-------- --------
- --------------------------
*Based on New York Stock Exchange Composite Transactions as reported in the
eastern edition of THE WALL STREET JOURNAL.
19
ITEM 6. SELECTED FINANCIAL DATA
1993 1992 1991 1990 1989
---------- ---------- ---------- ---------- ----------
(DOLLAR AMOUNTS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
Summary of Operations
Total Revenues................................................. $2,668,714 $2,491,343 $2,448,853 $2,178,112 $2,032,009
Expenses Other Than Interest and Income Taxes.................. 2,047,714 1,955,998 1,959,665 1,854,183 1,555,424
---------- ---------- ---------- ---------- ----------
Income From Operations......................................... 621,000 535,345 489,188 323,929 476,585
Other Income................................................... 15,702 22,096 26,628 36,674 30,928
---------- ---------- ---------- ---------- ----------
Income Before Interest and Income Taxes........................ 636,702 557,441 515,816 360,603 507,513
Interest Expense............................................... 188,764 189,747 196,588 165,205 149,593
---------- ---------- ---------- ---------- ----------
Income Before Income Taxes..................................... 447,938 367,694 319,228 195,398 357,920
Income Taxes................................................... 138,072 103,347 85,547 19,952 81,629
---------- ---------- ---------- ---------- ----------
Income Before Cumulative Effect of Changes in Accounting
Methods....................................................... 309,866 264,347 233,681 175,446 276,291
Cumulative Effect of Change in the Method of Accounting for
Income Taxes.................................................. -- -- 19,745 -- --
Cumulative Effect of Change in the Method of Accounting for
Unbilled Revenues, Net of Taxes............................... -- -- -- 37,754 --
---------- ---------- ---------- ---------- ----------
Net Income..................................................... 309,866 264,347 253,426 213,200 276,291
Preferred and Preference Stock Dividends....................... 41,839 42,247 42,746 40,261 32,381
---------- ---------- ---------- ---------- ----------
Earnings Applicable to Common Stock............................ $ 268,027 $ 222,100 $ 210,680 $ 172,939 $ 243,910
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
Earnings Per Share of Common Stock
Before Cumulative Effect of Changes in Accounting Methods.... $ 1.85 $ 1.63 $ 1.51 $ 1.09 $ 2.03
Cumulative Effect of Change in the Method of Accounting for
Income Taxes................................................ -- -- .16 -- --
Cumulative Effect of Change in the Method of Accounting for
Unbilled Revenues........................................... -- -- -- .31 --
---------- ---------- ---------- ---------- ----------
Total Earnings Per Share of Common Stock....................... $ 1.85 $ 1.63 $ 1.67 $ 1.40 $ 2.03
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
Dividends Declared Per Share of Common Stock................... $ 1.47 $ 1.43 $ 1.40 $ 1.40 $ 1.38
Ratio of Earnings to Fixed Charges............................. 3.00 2.65 2.27 1.78 3.02
Ratio of Earnings to Fixed Charges and Preferred and Preference
Stock Dividends Combined...................................... 2.34 2.08 1.82 1.47 2.44
Financial Statistics at Year End
Total Assets................................................... $7,987,039 $7,374,357 $7,137,989 $6,710,375 $5,985,679
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
Capitalization
Long-term debt............................................... $2,823,144 $2,376,950 $2,390,115 $2,193,844 $2,076,620
Preferred stock.............................................. 59,185 59,185 59,185 59,185 59,185
Redeemable preference stock.................................. 342,500 395,500 398,500 365,000 322,800
Preference stock not subject to mandatory redemption......... 150,000 110,000 110,000 110,000 110,000
Common shareholders equity................................... 2,620,511 2,534,639 2,153,306 2,073,158 2,001,188
---------- ---------- ---------- ---------- ----------
Total capitalization......................................... $5,995,340 $5,476,274 $5,111,106 $4,801,187 $4,569,793
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
Book Value Per Share of Common Stock........................... $ 17.94 $ 17.63 $ 17.00 $ 16.58 $ 16.60
Number of Common Shareholders.................................. 82,287 80,371 71,131 73,049 75,762
20
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
This annual report presents the financial condition and results of
operations of Baltimore Gas and Electric Company (BGE) and its subsidiaries
(collectively, the Company). Among other information, it provides Consolidated
Financial Statements, Notes to Consolidated Financial Statements (Notes),
Utility Operating Statistics, and Selected Financial Data. The following
discussion explains factors that significantly affect the Company's results of
operations, liquidity, and capital resources.
RESULTS OF OPERATIONS
EARNINGS PER SHARE OF COMMON STOCK
Consolidated earnings per share were $1.85 for 1993 and $1.63 for 1992, an
increase of $.22 and a decrease of $.04 from prior-year amounts. The changes in
earnings per share reflect a higher level of earnings applicable to common
stock, offset partially in 1993 and completely in 1992 by the larger number of
outstanding common shares. The summary below presents the earnings-per-share
amounts.
1993 1992 1991
--------- --------- ---------
Utility business........................................................................... $ 1.77 $ 1.52 $ 1.60
Diversified businesses
Current-year operations.................................................................. .08 .11 (.09)
Cumulative effect of change in the method of accounting for income taxes (see Note 1).... -- -- .16
--------- --------- ---------
Total diversified businesses............................................................. .08 .11 .07
--------- --------- ---------
Total...................................................................................... $ 1.85 $ 1.63 $ 1.67
--------- --------- ---------
--------- --------- ---------
EARNINGS APPLICABLE TO COMMON STOCK
Earnings applicable to common stock increased $45.9 million in 1993 and
$11.4 million in 1992. The 1993 increase reflects higher utility earnings,
slightly offset by lower earnings of diversified businesses. The 1992 increase
reflects increases in both utility and diversified businesses earnings.
Utility earnings increased in 1993 because BGE sold more electricity than in
the previous year and because of increased base rates. Three principal factors
produced the increase in sales of electricity: the summer of 1993 was hotter
than 1992; commercial customers used more electricity; and the number of
residential customers increased. The effect of weather on utility sales is
discussed below. The 1993 earnings increases were partially offset by higher
operations and maintenance expenses, depreciation expense, and property taxes,
and the effect of the Omnibus Budget Reconciliation Act of 1993 (1993 Tax Act),
which increased the federal corporate income tax rate to 35% from 34%. Utility
earnings increased in 1992 over 1991 because the colder winter in 1992 led to
higher electric and gas sales. Operations expenses and interest charges were
also lower in 1992, while other income was higher. However, the summer of 1992
was cooler than 1991, and as a result lower electric sales offset a substantial
portion of the increase in 1992 utility earnings.
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 base rate increases authorized by the PSC in April 1993
will affect 1994 utility earnings favorably. Several electric fuel rate cases
now pending before the PSC discussed in Notes 1 and 13 could also affect future
years' earnings. During 1993 and 1992, unfavorable economic conditions
diminished electric and gas sales growth in BGE's service territory. Electric
utilities presently face competition in the construction of generating units to
meet future load growth and in the sale of electricity in the bulk power
markets. Electric utilities also face the future prospect of competition for
electric sales to retail customers. It is not possible to predict currently the
ultimate effect competition will have on BGE's earnings in future years.
Earnings from diversified businesses, which primarily represent the
operations of Constellation Holdings, Inc. and its subsidiaries (collectively,
the Constellation Companies), decreased during 1993 and increased during 1992.
The reasons for these changes are discussed in the "Diversified Businesses
Earnings" section on pages 26 and 27.
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 temperature and the baseline temperature of 65 degrees. 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. Colder weather during the winter, as
measured by greater heating degree days, results in greater demand for
electricity and gas to operate heating systems.
21
Conversely, warmer weather during the winter, measured by fewer heating degree
days, results in less demand for electricity and gas to operate heating systems.
The degree-days chart below presents information regarding cooling and heating
degree days.
30-YEAR
1993 1992 AVERAGE
------------ ------------ -----------
Cooling degree days.................................................................. 865 707 804
Percentage change compared to prior year............................................. 22.3 % (31.1)%
Heating degree days.................................................................. 4,959 4,975 4,901
Percentage change compared to prior year............................................. (0.3)% 14.6 %
BGE UTILITY REVENUES AND SALES
Electric revenues changed during 1993 and 1992 because of the following
factors:
1993 1992
--------- ---------
(IN MILLIONS)
System sales volumes............................................................................. $ 112.4 $ (32.0)
Base rates....................................................................................... 58.5 84.9
Fuel rates....................................................................................... (55.0) (113.8)
--------- ---------
Revenues from system sales....................................................................... 115.9 (60.9)
Interchange sales................................................................................ 27.2 40.5
Other revenues................................................................................... 4.1 (6.2)
--------- ---------
Total electric revenues.......................................................................... $ 147.2 $ (26.6)
--------- ---------
--------- ---------
Electric system sales represent volumes sold to customers within BGE's
service territory at rates determined by the PSC. These amounts exclude
interchange sales, discussed separately later. In 1993, BGE changed its
classification of commercial and industrial customers to present this
information on a basis which is more consistent with predominant industry
practices. Prior-year amounts have been reclassified to conform to the current
year's presentation. Below is a comparison of the changes in electric system
sales volumes.
1993 1992
----------- ------------
Residential.......................................................................................... 9.0% (3.6)%
Commercial........................................................................................... 4.1 1.7
Industrial........................................................................................... 2.7 (1.2)
Total................................................................................................ 5.8 (0.8)
Hotter summer weather was the main reason for the increase in total sales
for 1993. The sales increases to residential and commercial customers reflect
significantly hotter summer weather, and to a lesser extent, increased usage and
customer growth. Sales to industrial customers reflect increased sales of
electricity to Bethlehem Steel to support its increased steel production during
1993. Sales to the residential customers decreased in 1992 because of cooler
weather in the summer of 1992. This decrease was partially offset by higher
sales because of colder winter weather in 1992 and growth in the total number of
customers. Improved economic conditions among commercial customers in 1992
increased sales compared to 1991. Sales to industrial customers in 1992 reflect
the negative effect of economic conditions on this segment despite higher sales
of electricity to Bethlehem Steel after the start-up of its newly modernized hot
strip mill.
Base rates increased in 1993 for two principal reasons: the PSC's April 1993
rate order and an increased recovery of eligible electric conservation program
costs through the energy conservation surcharge. The April 1993 rate order for
an annualized electric base rate increase of $84.9 million provided for a higher
level of operating expenses and a return on BGE's higher level of electric rate
base. The order also reduced the authorized rate of return to 9.40% from the
previous rate of 9.94%. Base rates increased in 1992 for similar reasons: the
PSC's December 1990 rate order and, to a lesser extent, the recovery of eligible
electric conservation program costs through the energy conservation surcharge,
which began in July 1992. The December 1990 rate order authorized a $124 million
base rate increase to provide rate recognition for BGE's investment and
operating expenses at Brandon Shores Unit 2, effective with that Unit's initial
commercial operation in May 1991. The order further authorized a $53 million
surcharge to base rates in October 1991 to recover certain purchased capacity
charges. Although these base rate increases improved BGE's electric revenues
during 1992, they had little effect on net income because they were essentially
offset by two things: a decrease in the allowance for funds used during
construction (AFC) and higher depreciation expense and other taxes because of
the completion and commercial operation of Brandon Shores Unit 2; and increased
purchased capacity charges.
The April 1993 rate order and a continued higher level of recovery of
electric conservation program costs under the energy conservation surcharge will
favorably affect base rate revenues in 1994. However, if the PSC determines that
BGE is earning in excess of its authorized rate of return, BGE will have to
refund a portion of
22
energy conservation surcharge revenues to its customers. The portion subject to
refund is compensation for foregone sales from conservation programs and
incentives for achieving conservation goals. BGE has been earning in excess of
its authorized rate of return on electric operations since September 30, 1993.
As a result, BGE has deferred the portion of electric energy conservation
revenues subject to refund beginning in December 1993. The deferral of these
billings is expected to average approximately $1.7 million each month these
deferrals continue in 1994. The deferral will continue as long as BGE exceeds
its authorized rate of return on electric operations, as determined by the PSC.
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 (see Notes 1 and 13). Changes in
fuel rate revenues and interchange 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 13.
Fuel rate revenues decreased during both 1993 and 1992 due to a lower fuel
rate. The rate was lower in both years because of a less costly twenty-four
month generation mix from greater generation at the Calvert Cliffs Nuclear Power
Plant compared to the year before. The 1993 decrease was partially offset by
increased electric system sales volumes. The 1992 decrease also reflects $58
million of annual fuel cost savings resulting from the commercial operation of
Brandon Shores Unit 2 and the October 1991 expiration of a surcharge to the
electric fuel rate. BGE expects electric fuel rate revenues to decrease again in
1994 because of a continued less-costly generation mix.
Interchange sales are sales of BGE's energy to the Pennsylvania-New
Jersey-Maryland Interconnection (PJM), a regional power pool of eight member
companies including BGE. Interchange sales occur after BGE has satisfied the
demand for system sales of electricity, if BGE's available generation is the
least costly available to PJM utilities. Interchange sales increased during 1993
and 1992 because BGE had a less costly generation mix than other PJM utilities.
The less costly mix during 1993 reflects the higher generation levels at the
Calvert Cliffs Nuclear Power Plant. The less costly mix during 1992 also
reflects the operation of the Calvert Cliffs Nuclear Power Plant and a full year
of operation of Brandon Shores Unit 2.
Gas revenues increased during 1993 and 1992 because of the following
factors:
1993 1992
--------- ---------
(IN MILLIONS)
Sales volumes........................................................................................ $ 0.6 $ 8.6
Base rates........................................................................................... 2.6 3.3
Gas cost adjustment revenues......................................................................... 28.8 32.9
Other revenues....................................................................................... 0.9 (0.1)
--------- ---------
Total gas revenues................................................................................... $ 32.9 $ 44.7
--------- ---------
--------- ---------
In 1993, BGE changed its classification of commercial and industrial
customers to present this information on a basis which is more consistent with
predominant industry practices. Prior-year amounts have been reclassified to
conform to the current year's presentation. The changes in gas sales volumes
compared to the year before were:
1993 1992
----------- -----------
Residential......................................................................................... 2.5% 6.9%
Commercial.......................................................................................... 2.2 12.8
Industrial.......................................................................................... (5.8) 2.9
Total............................................................................................... (0.6) 7.0
Total gas sales decreased during 1993 because of lower sales to industrial
customers, partially offset by increased sales to the remainder of the
gas-system customers. Sales to industrial customers decreased primarily because
of lower use of delivery service gas by Bethlehem Steel and interruptible
service customers, who increased their use of alternative fuels. Gas sales to
Bethlehem Steel also decreased because of a maintenance outage at its L-Blast
furnace. The increases in sales to residential and commercial customers reflect
the colder winter weather during the first quarter of 1993 and an increase in
the number of customers. Sales to residential and commercial customers during
1992 reflect the colder winter of 1992 and growth in the number of customers.
Gas sales to industrial customers for 1992 reflect primarily increased sales
volumes to Bethlehem Steel because of higher use of gas in its production and
processing.
Base rates increased in 1993 for two principal reasons: the PSC's April 1993
rate order and an increased recovery of eligible gas conservation program costs
through the energy conservation surcharge. The April 1993 rate order for an
annualized gas base rate increase of $1.6 million provided for a higher level of
operating expenses and a return on BGE's higher level of gas rate base. The
increased base rates during 1992 represent the
23
effects of the PSC's October 1991 rate order. That order authorized a $4 million
annualized increase in gas base rate revenues. The April 1993 gas base rate
order and continued recovery of gas conservation program costs under the energy
conservation surcharge will favorably affect base rate revenues in 1994.
Changes in gas cost adjustment revenues result from the operation of the
purchased gas adjustment (PGA) clause, which is designed to recover actual gas
costs incurred (See Note 1). Changes in gas cost adjustment revenues normally do
not affect earnings. Gas cost adjustment revenues increased during both years
primarily because of increased prices to recover higher costs of purchased gas
and higher sales volumes subject to the PGA clause. Delivery service sales
volumes are not subject to the PGA clause because these customers purchase their
gas directly from third parties.
BGE UTILITY FUEL AND ENERGY EXPENSES
Electric fuel and purchased energy expenses were as follows:
1993 1992 1991
--------- --------- ---------
(IN MILLIONS)
Actual costs........................................................................... $ 483.9 $ 445.2 $ 492.6
Net recovery of costs under electric fuel rate clause (see Note 1)..................... 50.7 111.0 105.6
--------- --------- ---------
Total expense.......................................................................... $ 534.6 $ 556.2 $ 598.2
--------- --------- ---------
--------- --------- ---------
Actual electric fuel and purchased energy costs during 1993 increased for
two principal reasons: a higher net output of electricity generated to meet the
demand of BGE's system and the PJM system, and higher purchased capacity costs
under the Pennsylvania Power & Light Company Energy and Capacity Purchase
Agreement. Actual electric fuel and purchased energy costs decreased during 1992
because of a less costly generation mix. The cost of the generation mix
decreased because of the Calvert Cliffs Nuclear Power Plant's return to
operation following the completion of extended maintenance and repair outages
and the May 1991 commercial operation of Brandon Shores Unit 2. This decrease
was partially offset by purchased capacity charges beginning in October 1991
under the Pennsylvania Power & Light Company Energy and Capacity Purchase
Agreement. Purchased gas expenses were as follows:
1993 1992 1991
--------- --------- ---------
(IN MILLIONS)
Actual costs........................................................................... $ 246.4 $ 213.6 $ 185.1
Net (deferral) recovery of costs under purchased gas adjustment clause (see Note 1).... (3.7) 0.5 (3.6)
--------- --------- ---------
Total expense.......................................................................... $ 242.7 $ 214.1 $ 181.5
--------- --------- ---------
--------- --------- ---------
Actual purchased gas costs went up in both 1993 and 1992 for three principal
reasons: higher gas prices caused by market conditions; higher reservation
charges; and higher output to meet greater demand for BGE gas. Purchased gas
costs exclude gas purchased by delivery service customers, including Bethlehem
Steel, who obtain gas directly from third parties. Future purchased gas costs
are expected to increase due to transition costs incurred by BGE gas pipeline
suppliers in implementing Federal Energy Regulatory Commission (FERC) Order No.
636. These transition costs, if approved by FERC, will be passed on to BGE
customers through the purchased gas adjustment clause.
OTHER OPERATING EXPENSES
Operations expense increased during 1993 by $50.6 million. The combined
effect of higher labor costs, employee reduction expenses (discussed below),
amortization of energy conservation program costs, postretirement benefit
expenses resulting from the implementation of Statement of Financial Accounting
Standards No. 106 (see Note 6), and nuclear operating costs was in total $70.2
million higher compared to 1992. These increases were partially offset by the
1993 reversal of a $9.8 million charge originally recorded in 1992 for
termination benefits associated with the Company's 1992 Voluntary Special Early
Retirement Program (1992 VSERP) to reflect the ratemaking treatment adopted by
the PSC in its April 1993 rate order. In accordance with that order, the Company
has deferred this charge and is amortizing it over a five-year period, beginning
in May 1993. Operations expense decreased in 1992 because of lower nuclear
contractor costs and lower payroll costs attributable to labor savings from the
Company's 1992 VSERP and other cost-control measures. These decreased costs were
partially offset by the original charge to operations for the $9.8 million cost
of termination benefits associated with the 1992 VSERP and by higher
fringe-benefit costs.
The Company announced several employee reduction programs during the third
quarter of 1993 in conjunction with its ongoing cost control efforts. The cost
of these programs totaled $105.5 million (see Note 7). Consistent with previous
rate actions of the PSC, BGE has deferred and will amortize the $88.3 million of
1993 Voluntary Special Early Retirement Program (1993 VSERP) costs related to
regulated activities over a five-year
24
period beginning in February 1994 . The remaining $17.2 million of these program
costs was charged to expense in 1993. Operations expense is expected to be
reduced in 1994 by three factors: cost savings from the 1993 employee reduction
programs are expected to be realized beginning in 1994; 1993 operations expense
reflects the portion of the cost of employee reduction programs charged to
expense; and the expected reduction in 1994 operations expense resulting from
the sale of a significant portion of the Constellation Companies' investment in
senior living facilities (see page 26 for a discussion of the sale of senior
living facilities). These decreases will be partially offset by the amortization
of the deferred VSERP costs and other increases in operations expenses.
Maintenance expense increased in 1993 because of higher labor costs and
higher costs at the Calvert Cliffs Nuclear Power Plant. Maintenance expense was
essentially unchanged in 1992 because lower costs at certain fossil-fuel
electric generating plants were offset by higher costs at Calvert Cliffs.
Depreciation expense increased during 1993 and 1992 compared to the year
before because of higher depreciable plant in service. The increase during 1993
resulted from the addition of electric transmission and distribution plant and
certain capital additions at the Calvert Cliffs Nuclear Power Plant. The 1992
increase resulted from the addition of Brandon Shores Unit 2, which began
commercial operation in May 1991.
Taxes other than income taxes increased during both years because of higher
property taxes from the addition of Brandon Shores Unit 2 to the taxable base
effective July 1, 1992. The increase during 1993 also reflects higher franchise
taxes because of the increase in total electric and gas revenues and increased
payroll taxes.
Inflation affects the Company through increased operating expenses and
higher replacement costs for utility plant assets. Although timely rate
increases can lessen the effects of inflation, the regulatory process imposes a
time lag which can delay BGE's recovery of increased costs. There is a
regulatory lag primarily because rate increases are based on historical costs
rather than projected costs. The PSC has historically allowed recovery of the
cost of replacing plant assets, together with the opportunity to earn a fair
return on BGE's investment, beginning at the time of replacement.
OTHER INCOME AND EXPENSES
AFC was essentially unchanged in 1993 because the accrual of AFC on a higher
level of construction work in progress compared to 1992 was offset by the lower
AFC rate approved in the April 1993 PSC rate order. AFC decreased during 1992
because of the completion and commercial operation of Brandon Shores Unit 2,
partially offset by the effects of the expansion of the AFC policy as discussed
in Note 1.
Interest charges increased slightly in 1993 as a higher level of outstanding
debt was partially offset by a decline in the level of interest rates and the
redemption of higher coupon debt of BGE. Interest charges decreased during 1992
primarily because of lower levels of debt outstanding and a decline in the level
of interest rates. The decreased debt levels in 1992 are attributable to the
additional shares of common stock issued and the recovery of previously deferred
electric fuel costs.
Capitalized interest increased during 1993 because BGE began accruing
carrying charges on electric deferred fuel costs excluded from rate base (see
Note 5). 1992 capitalized interest decreased because the Constellation Companies
discontinued interest capitalization at certain real estate projects.
Income tax expense increased during both years because of higher pre-tax
earnings. The 1993 increase also reflects the effect of the 1993 Tax Act, which
increased the federal corporate income tax rate to 35% from 34%, retroactive to
January 1, 1993. As a result, income tax expense related to 1993 operations
increased by $4.6 million, and the Company's deferred income tax liability
increased by $20.1 million. The Company deferred $12.8 million of the increase
in the deferred income tax liability applicable to utility operations for
recovery through future rates and charged the remaining $7.3 million to income
tax expense. Of this $7.3 million charged to expense, $5.8 million pertains to
the Constellation Companies as discussed on page 27.
25
DIVERSIFIED BUSINESSES EARNINGS
Earnings per share from diversified businesses were:
1993 1992 1991
--------- --------- ---------
Power generation systems..................................................................... $ .07 $ .08 $ .03
Financial investments........................................................................ .10 .09 .01
Real estate development and senior living facilities......................................... (.04) (.05) (.11)
Effect of 1993 Tax Act....................................................................... (.04) -- --
Other........................................................................................ (.01) (.01) (.02)
--------- --------- ---------
Current-year operations...................................................................... .08 .11 (.09)
Cumulative effect of change in the method of accounting for income taxes (see Note 1)........ -- -- .16
--------- --------- ---------
Total diversified businesses................................................................. $ .08 $ .11 $ .07
--------- --------- ---------
--------- --------- ---------
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 during 1993 were flat
compared to 1992. The recognition of $8 million of energy tax credits on the
commercial operation of the Puna geothermal plant was offset by costs incurred
at the Panther Creek waste-coal project in order to resolve fuel quality and
other start-up problems. Additionally, 1992 earnings reflect the gain on the
partial sale of an ownership interest in a power generation project,
representing most of the increase in power generation systems earnings compared
to 1991.
The Constellation Companies' investment in wholesale power generating
projects includes $163 million representing ownership interests in 16 projects
which sell electricity in California under Interim Standard Offer No. 4 power
purchase agreements. Under these agreements, the projects supply electricity to
purchasing utilities at a fixed energy rate for the first ten years of the
agreements and at 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 after these agreements were signed, 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. If
current avoided cost levels were to continue into 1996 and beyond, the
Constellation Companies could experience reduced earnings or incur losses
associated with these projects, which could be significant. The Constellation
Companies are investigating alternatives for certain of these power generation
projects including, but not limited to, repowering the projects to reduce
operating costs, renegotiating the power purchase agreements, and selling their
ownership interests in the projects. The Company cannot predict the impact these
matters 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.
1993 financial investment earnings increased slightly over 1992. $6.1 million in
income from an investment in a financial guaranty insurance company was
substantially offset by lower investment income compared to 1992, resulting from
the decline in the size of the investment portfolio due to the sale of selected
assets to provide liquidity for ongoing businesses of the Constellation
Companies. Financial investment earnings increased in 1992 primarily because of
write-downs taken on certain investments in 1991 and because of an improvement
in the performance of certain financial limited partnerships.
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 depressed real estate market and economic conditions, resulting
in reduced demand for the purchase or lease of available land, office, and
retail space.
Earnings from real estate development and senior living facilities were
essentially unchanged in 1993 compared to 1992 because a $2.1 million gain on
the sale of the nursing home portion of the Constellation Companies' investment
in senior living facilities was offset by greater operating losses at other real
estate projects. The senior living facilities which were sold contributed real
estate revenues and operating expenses of approximately $17 million and $16
million, respectively, in 1993. The increase in earnings in 1992 reflects the
1991 write-downs recorded by the Constellation Companies aggregating $10 million
on certain real estate
26
projects and a $3.6 million reserve for loans where the value of the collateral
was less than the outstanding loan balances. Additionally, the Constellation
Companies' real estate portfolio has experienced continuing carrying costs and
depreciation and, during 1991, the Constellation Companies began expensing
rather than capitalizing interest on certain undeveloped land where development
activities were at minimal levels. These factors have affected earnings
negatively during 1993 and 1992 and are expected to continue to do so until
current market conditions improve. Cash flow from real estate operations has
been insufficient to cover the debt service requirements of certain of 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. Until the real estate market shows sustained improvement,
earnings from real estate activities are expected to remain depressed.
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 is beginning to show signs of
improvement, 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 until
market conditions improve 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 Effect of the 1993 Tax Act represents a $5.8 million charge to income
tax expense to reflect the increase in the Constellation Companies' deferred
income tax liability because of the increase in the federal corporate tax rate.
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 Note 13 and in Item 1. Business -- Environmental
Matters.
LIQUIDITY AND CAPITAL RESOURCES
CAPITAL REQUIREMENTS
The Company's capital requirements reflect the capital-intensive nature of
the utility business. Actual capital requirements for the years 1991 through
1993, along with estimated amounts for the years 1994 through 1996, are
reflected below.
1991 1992 1993 1994 1995 1996
--------- --------- --------- --------- --------- ---------
(IN MILLIONS)
Utility Business:
Construction expenditures (excluding AFC)
Electric................................................ $ 328 $ 292 $ 360 $ 345 $ 319 $ 300
Gas..................................................... 43 36 51 54 60 56
Common.................................................. 48 39 44 51 46 44
--------- --------- --------- --------- --------- ---------
Total construction expenditures......................... 419 367 455 450 425 400
AFC....................................................... 37 22 23 34 35 25
Deferred nuclear expenditures............................. 23 16 14 12 -- --
Deferred energy conservation expenditures................. 3 20 33 48 45 40
Nuclear fuel (uranium purchases and processing charges)... 2 40 47 42 46 51
Retirement of long-term debt and redemption of preference
stock.................................................... 339 486 907 36 281 98
--------- --------- --------- --------- --------- ---------
Total utility business.................................... 823 951 1,479 622 832 614
--------- --------- --------- --------- --------- ---------
Diversified Businesses:
Retirement of long-term debt.............................. 167 118 222 9 81 77
Investment requirements................................... 109 80 78 63 60 20
--------- --------- --------- --------- --------- ---------
Total diversified businesses.............................. 276 198 300 72 141 97
--------- --------- --------- --------- --------- ---------
Total....................................................... $ 1,099 $ 1,149 $ 1,779 $ 694 $ 973 $ 711
--------- --------- --------- --------- --------- ---------
--------- --------- --------- --------- --------- ---------
27
BGE UTILITY CAPITAL REQUIREMENTS
BGE's construction program is subject to continuous review and modification,
and actual expenditures may vary from the estimates on page 27. Electric
construction expenditures include the installation of two 5,000 kilowatt diesel
generators at the Calvert Cliffs Nuclear Power Plant, scheduled to be placed in
service in 1995; the construction of a 140-megawatt combustion turbine at
Perryman, scheduled to be placed in service in 1995, which the PSC authorized in
an order dated March 25, 1993; and improvements in BGE's existing generating
plants and its transmission and distribution facilities. Future electric
construction expenditures do not include additional generating units in light of
the competitive bidding process established by the PSC. The Company estimates
currently that expenditures for compliance with the sulfur dioxide provisions of
the Clean Air Act of 1990 will total approximately $55 million through 1995.
During 1993, 1992, and 1991, the internal generation of cash from utility
operations provided 71%, 81%, and 74% respectively, of the funds required for
BGE's capital requirements exclusive of retirements and redemptions of debt and
preference stock. During the three-year period 1994 through 1996, BGE expects to
provide through utility operations approximately 70% of the funds required for
BGE's capital requirements, exclusive of retirements and redemptions.
Utility capital requirements not met through the internal generation of cash
are met through the issuance of debt and equity securities. During the
three-year period ended December 31, 1993, BGE's issuances of long-term debt,
preference stock, and common stock were $1,733 million, $165 million, and $446
million, respectively. During the same period, retirements and redemptions of
BGE's long-term debt and preference stock totaled $1,546 million and $167
million, respectively, exclusive of any redemption premiums. The increase in
issuances and retirements of long-term debt during 1993 reflects the refinancing
of a significant portion of BGE's debt in order to take advantage of the
favorable interest rate market. The amount and timing of future issuances and
redemptions will depend upon market conditions and BGE's actual capital
requirements.
The Constellation Companies' capital requirements are discussed below in the
section titled "Diversified Businesses Capital Requirements -- Debt and
Liquidity." 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 Constellation Holdings, Inc.
DIVERSIFIED BUSINESSES CAPITAL REQUIREMENTS
DEBT AND LIQUIDITY. During 1993, Constellation Holdings, Inc. (CHI) closed
two private placements totaling $225 million of unsecured serial notes with
several institutional investors. CHI used proceeds of the private placements to
pay off its bank debt facility, which CHI elected to terminate, as well as for
other general corporate uses. In addition, CHI entered into a $20 million
unsecured revolving credit facility with a bank on September 30, 1993. This
facility matures September 29, 1994 and will be used to provide liquidity for
general corporate purposes. As of December 31, 1993, CHI had no borrowings under
this facility.
The Constellation Companies intend to meet capital requirements by
refinancing debt as it comes due and through internally generated cash. These
sources include cash that may be generated from operations, the sale of assets,
and cash 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 page 26 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 may enter into additional credit facilities.
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 1994 through 1996 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 27 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 banks and institutional lenders.
28
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT AUDITORS
To the Shareholders of
Baltimore Gas and Electric Company
We have audited the accompanying consolidated balance sheets and statements
of capitalization of Baltimore Gas and Electric Company and Subsidiaries at
December 31, 1993 and 1992, and the related consolidated statements of income,
cash flows, common shareholders' equity, and income taxes for each of the three
years in the period ended December 31, 1993, and the consolidated financial
statement schedules listed in Item 14(a)(1) and (2) of this Form 10-K. These
financial statements and financial statement schedules are the responsibility of
the Company's Management. Our responsibility is to express an opinion on these
financial statements and financial statement schedules based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and 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
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
Management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Baltimore Gas
and Electric Company and Subsidiaries at December 31, 1993 and 1992, and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 1993 in conformity with generally
accepted accounting principles. In addition, the consolidated financial
schedules referred to above, when considered in relation to the basic
consolidated financial statements taken as a whole, present fairly, in all
material respects, the information required to be included therein.
As discussed in Note 13 to the consolidated financial statements, the Public
Service Commission of Maryland is currently reviewing the replacement energy
costs resulting from the outages at the Company's nuclear power plant and the
Company provided a reserve of $35 million in 1990 for the possible disallowance
of replacement energy costs. The ultimate outcome of the fuel rate proceedings,
however, cannot be determined but may result in a disallowance in excess of the
reserve provided.
As discussed in Note 1 to the consolidated financial statements, the Company
changed its method of accounting for income taxes in 1991.
We have also previously audited, in accordance with generally accepted
standards, the balance sheets and statements of capitalization at December 31,
1991, 1990 and 1989, and the related statements of income, retained earnings,
changes in financial position, and income taxes for each of the two years in the
period ended December 31, 1990 (none of which are presented herein); and we
expressed unqualified opinions on those financial statements. In our opinion,
the information set forth in the Summary of Operations included in the Selected
Financial Data for each of the five years in the period ended December 31, 1993,
appearing on page 20 is fairly stated in all material respects in relation to
the financial statements from which it has been derived.
/s/ Coopers & Lybrand
--------------------------------------
COOPERS & LYBRAND
Baltimore, Maryland
January 21, 1994
29
CONSOLIDATED STATEMENTS OF INCOME
YEAR ENDED DECEMBER 31,
-------------------------------------------
1993 1992 1991
------------- ------------- -------------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
Revenues
Electric......................................................................... $ 2,115,155 $ 1,967,923 $ 1,994,525
Gas.............................................................................. 435,849 402,937 358,195
Diversified businesses........................................................... 117,710 120,483 96,133
------------- ------------- -------------
Total revenues................................................................... 2,668,714 2,491,343 2,448,853
------------- ------------- -------------
Expenses Other Than Interest and Income Taxes
Electric fuel and purchased energy............................................... 534,628 556,184 598,208
Gas purchased for resale......................................................... 242,685 214,103 181,455
Operations....................................................................... 657,110 606,498 634,309
Maintenance...................................................................... 181,685 172,726 173,648
Depreciation..................................................................... 236,774 223,483 201,264
Taxes other than income taxes.................................................... 194,832 183,004 170,781
------------- ------------- -------------
Total expenses other than interest and income taxes.............................. 2,047,714 1,955,998 1,959,665
------------- ------------- -------------
Income from Operations............................................................. 621,000 535,345 489,188
------------- ------------- -------------
Other Income
Allowance for equity funds used during construction.............................. 14,492 13,892 23,596
Equity in earnings of Safe Harbor Water Power Corporation........................ 4,243 4,267 4,388
Net other income and deductions.................................................. (3,033) 3,937 (1,356)
------------- ------------- -------------
Total other income............................................................... 15,702 22,096 26,628
------------- ------------- -------------
Income Before Interest and Income Taxes............................................ 636,702 557,441 515,816
------------- ------------- -------------
Interest Expense
Interest charges................................................................. 212,971 211,712 231,411
Capitalized interest............................................................. (16,167) (13,800) (20,953)
Allowance for borrowed funds used during construction............................ (8,040) (8,165) (13,870)
------------- ------------- -------------
Net interest expense............................................................. 188,764 189,747 196,588
------------- ------------- -------------
Income Before Income Taxes......................................................... 447,938 367,694 319,228
Income Taxes....................................................................... 138,072 103,347 85,547
------------- ------------- -------------
Income Before Cumulative Effect of Change in Accounting Method..................... 309,866 264,347 233,681
Cumulative Effect of Change in the Method of Accounting for Income Taxes (See Note
1)................................................................................ -- -- 19,745
------------- ------------- -------------
Net Income......................................................................... 309,866 264,347 253,426
Preferred and Preference Stock Dividends........................................... 41,839 42,247 42,746
------------- ------------- -------------
Earnings Applicable to Common Stock................................................ $ 268,027 $ 222,100 $ 210,680
------------- ------------- -------------
------------- ------------- -------------
Average Shares of Common Stock Outstanding......................................... 145,072 136,248 126,093
Earnings Per Share of Common Stock
Before cumulative effect of change in accounting method.......................... $ 1.85 $ 1.63 $ 1.51
Cumulative effect of change in the method of accounting for income taxes......... -- -- .16
------------- ------------- -------------
Total earnings per share of common stock......................................... $ 1.85 $ 1.63 $ 1.67
------------- ------------- -------------
------------- ------------- -------------
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been restated to conform to the current year's
presentation.
30
CONSOLIDATED BALANCE SHEETS
AT DECEMBER 31,
----------------------------
1993 1992
------------- -------------
(IN THOUSANDS)
ASSETS
Current Assets
Cash and cash equivalents...................................................................... $ 84,236 $ 27,122
Accounts receivable (net of allowance for uncollectibles)...................................... 401,853 369,144
Fuel stocks.................................................................................... 70,233 85,063
Materials and supplies......................................................................... 145,130 141,611
Prepaid taxes other than income taxes.......................................................... 54,237 54,510
Other.......................................................................................... 38,971 29,604
------------- -------------
Total current assets........................................................................... 794,660 707,054
------------- -------------
Investments and Other Assets
Real estate projects........................................................................... 487,397 462,042
Power generation systems....................................................................... 298,514 259,996
Financial investments.......................................................................... 213,315 207,011
Nuclear decommissioning trust fund............................................................. 56,207 43,118
Safe Harbor Water Power Corporation............................................................ 34,138 34,176
Senior living facilities....................................................................... 2,005 24,538
Other.......................................................................................... 65,355 64,986
------------- -------------
Total investments and other assets............................................................. 1,156,931 1,095,867
------------- -------------
Utility Plant
Plant in service
Electric..................................................................................... 5,713,259 5,474,590
Gas.......................................................................................... 557,942 526,058
Common....................................................................................... 487,740 468,264
------------- -------------
Total plant in service....................................................................... 6,758,941 6,468,912
Accumulated depreciation....................................................................... (2,161,984) (1,980,361)
------------- -------------
Net plant in service........................................................................... 4,596,957 4,488,551
Construction work in progress.................................................................. 436,440 308,908
Nuclear fuel (net of amortization)............................................................. 139,424 147,374
Plant held for future use...................................................................... 24,066 21,486
------------- -------------
Net utility plant.............................................................................. 5,196,887 4,966,319
------------- -------------
Deferred Charges
Regulatory assets.............................................................................. 768,125 568,563
Other.......................................................................................... 70,436 36,554
------------- -------------
Total deferred charges......................................................................... 838,561 605,117
------------- -------------
Total Assets..................................................................................... $ 7,987,039 $ 7,374,357
------------- -------------
------------- -------------
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been restated to conform to the current year's
presentation.
31
CONSOLIDATED BALANCE SHEETS
AT DECEMBER 31,
----------------------------
1993 1992
------------- -------------
(IN THOUSANDS)
LIABILITIES AND CAPITALIZATION
Current Liabilities
Short-term borrowings.......................................................................... $ -- $ 11,900
Current portions of long-term debt and preference stock........................................ 44,516 291,270
Accounts payable............................................................................... 195,534 175,495
Customer deposits.............................................................................. 22,345 20,027
Accrued taxes.................................................................................. 20,623 20,925
Accrued interest............................................................................... 58,541 55,537
Dividends declared............................................................................. 63,966 62,282
Accrued vacation costs......................................................................... 35,546 28,908
Other.......................................................................................... 38,716 2,567
------------- -------------
Total current liabilities...................................................................... 479,787 668,911
------------- -------------
Deferred Credits and Other Liabilities
Deferred income taxes.......................................................................... 1,067,611 983,534
Deferred investment tax credits................................................................ 157,426 165,697
Pension and postemployment benefits............................................................ 183,043 5,352
Decommissioning of federal uranium enrichment facilities....................................... 46,858 55,000
Other.......................................................................................... 56,974 19,589
------------- -------------
Total deferred credits and other liabilities................................................... 1,511,912 1,229,172
------------- -------------
Capitalization
Long-term debt................................................................................. 2,823,144 2,376,950
Preferred stock................................................................................ 59,185 59,185
Redeemable preference stock.................................................................... 342,500 395,500
Preference stock not subject to mandatory redemption........................................... 150,000 110,000
Common shareholders' equity.................................................................... 2,620,511 2,534,639
------------- -------------
Total capitalization........................................................................... 5,995,340 5,476,274
------------- -------------
Commitments, Guarantees, and Contingencies See Note 13
Total Liabilities and Capitalization............................................................. $ 7,987,039 $ 7,374,357
------------- -------------
------------- -------------
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been restated to conform to the current year's
presentation.
32
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31,
-------------------------------------------
1993 1992 1991
-------------- ------------ -------------
(IN THOUSANDS)
Cash Flows From Operating Activities
Net income....................................................................... $ 309,866 $ 264,347 $ 253,426
Adjustments to reconcile to net cash provided by operating activities:
Cumulative effect of change in the method of accounting for income taxes....... -- -- (19,745)
Depreciation and amortization.................................................. 314,027 273,549 244,017
Deferred income taxes.......................................................... 53,057 26,914 30,725
Investment tax credit adjustments.............................................. (8,444) (8,854) (6,225)
Deferred fuel costs............................................................ 51,445 105,430 102,754
Write-down of financial investments and real estate projects................... -- -- 23,563
Allowance for equity funds used during construction............................ (14,492) (13,892) (23,596)
Equity in earnings of affiliates and joint ventures (net)...................... (4,655) (11,525) 8,707
Changes in current assets...................................................... (37,252) (26,206) (6,563)
Changes in current liabilities, other than short-term borrowings............... 71,153 (9,614) (6,027)
Other.......................................................................... (31,919) (31,005) (5,373)
-------------- ------------ -------------
Net cash provided by operating activities...................................... 702,786 569,144 595,663
-------------- ------------ -------------
Cash Flows From Financing Activities
Proceeds from issuance of:
Short-term borrowings (net).................................................... (11,900) (139,600) (15,530)
Long-term debt................................................................. 1,206,350 603,400 1,015,950
Preference stock............................................................... 128,776 -- 34,801
Common stock................................................................... 57,379 355,759 32,263
Reacquisition of long-term debt.................................................. (1,012,514) (687,052) (959,379)
Redemption of preference stock................................................... (144,310) (2,924) (22,800)
Common stock dividends paid...................................................... (211,137) (189,180) (176,007)
Preferred and preference stock dividends paid.................................... (42,425) (42,300) (42,743)
Other............................................................................ (7,094) (399) (442)
-------------- ------------ -------------
Net cash used in financing activities............................................ (36,875) (102,296) (133,887)
-------------- ------------ -------------
Cash Flows From Investing Activities
Utility construction expenditures................................................ (477,878) (389,416) (456,244)
Allowance for equity funds used during construction.............................. 14,492 13,892 23,596
Nuclear fuel expenditures........................................................ (47,329) (39,486) (1,854)
Deferred nuclear expenditures.................................................... (13,791) (15,809) (22,681)
Deferred energy conservation expenditures........................................ (32,909) (19,918) (3,489)
Nuclear decommissioning trust fund............................................... (9,699) (8,900) (8,900)
Financial investments............................................................ 6,523 52,616 67,282
Real estate projects............................................................. (30,330) (23,385) (45,322)
Power generation systems......................................................... (26,841) (31,483) (33,204)
Other............................................................................ 8,965 4,746 (3,422)
-------------- ------------ -------------
Net cash used in investing activities............................................ (608,797) (457,143) (484,238)
-------------- ------------ -------------
Net Increase (Decrease) in Cash and Cash Equivalents............................... 57,114 9,705 (22,462)
Cash and Cash Equivalents at Beginning of Year..................................... 27,122 17,417 39,879
-------------- ------------ -------------
Cash and Cash Equivalents at End of Year........................................... $ 84,236 $ 27,122 $ 17,417
-------------- ------------ -------------
-------------- ------------ -------------
Other Cash Flow Information
Cash paid during the year for:
Interest (net of amounts capitalized).......................................... $ 183,266 $ 183,209 $ 189,271
Income taxes................................................................... $ 126,034 $ 87,693 $ 16,078
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been restated to conform to the current year's
presentation.
33
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY
YEARS ENDED DECEMBER 31, 1993, 1992, AND 1991
------------------------------------------------------------------
NET
UNREALIZED
COMMON STOCK PENSION LOSS ON
------------------------- RETAINED LIABILITY MARKETABLE
SHARES AMOUNT EARNINGS ADJUSTMENT SECURITIES
---------- ------------- ------------- ----------- -----------
(IN THOUSANDS)
BALANCE AT DECEMBER 31, 1990............................ 125,039 $ 947,147 $ 1,139,999 $ -- $ (13,988)
Deferred taxes on net unrealized loss................... 4,756
Net income.............................................. 253,426
Dividends declared
Preferred and preference stock........................ (42,746)
Common stock ($1.40 per share)........................ (176,584)
Common stock issued..................................... 1,651 32,263
Other................................................... (199)
Change in net unrealized loss on marketable
securities............................................. 13,988
Change in deferred taxes on net unrealized loss......... (4,756)
---------- ------------- ------------- ----------- -----------
BALANCE AT DECEMBER 31, 1991............................ 126,690 979,211 1,174,095 -- --
Net income.............................................. 264,347
Dividends declared
Preferred and preference stock........................ (42,247)
Common stock ($1.43 per share)........................ (196,601)
Common stock issued..................................... 17,098 356,230
Other................................................... (4) (439) 43
---------- ------------- ------------- ----------- -----------
BALANCE AT DECEMBER 31, 1992............................ 143,784 1,335,002 1,199,637 -- --
Net income.............................................. 309,866
Dividends declared
Preferred and preference stock........................ (41,839)
Common stock ($1.47 per share)........................ (213,407)
Common stock issued..................................... 2,250 57,379
Other................................................... (917) (3,117)
Pension liability adjustment............................ (33,990)
Deferred taxes on pension liability adjustment.......... 11,897
---------- ------------- ------------- ----------- -----------
BALANCE AT DECEMBER 31, 1993............................ 146,034 $ 1,391,464 $ 1,251,140 $ (22,093) $ --
---------- ------------- ------------- ----------- -----------
---------- ------------- ------------- ----------- -----------
TOTAL AMOUNT
-------------
BALANCE AT DECEMBER 31, 1990............................ $ 2,073,158
Deferred taxes on net unrealized loss................... 4,756
Net income.............................................. 253,426
Dividends declared
Preferred and preference stock........................ (42,746)
Common stock ($1.40 per share)........................ (176,584)
Common stock issued..................................... 32,263
Other................................................... (199)
Change in net unrealized loss on marketable
securities............................................. 13,988
Change in deferred taxes on net unrealized loss......... (4,756)
-------------
BALANCE AT DECEMBER 31, 1991............................ 2,153,306
Net income.............................................. 264,347
Dividends declared
Preferred and preference stock........................ (42,247)
Common stock ($1.43 per share)........................ (196,601)
Common stock issued..................................... 356,230
Other................................................... (396)
-------------
BALANCE AT DECEMBER 31, 1992............................ 2,534,639
Net income.............................................. 309,866
Dividends declared
Preferred and preference stock........................ (41,839)
Common stock ($1.47 per share)........................ (213,407)
Common stock issued..................................... 57,379
Other................................................... (4,034)
Pension liability adjustment............................ (33,990)
Deferred taxes on pension liability adjustment.......... 11,897
-------------
BALANCE AT DECEMBER 31, 1993............................ $ 2,620,511
-------------
-------------
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been restated to conform to the current year's
presentation.
34
CONSOLIDATED STATEMENTS OF CAPITALIZATION
AT DECEMBER
31,
-------------
1993
-------------
(IN
THOUSANDS)
LONG-TERM DEBT
First Refunding Mortgage Bonds of BGE
4% Series, due March 1, 1993............................................................................. $ --
4 1/2% Series, due July 15, 1994......................................................................... --
9 1/8% Series, due October 15, 1995...................................................................... 200,000
5 1/8% Series, due April 15, 1996........................................................................ 26,585
6 1/8% Series, due August 1, 1997........................................................................ 24,957
5 5/8% Installment Series, due August 15, 1998........................................................... --
7% Series, due December 15, 1998......................................................................... 28,638
8.40% Series, due October 15, 1999....................................................................... 100,000
5 1/2% Series, due July 15, 2000......................................................................... 125,000
7 1/4% Series, due April 15, 2001........................................................................ 59,911
8 3/8% Series, due August 15, 2001....................................................................... 124,980
7 5/8% Series, due September 1, 2001..................................................................... --
7 1/8% Series, due January 1, 2002....................................................................... 49,999
7 1/4% Series, due July 1, 2002.......................................................................... 125,000
7 1/2% Series, due July 1, 2002.......................................................................... --
5 1/2% Installment Series, due July 15, 2002............................................................. 12,080
7 1/2% Series, due September 15, 2002.................................................................... --
6 1/2% Series, due February 15, 2003..................................................................... 125,000
6 1/8% Series, due July 1, 2003.......................................................................... 125,000
8 1/8% Series, due February 1, 2004...................................................................... --
5 1/2% Series, due April 15, 2004........................................................................ 125,000
6.80% Series, due September 15, 2004..................................................................... 20,000
8 3/8% Series, due September 15, 2006.................................................................... --
7 1/2% Series, due January 15, 2007...................................................................... 125,000
8 1/4% Series, due September 15, 2007.................................................................... --
6 5/8% Series, due March 15, 2008........................................................................ 125,000
9 3/8% Series, due July 1, 2008.......................................................................... --
6.90% Installment Series, due September 15, 2009......................................................... 55,000
9 1/8% Series, due March 1, 2016......................................................................... --
7 1/2% Series, due March 1, 2023......................................................................... 124,998
7 1/2% Series, due April 15, 2023........................................................................ 100,000
-------------
Total First Refunding Mortgage Bonds..................................................................... 1,802,148
-------------
Other long-term debt of BGE
Medium-term notes, Series A.............................................................................. 23,500
Medium-term notes, Series B.............................................................................. 100,000
Medium-term notes, Series C.............................................................................. 173,050
9 1/2% Notes, due May 1, 1993............................................................................ --
Pollution control loan, due July 1, 2011................................................................. 36,000
Port facilities loan, due June 1, 2013................................................................... 48,000
Adjustable rate pollution control loan, due July 1, 2014................................................. 20,000
5.55% Pollution control revenue refunding loan, due July 15, 2014........................................ 47,000
Economic development loan, due December 1, 2018.......................................................... 35,000
-------------
Total other long-term debt............................................................................... 482,550
-------------
Long-term debt of Constellation Companies
Mortgage and construction loans and other collateralized notes 7.75%, due December 16, 1995.............. $ --
Variable rates, due through 2009......................................................................... 151,251
8.5%, due May 1, 2001.................................................................................... --
7.73%, due March 15, 2009................................................................................ 6,465
Loans under revolving credit agreements.................................................................. --
Unsecured notes.......................................................................................... 440,000
-------------
Total long-term debt of Constellation Companies.......................................................... 597,716
-------------
Unamortized discount and premium........................................................................... (17,754)
Current portion of long-term debt.......................................................................... (41,516)
-------------
Total long-term debt....................................................................................... 2,823,144
-------------
1992
-------------
LONG-TERM DEBT
First Refunding Mortgage Bonds of BGE
4% Series, due March 1, 1993............................................................................. $ 24,061
4 1/2% Series, due July 15, 1994......................................................................... 29,921
9 1/8% Series, due October 15, 1995...................................................................... 200,000
5 1/8% Series, due April 15, 1996........................................................................ 26,585
6 1/8% Series, due August 1, 1997........................................................................ 24,957
5 5/8% Installment Series, due August 15, 1998........................................................... 50,000
7% Series, due December 15, 1998......................................................................... 28,638
8.40% Series, due October 15, 1999....................................................................... 100,000
5 1/2% Series, due July 15, 2000......................................................................... --
7 1/4% Series, due April 15, 2001........................................................................ 59,914
8 3/8% Series, due August 15, 2001....................................................................... 125,000
7 5/8% Series, due September 1, 2001..................................................................... 59,975
7 1/8% Series, due January 1, 2002....................................................................... 49,999
7 1/4% Series, due July 1, 2002.......................................................................... 125,000
7 1/2% Series, due July 1, 2002.......................................................................... 49,985
5 1/2% Installment Series, due July 15, 2002............................................................. 12,500
7 1/2% Series, due September 15, 2002.................................................................... 49,990
6 1/2% Series, due February 15, 2003..................................................................... --
6 1/8% Series, due July 1, 2003.......................................................................... --
8 1/8% Series, due February 1, 2004...................................................................... 74,983
5 1/2% Series, due April 15, 2004........................................................................ --
6.80% Series, due September 15, 2004..................................................................... 20,000
8 3/8% Series, due September 15, 2006.................................................................... 74,960
7 1/2% Series, due January 15, 2007...................................................................... 125,000
8 1/4% Series, due September 15, 2007.................................................................... 75,000
6 5/8% Series, due March 15, 2008........................................................................ --
9 3/8% Series, due July 1, 2008.......................................................................... 12,718
6.90% Installment Series, due September 15, 2009......................................................... 55,000
9 1/8% Series, due March 1, 2016......................................................................... 98,000
7 1/2% Series, due March 1, 2023......................................................................... --
7 1/2% Series, due April 15, 2023........................................................................ --
-------------
Total First Refunding Mortgage Bonds..................................................................... 1,552,186
-------------
Other long-term debt of BGE
Medium-term notes, Series A.............................................................................. 69,500
Medium-term notes, Series B.............................................................................. 100,000
Medium-term notes, Series C.............................................................................. 138,050
9 1/2% Notes, due May 1, 1993............................................................................ 100,000
Pollution control loan, due July 1, 2011................................................................. 36,000
Port facilities loan, due June 1, 2013................................................................... 48,000
Adjustable rate pollution control loan, due July 1, 2014................................................. 20,000
5.55% Pollution control revenue refunding loan, due July 15, 2014........................................ --
Economic development loan, due December 1, 2018.......................................................... 35,000
-------------
Total other long-term debt............................................................................... 546,550
-------------
Long-term debt of Constellation Companies
Mortgage and construction loans and other collateralized notes 7.75%, due December 16, 1995.............. $ 5,575
Variable rates, due through 2009......................................................................... 160,572
8.5%, due May 1, 2001.................................................................................... 3,300
7.73%, due March 15, 2009................................................................................ --
Loans under revolving credit agreements.................................................................. 152,000
Unsecured notes.......................................................................................... 255,000
-------------
Total long-term debt of Constellation Companies.......................................................... 576,447
-------------
Unamortized discount and premium........................................................................... (8,463)
Current portion of long-term debt.......................................................................... (289,770)
-------------
Total long-term debt....................................................................................... 2,376,950
-------------
35
CONSOLIDATED STATEMENTS OF CAPITALIZATION (CONTINUED)
AT DECEMBER
31,
-------------
1993
-------------
(IN
THOUSANDS)
PREFERRED STOCK
Cumulative, $100 par value, 1,000,000 shares authorized
Series B, 4 1/2%, 222,921 shares outstanding, callable at $110 per share................................. 22,292
Series C, 4%, 68,928 shares outstanding, callable at $105 per share...................................... 6,893
Series D, 5.40%, 300,000 shares outstanding, callable at $101 per share.................................. 30,000
-------------
Total preferred stock...................................................................................... 59,185
-------------
PREFERENCE STOCK
Cumulative, $100 par value, 6,500,000 shares authorized
Redeemable preference stock
7.50%, 1986 Series, 470,000 and 485,000 shares outstanding, respectively. Callable at $105 per share
prior to October 1, 1996 and at lesser amounts thereafter............................................... 47,000
6.75%, 1987 Series, 485,000 shares outstanding. Callable at $104.50 per share prior to April 1, 1997 and
at lesser amounts thereafter............................................................................ 48,500
6.95%, 1987 Series, 500,000 shares outstanding........................................................... 50,000
7.64%, 1988 Series, 500,000 shares outstanding, called at $103.82 per share on July 1, 1993.............. --
7.80%, 1989 Series, 500,000 shares outstanding........................................................... 50,000
8.25%, 1989 Series, 500,000 shares outstanding........................................................... 50,000
8.625%, 1990 Series, 650,000 shares outstanding.......................................................... 65,000
7.85%, 1991 Series, 350,000 shares outstanding........................................................... 35,000
Current portion of redeemable preference stock........................................................... (3,000)
-------------
Total redeemable preference stock........................................................................ 342,500
-------------
Preference stock not subject to mandatory redemption
7.88%, 1971 Series, 500,000 shares outstanding, called at $101 per share on September 1, 1993............ $ --
7.75%, 1972 Series, 400,000 shares outstanding, called at $101 per share on November 8, 1993............. --
7.78%, 1973 Series, 200,000 shares outstanding, callable at $101 per share............................... 20,000
7.125%, 1993 Series, 400,000 shares outstanding, not callable prior to July 1, 2003...................... 40,000
6.97%, 1993 Series, 500,000 shares outstanding, not callable prior to October 1, 2003.................... 50,000
6.70%, 1993 Series, 400,000 shares outstanding, not callable prior to January 1, 2004.................... 40,000
-------------
Total preference stock not subject to mandatory redemption............................................... 150,000
-------------
COMMON SHAREHOLDERS' EQUITY
Common stock without par value, 175,000,000 shares authorized; 146,034,014 and 143,783,581 shares issued
and outstanding at December 31, 1993 and 1992, respectively. (At December 31, 1993, 166,893 shares were
reserved for the Employee Savings Plan and 4,770,773 shares were reserved for the Dividend Reinvestment
and Stock Purchase Plan.)................................................................................. 1,391,464
Retained earnings.......................................................................................... 1,251,140
Pension liability adjustment............................................................................... (22,093)
-------------
Total common shareholders' equity.......................................................................... 2,620,511
-------------
TOTAL CAPITALIZATION......................................................................................... $ 5,995,340
-------------
-------------
1992
-------------
PREFERRED STOCK
Cumulative, $100 par value, 1,000,000 shares authorized
Series B, 4 1/2%, 222,921 shares outstanding, callable at $110 per share................................. 22,292
Series C, 4%, 68,928 shares outstanding, callable at $105 per share...................................... 6,893
Series D, 5.40%, 300,000 shares outstanding, callable at $101 per share.................................. 30,000
-------------
Total preferred stock...................................................................................... 59,185
-------------
PREFERENCE STOCK
Cumulative, $100 par value, 6,500,000 shares authorized
Redeemable preference stock
7.50%, 1986 Series, 470,000 and 485,000 shares outstanding, respectively. Callable at $105 per share
prior to October 1, 1996 and at lesser amounts thereafter............................................... 48,500
6.75%, 1987 Series, 485,000 shares outstanding. Callable at $104.50 per share prior to April 1, 1997 and
at lesser amounts thereafter............................................................................ 48,500
6.95%, 1987 Series, 500,000 shares outstanding........................................................... 50,000
7.64%, 1988 Series, 500,000 shares outstanding, called at $103.82 per share on July 1, 1993.............. 50,000
7.80%, 1989 Series, 500,000 shares outstanding........................................................... 50,000
8.25%, 1989 Series, 500,000 shares outstanding........................................................... 50,000
8.625%, 1990 Series, 650,000 shares outstanding.......................................................... 65,000
7.85%, 1991 Series, 350,000 shares outstanding........................................................... 35,000
Current portion of redeemable preference stock........................................................... (1,500)
-------------
Total redeemable preference stock........................................................................ 395,500
-------------
Preference stock not subject to mandatory redemption
7.88%, 1971 Series, 500,000 shares outstanding, called at $101 per share on September 1, 1993............ $ 50,000
7.75%, 1972 Series, 400,000 shares outstanding, called at $101 per share on November 8, 1993............. 40,000
7.78%, 1973 Series, 200,000 shares outstanding, callable at $101 per share............................... 20,000
7.125%, 1993 Series, 400,000 shares outstanding, not callable prior to July 1, 2003...................... --
6.97%, 1993 Series, 500,000 shares outstanding, not callable prior to October 1, 2003.................... --
6.70%, 1993 Series, 400,000 shares outstanding, not callable prior to January 1, 2004.................... --
-------------
Total preference stock not subject to mandatory redemption............................................... 110,000
-------------
COMMON SHAREHOLDERS' EQUITY
Common stock without par value, 175,000,000 shares authorized; 146,034,014 and 143,783,581 shares issued
and outstanding at December 31, 1993 and 1992, respectively. (At December 31, 1993, 166,893 shares were
reserved for the Employee Savings Plan and 4,770,773 shares were reserved for the Dividend Reinvestment
and Stock Purchase Plan.)................................................................................. 1,335,002
Retained earnings.......................................................................................... 1,199,637
Pension liability adjustment............................................................................... --
-------------
Total common shareholders' equity.......................................................................... 2,534,639
-------------
TOTAL CAPITALIZATION......................................................................................... $ 5,476,274
-------------
-------------
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been restated to conform to the current year's
presentation.
36
CONSOLIDATED STATEMENTS OF INCOME TAXES
YEAR ENDED DECEMBER 31,
----------------------------
1993 1992
------------- -------------
(DOLLAR AMOUNTS IN
THOUSANDS)
INCOME TAXES
Current....................................................................................... $ 93,459 $ 85,287
------------- -------------
Deferred
Change in tax effect of temporary differences............................................... 63,972 44,975
Change in income taxes recoverable through future rates..................................... (30,086) (18,061)
Deferred taxes credited (charged) to shareholders' equity................................... 11,897 --
------------- -------------
Deferred taxes charged to expense........................................................... 45,783 26,914
------------- -------------
Effect on deferred taxes of enacted change in federal corporate income tax rate
Increase in deferred tax liability.......................................................... 20,105 --
Income taxes recoverable through future rates............................................... (12,831) --
------------- -------------
Deferred taxes charged to expense........................................................... 7,274 --
------------- -------------
Investment tax credit adjustments............................................................. (8,444) (8,854)
------------- -------------
Total income taxes............................................................................ 138,072 103,347
------------- -------------
Cumulative effect of change in the method of accounting for income taxes
Increase in deferred tax liability.......................................................... -- --
Income taxes recoverable through future rates............................................... -- --
------------- -------------
Amount recognized in income................................................................. -- --
------------- -------------
Income taxes per Consolidated Statements of Income............................................ $ 138,072 $ 103,347
------------- -------------
------------- -------------
RECONCILIATION OF INCOME TAXES COMPUTED AT STATUTORY
FEDERAL RATE TO TOTAL INCOME TAXES
Income before income taxes (including cumulative effect of accounting change)............... $ 447,938 $ 367,694
Statutory federal income tax rate......................................................... 35% 34%
------------- -------------
Income taxes computed at statutory federal rate........................................... 156,778 125,016
Increases (decreases) in income taxes due to
Depreciation differences not normalized on regulated activities......................... 9,253 8,955
Allowance for equity funds used during construction..................................... (5,072) (4,723)
Amortization of deferred investment tax credits......................................... (8,444) (8,854)
Tax credits flowed through to income.................................................... (9,736) (804)
Change in federal corporate income tax rate charged to expense.......................... 7,274 --
Reversal of deferred taxes on nonregulated activities................................... -- --
Amortization of deferred tax rate differential on regulated activities.................. (5,789) (7,365)
Other................................................................................... (6,192) (8,878)
------------- -------------
Total income taxes........................................................................ $ 138,072 $ 103,347
------------- -------------
------------- -------------
Effective federal income tax rate......................................................... 30.8% 28.1%
1991
-------------
INCOME TAXES
Current....................................................................................... $ 61,047
-------------
Deferred
Change in tax effect of temporary differences............................................... 28,361
Change in income taxes recoverable through future rates..................................... (12,625)
Deferred taxes credited (charged) to shareholders' equity................................... (4,756)
-------------
Deferred taxes charged to expense........................................................... 10,980
-------------
Effect on deferred taxes of enacted change in federal corporate income tax rate
Increase in deferred tax liability.......................................................... --
Income taxes recoverable through future rates............................................... --
-------------
Deferred taxes charged to expense........................................................... --
-------------
Investment tax credit adjustments............................................................. (6,225)
-------------
Total income taxes............................................................................ 65,802
-------------
Cumulative effect of change in the method of accounting for income taxes
Increase in deferred tax liability.......................................................... 286,787
Income taxes recoverable through future rates............................................... (267,042)
-------------
Amount recognized in income................................................................. 19,745
-------------
Income taxes per Consolidated Statements of Income............................................ $ 85,547
-------------
-------------
RECONCILIATION OF INCOME TAXES COMPUTED AT STATUTORY
FEDERAL RATE TO TOTAL INCOME TAXES
Income before income taxes (including cumulative effect of accounting change)............... $ 319,228
Statutory federal income tax rate......................................................... 34%
-------------
Income taxes computed at statutory federal rate........................................... 108,538
Increases (decreases) in income taxes due to
Depreciation differences not normalized on regulated activities......................... 7,008
Allowance for equity funds used during construction..................................... (8,023)
Amortization of deferred investment tax credits......................................... (9,344)
Tax credits flowed through to income.................................................... (1,335)
Change in federal corporate income tax rate charged to expense.......................... --
Reversal of deferred taxes on nonregulated activities................................... (19,745)
Amortization of deferred tax rate differential on regulated activities.................. (5,024)
Other................................................................................... (6,273)
-------------
Total income taxes........................................................................ $ 65,802
-------------
-------------
Effective federal income tax rate......................................................... 20.6%
AT DECEMBER
31,
-------------
1993
-------------
(DOLLAR
AMOUNTS IN
THOUSANDS)
DEFERRED INCOME TAXES
Deferred tax liabilities
Accelerated depreciation.................................................................................... $ 789,165
Allowance for funds used during construction................................................................ 202,490
Income taxes recoverable through future rates............................................................... 90,950
Deferred termination and postemployment costs............................................................... 55,890
Deferred fuel costs......................................................................................... 45,518
Leveraged leases............................................................................................ 32,613
Percentage repair allowance................................................................................. 35,431
Other....................................................................................................... 129,130
-------------
Total deferred tax liabilities.............................................................................. 1,381,187
-------------
Deferred tax assets
Alternative minimum tax..................................................................................... 72,187
Accrued pension and postemployment benefit costs............................................................ 67,016
Deferred investment tax credits............................................................................. 55,099
Other....................................................................................................... 119,274
-------------
Total deferred tax assets................................................................................... 313,576
-------------
Deferred income taxes per Consolidated Balance Sheets......................................................... $ 1,067,611
-------------
-------------
1992
-------------
DEFERRED INCOME TAXES
Deferred tax liabilities
Accelerated depreciation.................................................................................... $ 714,019
Allowance for funds used during construction................................................................ 199,577
Income taxes recoverable through future rates............................................................... 73,759
Deferred termination and postemployment costs............................................................... --
Deferred fuel costs......................................................................................... 61,709
Leveraged leases............................................................................................ 33,867
Percentage repair allowance................................................................................. 33,367
Other....................................................................................................... 95,995
-------------
Total deferred tax liabilities.............................................................................. 1,212,293
-------------
Deferred tax assets
Alternative minimum tax..................................................................................... 72,189
Accrued pension and postemployment benefit costs............................................................ 1,595
Deferred investment tax credits............................................................................. 56,337
Other....................................................................................................... 98,638
-------------
Total deferred tax assets................................................................................... 228,759
-------------
Deferred income taxes per Consolidated Balance Sheets......................................................... $ 983,534
-------------
-------------
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been restated to conform to the current year's
presentation.
37
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. SIGNIFICANT ACCOUNTING POLICIES
NATURE OF THE BUSINESS
Baltimore Gas and Electric Company (BGE) and Subsidiaries (collectively, the
Company) is primarily an electric and gas utility serving a territory which
encompasses Baltimore City and all or part of nine Central Maryland counties.
The Company is also engaged in diversified businesses as described further in
Note 3.
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of BGE and all
subsidiaries in which BGE owns directly or indirectly a majority of the voting
stock. Intercompany balances and transactions have been eliminated in
consolidation. Under this policy, the accounts of Constellation Holdings, Inc.
and its subsidiaries (collectively, the Constellation Companies) and BNG, Inc.
are consolidated in the financial statements. Safe Harbor Water Power
Corporation is reported under the equity method. Corporate joint ventures,
partnerships, and affiliated companies in which a 20% to 50% voting interest is
held are accounted for under the equity method, unless control is evident, in
which case the entity is consolidated. Investments in power generation systems
and certain financial investments in which less than a 20% voting interest is
held are accounted for under the cost method, unless significant influence is
exercised over the entity, in which case the investment is accounted for under
the equity method.
REGULATION OF UTILITY OPERATIONS
BGE's utility operations are subject to regulation by the Public Service
Commission of Maryland (PSC). The accounting policies and practices used in the
determination of service rates are also generally used for financial reporting
purposes in accordance with generally accepted accounting principles for
regulated industries. See Note 5.
UTILITY REVENUES
BGE recognizes utility revenues as service is rendered to customers.
FUEL AND PURCHASED ENERGY COSTS
Subject to the approval of the PSC, the cost of fuel used in generating
electricity, net of revenues from interchange sales, and the cost of gas sold
may be recovered through zero-based electric fuel rate (see Note 13) and
purchased gas adjustment clauses. The difference between actual fuel costs and
fuel revenues is deferred on the balance sheet to be recovered from or refunded
to customers in future periods.
The electric fuel rate formula is based upon the latest twenty-four-month
generation mix, subject to a minimum level of nuclear generation, and the latest
three-month average fuel cost for each generating unit. The fuel rate does not
change unless the calculated rate is more than 5% above or below the rate then
in effect.
The purchased gas adjustment is based on recent annual volumes of gas and
the related current prices charged by BGE's gas suppliers. Any deferred
underrecoveries or overrecoveries of purchased gas costs for the twelve months
ended November 30 each year are charged or credited to customers over the
ensuing calendar year.
INCOME TAXES
The Company adopted Statement of Financial Accounting Standards No. 109,
"Accounting for Income Taxes," effective January 1, 1991. Statement No. 109
requires the use of the liability method of accounting for income taxes. Under
the liability method, the deferred tax liability represents the tax effect of
temporary differences between the financial statement and tax bases of assets
and liabilities. It is measured using presently enacted tax rates. The portion
of BGE's deferred tax liability applicable to utility operations which has not
been reflected in current service rates represents income taxes recoverable
through future rates. It has been recorded as a regulatory asset on the balance
sheet. Deferred income tax expense represents the net change in the deferred tax
liability and regulatory asset during the year, exclusive of amounts charged or
credited to common shareholders' equity.
The 1993 and 1992 current tax expense consists solely of regular tax. The
1991 current tax expense consists of a regular tax of $46.8 million and an
alternative minimum tax (AMT) of $14.2 million. The AMT liabilities generated in
1991 and prior years can be carried forward indefinitely as tax credits to
future years in which the regular tax liability exceeds the AMT liability. As of
December 31, 1993, this carryforward totaled $73.2 million.
As a result of its effect on nonregulated activities, the cumulative effect
of the change in the method of accounting for income taxes resulted in an
increase in 1991 net income of $19.7 million, or 16 CENTS per common share,
because of the reversal of deferred income taxes on nonregulated activities
accrued in prior years at tax rates in excess of the 34% tax rate in effect at
that time.
38
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 1. SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
The investment tax credit (ITC) associated with BGE's regulated utility
operations has been deferred and is amortized to income ratably over the lives
of the subject property. ITC and other tax credits associated with nonregulated
diversified business activities other than leveraged leases are flowed through
to income. As of December 31, 1993, the Company had energy and other tax credit
carryforwards of $4.8 million which expire in the years 2005 through 2008.
BGE's utility revenue from system sales is subject to the Maryland public
service company franchise tax in lieu of a state income tax. The franchise tax
is included in taxes other than income taxes in the Consolidated Statements of
Income.
INVENTORY VALUATION
Fuel stocks and materials and supplies are generally stated at average cost.
REAL ESTATE PROJECTS
Real estate projects consist of the Constellation Companies' investment in
rental and operating properties and properties under development. Rental and
operating properties are held for investment. Properties under development are
held for future development and sale. Costs incurred in the acquisition and
active development of such properties are capitalized. Rental and operating
properties and properties under development are stated at cost unless the amount
invested exceeds the amounts expected to be recovered through operations and
sales. In these cases, the projects are written down to the amount estimated to
be recoverable.
INVESTMENTS
Marketable equity securities are stated at the lower of cost or market
value, and other securities are stated at cost. Where appropriate, cost reflects
amortization of premium and discount computed on a straight-line basis. Gains
and losses on the sale of the Constellation Companies' investment securities are
included in revenues from diversified activities on the income statement and are
recognized upon realization on a specific identification basis. Gains and losses
on the sale of BGE's nuclear decommissioning trust fund securities are included
in net other income and deductions on the income statement and are recognized
upon realization on a specific identification basis.
Statement of Financial Accounting Standards No. 115, which must be adopted
in 1994, requires that investments in equity securities having readily
determinable fair values and debt securities other than those which the Company
has the positive intent and ability to hold to maturity be recorded at fair
value rather than at amortized cost. Changes in the fair value of these
securities will be recorded in shareholders' equity except for trading
securities, for which such changes will be recorded in income. Adoption of this
statement is not expected to have a material impact on the Company's financial
statements.
UTILITY PLANT, DEPRECIATION AND AMORTIZATION, AND DECOMMISSIONING
Utility plant is stated at original cost, which includes material, labor,
and, where applicable, construction overhead costs and an allowance for funds
used during construction. Additions to utility plant and replacements of units
of property are capitalized to utility plant accounts. Maintenance and repairs
of property and replacements of items of property determined to be less than a
unit of property are charged to maintenance expense.
Depreciation is generally computed using composite straightline rates
applied to the average investment in classes of depreciable property. The
composite depreciation rates by class of depreciable property are 2.80% for the
Calvert Cliffs Nuclear Power Plant, 2.75% for the Brandon Shores Power Plant,
3.26% for other electric plant, 3.12% for gas plant, and 4.02% for common plant
other than vehicles. Vehicles are depreciated based on their estimated useful
lives.
BGE owns an undivided interest in the Keystone and Conemaugh electric
generating plants located in western Pennsylvania, as well as in the
transmission line which transports the plants' output to the joint owners'
service territories. BGE's ownership interest in these plants is 20.99% and
10.56%, respectively, and represents a net investment of $128 million as of
December 31, 1993. Financing and accounting for these properties are the same as
for wholly owned utility plant.
Nuclear fuel expenditures are amortized as a component of actual fuel costs
based on the energy produced over the life of the fuel. Fees for the future
disposal of spent fuel are paid quarterly to the Department of Energy and are
accrued based on the kilowatt-hours of electricity generated. Nuclear fuel
expenses are subject to recovery through the electric fuel rate.
Nuclear decommissioning costs are accrued by and recovered through a sinking
fund methodology. In its April 1993 rate order, the PSC granted BGE revenue to
accumulate a decommissioning reserve of $336 million in
39
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 1. SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
1992 dollars by the end of Calvert Cliffs' service life in 2016, adjusted to
reflect expected inflation, to decommission the radioactive portion of the
plant. The total decommissioning reserve of $93.4 million and $77.8 million at
December 31, 1993 and 1992, respectively, is included in accumulated
depreciation in the Consolidated Balance Sheets. In accordance with Nuclear
Regulatory Commission (NRC) regulations, BGE has established an external
decommissioning trust to which a portion of accrued decommissioning costs has
been contributed.
The NRC requires utilities to provide financial assurance that they will
accumulate sufficient funds to pay for the cost of nuclear decommissioning based
upon either a generic NRC formula or a facility-specific decommissioning cost
estimate, provided that the facility-specific estimate is equal to or greater
than that of the NRC formula. Subsequent to the PSC's April 1993 rate order, the
NRC updated its generic formula to reflect substantially higher waste burial
charges. The revised NRC formula generates a decommissioning cost estimate of
$703 million in 1992 dollars. Additionally, the Company initiated a
facility-specific study which, when completed, is expected to generate an
estimate of the cost to decommission the radioactive portion of the plant which
is less than the NRC formula estimate. The Company is currently completing the
facility-specific study and plans to request the NRC to permit the use of the
facility-specific decommissioning cost estimate as a basis of funding these
costs and providing the requisite financial assurance.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION AND CAPITALIZED INTEREST
The allowance for funds used during construction (AFC) is an accounting
procedure which capitalizes the cost of funds used to finance utility
construction projects as part of utility plant on the balance sheet, crediting
the cost as a noncash item on the income statement. The cost of borrowed and
equity funds is segregated between interest expense and other income,
respectively. BGE recovers the capitalized AFC and a return thereon after the
related utility plant is placed in service and included in depreciable assets
and rate base.
During the period January 1, 1991 through April 23, 1993, the Company
accrued AFC at a pre-tax rate of 9.94%, compounded annually. Effective April 24,
1993, a rate order of the PSC reduced the pre-tax AFC rate to 9.40%, compounded
annually.
Effective January 1, 1992, the PSC authorized the accrual of AFC on all
electric, gas, and common utility construction projects with a construction
period of more than one month. Prior to 1992, AFC was accrued on major electric
projects only.
The Constellation Companies capitalize interest on qualifying real estate
and power generation development projects. BGE capitalizes interest on certain
deferred fuel costs as discussed in Note 5.
LONG-TERM DEBT
The discount or premium and expense of issuance associated with long-term
debt are deferred and amortized over the original lives of the respective debt
issues. Gains and losses on the reacquisition of debt are amortized over the
remaining original lives of the issuances.
CASH FLOWS
For the purpose of reporting cash flows, highly liquid investments purchased
with a maturity of three months or less are considered to be cash equivalents.
40
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 2. SEGMENT INFORMATION
YEAR ENDED DECEMBER 31,
-------------------------------------------
1993 1992 1991
------------- ------------- -------------
(IN THOUSANDS)
Electric
Revenues......................................................................... $ 2,115,155 $ 1,967,923 $ 1,994,525
Income from operations........................................................... 538,340 441,784 444,530
Income from operations net of income taxes....................................... 402,893 350,429 352,385
Depreciation..................................................................... 203,476 191,970 173,349
Construction expenditures (including AFC)........................................ 419,519 346,728 406,008
Identifiable assets at December 31............................................... 6,025,798 5,508,008 5,374,940
Gas
Revenues......................................................................... $ 435,849 $ 402,937 $ 358,195
Income from operations........................................................... 39,426 45,552 35,607
Income from operations net of income taxes....................................... 33,188 37,514 30,945
Depreciation..................................................................... 22,995 21,364 18,896
Construction expenditures (including AFC)........................................ 58,359 42,688 50,236
Identifiable assets at December 31............................................... 694,977 579,386 555,609
Diversified Businesses
Revenues......................................................................... $ 117,710 $ 120,483 $ 96,133
Income from operations........................................................... 43,234 48,009 9,051
Income from operations net of income taxes....................................... 46,847 44,055 20,313
Depreciation..................................................................... 10,303 10,149 9,019
Cumulative effect of change in the method of accounting for income taxes......... -- -- 19,745
Identifiable assets at December 31............................................... 1,096,220 1,023,315 1,001,313
Total
Revenues......................................................................... $ 2,668,714 $ 2,491,343 $ 2,448,853
Income from operations........................................................... 621,000 535,345 489,188
Income from operations net of income taxes....................................... 482,928 431,998 403,641
Depreciation..................................................................... 236,774 223,483 201,264
Cumulative effect of change in the method of accounting for income taxes......... -- -- 19,745
Construction expenditures (including AFC)........................................ 477,878 389,416 456,244
Identifiable assets at December 31............................................... 7,816,995 7,110,709 6,931,862
Other assets at December 31...................................................... 170,044 263,648 206,127
Total assets at December 31...................................................... 7,987,039 7,374,357 7,137,989
41
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 3. SUBSIDIARY INFORMATION
Diversified businesses consist of the operations of Constellation Holdings,
Inc. and its subsidiaries and BNG, Inc.
Constellation Holdings, Inc., a wholly owned subsidiary, holds all of the
stock of three other subsidiaries, Constellation Real Estate Group, Inc.,
Constellation Energy, Inc., and Constellation Investments, Inc. These companies
are engaged in real estate development and ownership of senior living
facilities; development, ownership, and operation of power generation systems;
and financial investments, respectively.
BNG, Inc. is a wholly owned subsidiary which invests in natural gas
reserves.
BGE's investment in Safe Harbor Water Power Corporation, a producer of
hydroelectric power, represents two-thirds of Safe Harbor's total capital stock,
including one-half of the voting stock, and a two-thirds interest in its
retained earnings.
The following is condensed financial information for Constellation Holdings,
Inc. and its subsidiaries. Similar information is not presented for Safe Harbor
Water Power Corporation and BNG, Inc. as the financial position and results of
operations of these entities are immaterial. The condensed financial information
for the Constellation Companies does not reflect the elimination of intercompany
balances or transactions which are eliminated in the Company's consolidated
financial statements.
1993 1992 1991
------------- ------------- -------------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
Income Statements
Revenues
Real estate projects........................................................... $ 77,598 $ 76,582 $ 75,205
Power generation systems....................................................... 24,971 28,084 17,732
Financial investments.......................................................... 21,195 21,485 8,059
------------- ------------- -------------
Total revenues................................................................. 123,764 126,151 100,996
Expenses other than interest and income taxes.................................... 80,427 77,872 91,848
------------- ------------- -------------
Income from operations........................................................... 43,337 48,279 9,148
Minority interest................................................................ (280) 718 3,550
Interest expense................................................................. (33,143) (30,103) (32,938)
Income tax benefit (expense)..................................................... 1,984 (3,637) 9,005
Cumulative effect of change in the method of accounting for income taxes......... -- -- 19,745
------------- ------------- -------------
Net income....................................................................... $ 11,898 $ 15,257 $ 8,510
------------- ------------- -------------
------------- ------------- -------------
Contribution to the Company's earnings per share of common stock................... $ .08 $ .11 $ .07
------------- ------------- -------------
------------- ------------- -------------
Balance Sheets
Current assets................................................................... $ 54,039 $ 29,899 $ 20,463
Noncurrent assets................................................................ 1,036,507 990,273 976,179
------------- ------------- -------------
Total assets..................................................................... $ 1,090,546 $ 1,020,172 $ 996,642
------------- ------------- -------------
------------- ------------- -------------
Current liabilities.............................................................. $ 24,201 $ 113,404 $ 285,130
Noncurrent liabilities........................................................... 759,048 611,370 431,370
Shareholder's equity............................................................. 307,297 295,398 280,142
------------- ------------- -------------
Total liabilities and shareholder's equity....................................... $ 1,090,546 $ 1,020,172 $ 996,642
------------- ------------- -------------
------------- ------------- -------------
42
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 4. REAL ESTATE PROJECTS AND FINANCIAL INVESTMENTS
Real estate projects consist of the following investments held by the
Constellation Companies:
AT DECEMBER 31,
------------------------
1993 1992
----------- -----------
(IN THOUSANDS)
Properties under development........................................................................... $ 249,473 $ 231,856
Rental and operating properties (net of accumulated depreciation)...................................... 237,194 227,412
Other real estate ventures............................................................................. 730 2,774
----------- -----------
Total.................................................................................................. $ 487,397 $ 462,042
----------- -----------
----------- -----------
In 1991, a subsidiary of Constellation Holdings, Inc. recognized a loss of
$10 million to write down the carrying value of certain operating properties and
properties under development to reflect the depressed real estate and economic
markets.
Financial investments consist of the following investments held by the
Constellation Companies:
AT DECEMBER 31,
------------------------
1993 1992
----------- -----------
(IN THOUSANDS)
Insurance companies.................................................................................... $ 83,275 $ 93,048
Financial limited partnerships......................................................................... 44,903 41,076
Leveraged leases....................................................................................... 38,669 39,441
Marketable equity securities........................................................................... 42,681 25,304
Other securities....................................................................................... 3,787 8,142
----------- -----------
Total.................................................................................................. $ 213,315 $ 207,011
----------- -----------
----------- -----------
In 1991, a subsidiary of Constellation Holdings, Inc. recognized a loss of
$10.5 million to write-down the carrying value of financial investments to
reflect previously unrealized losses on certain marketable equity securities.
The securities written down were subsequently sold. A subsidiary of
Constellation Holdings, Inc. also recognized a loss of $3.1 million on two
financial limited partnerships that were adjusted to reflect market value when
the partnerships were reclassified as short-term investments.
As of December 31, 1993, gross unrealized gains and losses applicable to
marketable equity securities totaled $1.8 and $0.5 million, respectively. Net
realized gains (losses) from financial investments included in net income
totaled $6.5 million in 1993, $9.8 million in 1992, and $(11.6) million in 1991.
NOTE 5. REGULATORY ASSETS
Certain utility expenses and credits normally reflected in income are
deferred on the balance sheet as regulatory assets and liabilities and are
recognized in income as the related amounts are included in service rates and
recovered from or refunded to customers in utility revenues. The following table
sets forth BGE's regulatory assets.
AT DECEMBER 31,
------------------------
1993 1992
----------- -----------
(IN THOUSANDS)
Income taxes recoverable through future rates.......................................................... $ 259,856 $ 216,939
Deferred fuel costs.................................................................................... 130,052 181,497
Deferred termination benefit costs..................................................................... 96,793 --
Deferred nuclear expenditures.......................................................................... 86,726 76,549
Deferred postemployment benefit costs.................................................................. 62,892 --
Deferred cost of decommissioning federal uranium enrichment facilities................................. 49,562 55,000
Deferred energy conservation expenditures.............................................................. 38,655 20,519
Deferred environmental costs........................................................................... 32,966 --
Other.................................................................................................. 10,623 18,059
----------- -----------
Total.................................................................................................. $ 768,125 $ 568,563
----------- -----------
----------- -----------
Income taxes recoverable through future rates represent principally the tax
effect of depreciation differences not normalized and the allowance for equity
funds used during construction, offset by unamortized deferred tax rate
differentials and deferred taxes on deferred ITC. These amounts are amortized as
the related temporary differences reverse. See Note 1 for a further discussion
of income taxes.
43
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 5. REGULATORY ASSETS (CONTINUED)
Deferred fuel costs represent the difference between actual fuel costs and
the fuel rate revenues under BGE's fuel clauses (see Note 1). Deferred fuel
costs are amortized as they are collected from customers.
The underrecovered costs deferred under the fuel clauses were as follows:
AT DECEMBER 31,
------------------------
1993 1992
----------- -----------
(IN THOUSANDS)
Electric
Costs deferred....................................................................................... $ 155,901 $ 210,483
Reserve for possible disallowance of replacement energy costs (see Note 13).......................... (35,000) (35,000)
----------- -----------
Net electric......................................................................................... 120,901 175,483
Gas.................................................................................................... 9,151 6,014
----------- -----------
Total.................................................................................................. $ 130,052 $ 181,497
----------- -----------
----------- -----------
Deferred termination benefit costs represent the net unamortized balance of
the cost of certain termination benefits (see Note 7) applicable to BGE's
regulated operations. These costs are being amortized over a five-year period in
accordance with rate actions of the PSC.
Deferred nuclear expenditures represent the net unamortized balance of
certain operations and maintenance costs which are being amortized over the
remaining life of the Calvert Cliffs Nuclear Power Plant in accordance with
orders of the PSC. These expenditures consist of costs incurred from 1979
through 1982 for inspecting and repairing seismic pipe supports, expenditures
incurred from 1989 through 1993 associated with nonrecurring phases of certain
nuclear operations projects, and expenditures incurred during 1990 for
investigating leaks in the pressurizer heater sleeves.
Deferred postemployment benefit costs represent the excess of such costs
recognized in accordance with Statements of Financial Accounting Standards No.
106 and No. 112 over the amounts reflected in utility rates. These costs will be
amortized over a 15-year period beginning no later than 1998 (see Note 6).
Deferred cost of decommissioning federal uranium enrichment facilities
represents the unamortized portion of BGE's required contributions to a fund for
decommissioning and decontaminating the Department of Energy's (DOE) uranium
enrichment facilities. The Energy Policy Act of 1992 requires domestic utilities
to make such contributions, which are generally payable over a fifteen-year
period with escalation for inflation and are based upon the amount of uranium
enriched by DOE for each utility. These costs are being amortized over the
contribution period as a cost of fuel.
Deferred energy conservation expenditures represent the net unamortized
balance of certain operations costs which are being amortized over five years in
accordance with orders of the PSC. These expenditures consist of labor,
materials, and indirect costs associated with the conservation programs approved
by the PSC.
Deferred environmental costs represent the estimated costs of investigating
contamination and performing certain remediation activities at contaminated
Company-owned sites (see Note 13). These costs are generally amortized over the
estimated term of the remediation process.
Electric deferred fuel costs in excess of $72.8 million are excluded from
rate base by the PSC for ratemaking purposes. Effective April 24, 1993, BGE has
been authorized by the PSC to accrue carrying charges on electric deferred fuel
costs excluded from rate base. These carrying charges are accrued prospectively
at the 9.40% authorized rate of return. The income effect of the equity funds
portion of the carrying charges is being deferred until such amounts are
recovered in utility service rates subsequent to the completion of the fuel rate
proceeding examining the 1989-1991 outages at Calvert Cliffs Nuclear Power Plant
as discussed in Note 13.
NOTE 6. PENSION AND POSTEMPLOYMENT BENEFITS
PENSION BENEFITS
The Company sponsors several noncontributory defined benefit pension plans,
the largest of which (the Pension Plan) covers substantially all BGE employees
and certain employees of the Constellation Companies. The other plans, which are
not material in amount, provide supplemental benefits to certain non-employee
directors and key employees. Benefits under the plans are generally based on
age, years of service, and compensation levels.
44
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 6. PENSION AND POSTEMPLOYMENT BENEFITS (CONTINUED)
Prior service cost associated with retroactive plan amendments is amortized
on a straightline basis over the average remaining service period of active
employees.
The Company's funding policy is to contribute annually the cost of the
Pension Plan as determined under the projected unit credit cost method. Pension
Plan assets at December 31, 1993 consisted primarily of marketable fixed income
and equity securities, group annuity contracts, and short-term investments.
The following tables set forth the combined funded status of the plans and
the composition of total net pension cost. Due to declining interest rates, the
Company reduced the discount rate used to measure its liability for pension,
postretirement, and postemployment benefits to 7.5% as of December 31, 1993.
This decrease in the discount rate, coupled with the increased pension liability
resulting from the 1993 Voluntary Special Early Retirement Program, produced an
accumulated pension obligation greater than the fair value of the Pension Plan's
assets. As a result, the Company recorded a pension liability adjustment, a
portion of which was charged to shareholders' equity.
AT DECEMBER 31,
------------------------
1993 1992
----------- -----------
(IN THOUSANDS)
Vested benefit obligation.............................................................................. $ 677,069 $ 485,098
Nonvested benefit obligation........................................................................... 11,359 9,814
----------- -----------
Accumulated benefit obligation......................................................................... 688,428 494,912
Projected benefits related to increase in future compensation levels................................... 109,161 86,882
----------- -----------
Projected benefit obligation........................................................................... 797,589 581,794
Plan assets at fair value.............................................................................. (605,629) (542,190)
----------- -----------
Projected benefit obligation less plan assets.......................................................... 191,960 39,604
Unrecognized prior service cost........................................................................ (21,252) (17,671)
Unrecognized net loss.................................................................................. (148,450) (28,017)
Pension liability adjustment........................................................................... 58,553 --
Unamortized net asset from adoption of FASB Statement No. 87........................................... 1,812 2,039
----------- -----------
Accrued pension liability (asset)...................................................................... $ 82,623 $ (4,045)
----------- -----------
----------- -----------
YEAR ENDED DECEMBER 31,
----------------------------------
1993 1992 1991
---------- ---------- ----------
(IN THOUSANDS)
Components of net pension cost
Service cost-benefits earned during the period............................................. $ 11,645 $ 11,771 $ 11,729
Interest cost on projected benefit obligation.............................................. 51,183 47,355 43,143
Actual return on plan assets............................................................... (56,225) (33,685) (56,737)
Net amortization and deferral.............................................................. 6,591 (12,257) 12,810
---------- ---------- ----------
Total net pension cost..................................................................... 13,194 13,184 10,945
Amount capitalized as construction cost.................................................... (1,800) (1,839) (1,500)
---------- ---------- ----------
Amount charged to expense.................................................................. $ 11,394 $ 11,345 $ 9,445
---------- ---------- ----------
---------- ---------- ----------
Net pension cost shown above does not include the cost of termination
benefits described in Note 7.
The Company also sponsors a defined contribution savings plan covering all
eligible BGE employees and certain employees of the Constellation Companies.
Under this plan, the Company makes contributions on behalf of participants.
Company contributions to this plan totaled $9 million, $14.8 million, and $10.6
million in 1993, 1992, and 1991, respectively.
POSTRETIREMENT BENEFITS
The Company sponsors defined benefit postretirement health care and life
insurance plans which cover substantially all BGE employees and certain
employees of the Constellation Companies. Benefits under the plans are generally
based on age, years of service, and pension benefit levels. The postretirement
benefit (PRB) plans are unfunded. Substantially all of the health care plans are
contributory, and participant contributions for employees who retire after June
30, 1992 are based on age and years of service. Retiree contributions increase
commensurate with the expected increase in medical costs. The postretirement
life insurance plan is noncontributory.
45
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 6. PENSION AND POSTEMPLOYMENT BENEFITS (CONTINUED)
Effective January 1, 1993, the Company adopted Statement of Financial
Accounting Standards No. 106, which requires a change in the method of
accounting for postretirement benefits other than pensions from the
pay-as-you-go method used prior to 1993 to the accrual method. The transition
obligation existing at the beginning of 1993 is being amortized over a
twenty-year period.
In April 1993, the PSC issued a rate order authorizing BGE to recognize in
operating expense one-half of the annual increase in PRB costs applicable to
regulated operations as a result of the adoption of Statement No. 106 and to
defer the remainder of the annual increase in these costs for inclusion in BGE's
next base rate proceeding. In accordance with the PSC's Order, the increase in
annual PRB costs applicable to regulated operations for the period January
through April 1993, net of amounts capitalized as construction cost, has been
deferred. This amount, which totaled $5.7 million, as well as all amounts to be
deferred prior to completion of BGE's next base rate proceeding, will be
amortized over a 15-year period beginning no later than 1998 in accordance with
the PSC's Order. This phase-in approach meets the guidelines established by the
Emerging Issues Task Force of the Financial Accounting Standards Board for
deferring post-retirement benefit costs as a regulatory asset. Accrual-basis PRB
costs applicable to nonregulated operations are charged to expense.
The following table sets forth the components of the accumulated
postretirement benefit obligation and a reconciliation of these amounts to the
accrued postretirement benefit liability.
AT DECEMBER 31,
----------------------------------------------------
1993 1992
------------------------- -------------------------
LIFE LIFE
HEALTH CARE INSURANCE HEALTH CARE INSURANCE
------------ ----------- ------------ -----------
(IN THOUSANDS)
Accumulated postretirement benefit obligation:
Retirees................................................................ $ 182,638 $ 45,461 $ 116,935 $ 34,600
Fully eligible active employees......................................... 19,177 839 18,082 143
Other active employees.................................................. 58,832 15,377 54,208 16,458
------------ ----------- ------------ -----------
Total accumulated postretirement benefit obligation..................... 260,647 61,677 189,225 51,201
Unrecognized transition obligation...................................... (179,764) (48,641) (189,225) (51,201)
Unrecognized net loss................................................... (36,675) (9,072) -- --
------------ ----------- ------------ -----------
Accrued postretirement benefit liability.................................. $ 44,208 $ 3,964 $ -- $ --
------------ ----------- ------------ -----------
------------ ----------- ------------ -----------
The following table sets forth the composition of net postretirement benefit
cost.
YEAR ENDED
DECEMBER 31,
1993
--------------
(IN THOUSANDS)
Components of net postretirement benefit cost:
Service cost--benefits earned during the period................................................................. $ 4,373
Interest cost on accumulated postretirement benefit obligation.................................................. 20,451
Amortization of transition obligation........................................................................... 12,021
--------------
Total net postretirement benefit cost........................................................................... 36,845
Amount capitalized as construction cost......................................................................... (5,898)
Amount deferred................................................................................................. (11,965)
--------------
Amount charged to expense....................................................................................... $ 18,982
--------------
--------------
Net postretirement benefit costs shown above do not include the cost of
termination benefits described in Note 7.
Postretirement benefit costs recognized under the pay-as-you-go method were
as follows:
YEAR ENDED DECEMBER
31,
---------------------
1992 1991
---------- ---------
(IN THOUSANDS)
Total postretirement benefit cost.......................................................................... $ 11,676 $ 9,741
Amount capitalized as construction cost.................................................................... (1,911) (1,573)
---------- ---------
Amount charged to expense.................................................................................. $ 9,765 $ 8,168
---------- ---------
---------- ---------
46
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 6. PENSION AND POSTEMPLOYMENT BENEFITS (CONTINUED)
OTHER POSTEMPLOYMENT BENEFITS
The Company provides certain pay continuation payments and health and life
insurance benefits to employees of BGE and certain of the Constellation
Companies who are determined to be disabled under BGE's Long-Term Disability
Plan. The Company adopted Statement of Financial Accounting Standards No. 112,
which requires a change in the method of accounting for these benefits from the
pay-as-you-go method to an accrual method, as of December 31, 1993. The
liability for these benefits totaled $52.1 million as of December 31, 1993, and
the portion of this liability attributable to regulated activities was deferred.
The amounts deferred will be amortized over a 15-year period beginning no later
than 1998. The adoption of Statement No. 112 did not have a material impact on
net income. The increase in the annual cost of these benefits subsequent to the
adoption of accrual accounting is not expected to have a material impact on the
Company's financial statements.
ASSUMPTIONS
The pension and postemployment benefit liabilities were determined using the
following assumptions.
AT DECEMBER
31,
-----------
1993
-----------
Assumptions:
Discount rate................................................................................................ 7.5%
Average increase in future compensation levels............................................................... 4.5%
Expected long-term rate of return on assets.................................................................. 9.5%
1992
-----------
Assumptions:
Discount rate................................................................................................ 8.75%
Average increase in future compensation levels............................................................... 4.5 %
Expected long-term rate of return on assets.................................................................. 9.5 %
The health care inflation rates for 1993 are assumed to be 9.5% for
Medicare-eligible retirees and 12% for retirees not covered by Medicare. Both
rates are assumed to decrease by 0.5% annually to an ultimate rate of 5.5% in
the years 2001 and 2006, respectively. A one percentage point increase in the
health care inflation rate from the assumed rates would increase the accumulated
postretirement benefit obligation by approximately $37.8 million as of December
31, 1993 and would increase the aggregate of the service cost and interest cost
components of postretirement benefit cost by approximately $3.8 million
annually.
NOTE 7. TERMINATION BENEFITS
The Company offered a Voluntary Special Early Retirement Program (the 1992
VSERP) to eligible employees who retired during the period February 1, 1992
through April 1, 1992. In accordance with Statement of Financial Accounting
Standards No. 88, "Employers' Accounting for Settlements and Curtailments of
Defined Benefit Pension Plans and for Termination Benefits," the cost of
termination benefits associated with the 1992 VSERP, which consisted principally
of an enhanced pension benefit, was recognized in 1992 and reduced net income by
$6.6 million, or 5 CENTS per common share. In April 1993, the PSC authorized BGE
to amortize this charge over a five-year period for ratemaking purposes.
Accordingly, BGE established a regulatory asset and recorded a corresponding
credit to operating expense for this amount. The reversal of the 1992 VSERP in
April 1993 increased net income by $6.6 million, or 5 CENTS per common share.
The Company offered a second Voluntary Special Early Retirement Program (the
1993 VSERP) to eligible employees who retired as of February 1, 1994. The
one-time cost of the 1993 VSERP consisted of enhanced pension and postretirement
benefits. In addition to the 1993 VSERP, further employee reductions have been
accomplished through the elimination of certain positions, and various programs
have been offered to employees impacted by the eliminations. In accordance with
Statement No. 88, the cost of termination benefits associated with the 1993
VSERP and various programs, which totaled $105.5 million, was recognized in
1993. The $88.3 million portion of 1993 VSERP attributable to regulated
activities was deferred and will be amortized over a five-year period for
ratemaking purposes, beginning in February 1994, consistent with previous rate
actions of the PSC. The $17.2 million remaining portion of the cost of
termination benefits was charged to expense in 1993.
47
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 8. SHORT-TERM BORROWINGS
Information concerning commercial paper notes and lines of credit is set
forth below. In support of the lines of credit, the Company pays commitment fees
and, in some cases, maintains compensating balances which have no withdrawal
restrictions. Borrowings under the lines are at the banks' prime rates, base
interest rates, or at various money market rates.
1993 1992 1991
------------- ------------- -------------
(DOLLAR AMOUNTS IN THOUSANDS)
BGE'S COMMERCIAL PAPER NOTES
Borrowings outstanding at December 31............................................ $ -- $ 11,900 $ 159,500
Weighted average interest rate of notes outstanding at December 31............... -- % 3.62% 4.75%
Unused lines of credit supporting commercial paper notes at December 31 (a)...... $ 208,000 $ 203,000 $ 303,000
Maximum borrowings during the year............................................... 96,900 393,650 336,200
Average daily borrowings during the year (b)..................................... 10,322 98,892 210,883
Weighted average interest rate for the year (c).................................. 3.28% 4.79% 6.08%
CONSTELLATION COMPANIES' LINES OF CREDIT
Borrowings outstanding at December 31............................................ $ -- $ -- $ 52,670
Weighted average interest rate of borrowings outstanding at December 31.......... -- % -- % 5.94%
Unused lines of credit at December 31............................................ $ 20,000 $ -- $ 8,000
Maximum borrowings during the year............................................... -- 60,670 75,000
Average daily borrowings during the year (b)..................................... -- 31,773 61,860
Weighted average interest rate for the year (c).................................. -- % 6.01% 7.19%
- --------------------------
(a) BGE decreased its lines of credit supporting commercial paper notes to
$143 million effective January 1, 1994.
(b) The sum of dollar days of outstanding borrowings divided by the number of
days in the period.
(c) Total interest accrued during the period divided by average daily
borrowings.
NOTE 9. LONG-TERM DEBT
FIRST REFUNDING MORTGAGE BONDS OF BGE
Substantially all of the principal properties and franchises owned by BGE,
as well as the capital stock of Constellation Holdings, Inc., Safe Harbor Water
Power Corporation, and BNG, Inc., are subject to the lien of the mortgage under
which BGE's outstanding First Refunding Mortgage Bonds have been issued.
On August 1 of each year, BGE is required to pay to the mortgage trustee an
annual sinking fund payment equal to 1% of the largest principal amount of
Mortgage Bonds outstanding under the mortgage during the preceding twelve
months. Such funds are to be used, as provided in the mortgage, for the purchase
and retirement by the trustee of Mortgage Bonds of any series other than the
Installment Series of 2002 and 2009, the 9 1/8% Series of 1995, the 8.40% Series
of 1999, the 5 1/2% Series of 2000, the 8 3/8% Series of 2001, the 7 1/4% Series
of 2002, the 6 1/2% Series of 2003, the 6 1/8% Series of 2003, the 5 1/2% Series
of 2004, the 6.80% Series of 2004, the 7 1/2% Series of 2007, and the 6 5/8%
Series of 2008.
OTHER LONG-TERM DEBT OF BGE
BGE maintains revolving credit agreements that expire at various times
during 1995 and 1996. Under the terms of the agreements, BGE may, at its option,
obtain loans at various interest rates. A commitment fee is paid on the daily
average of the unborrowed portion of the commitment. At December 31, 1993, BGE
had no borrowings under these revolving credit agreements and had available $165
million of unused capacity under these agreements. Effective January 1, 1994,
BGE decreased its revolving credit agreements to $125 million.
The Medium-term Notes Series A mature at various dates from February 1994
through February 1996. The weighted average interest rate for notes outstanding
at December 31, 1993 is 7.93%.
The Medium-term Notes Series B mature at various dates from July 1998
through September 2006. The weighted average interest rate for notes outstanding
at December 31, 1993 is 8.43%.
The Medium-term Notes Series C mature at various dates from June 1996
through June 2003. The weighted average interest rate for notes outstanding at
December 31, 1993 is 7.16%.
48
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 9. LONG-TERM DEBT (CONTINUED)
The principal amounts of Installment Series Mortgage Bonds payable each year
are as follows:
BONDS DUE BONDS DUE
YEAR 2002 2009
- ------------------------------------------------------------------------------------ ----------- -----------
(IN THOUSANDS)
1994................................................................................ $ 430
1995 through 1997................................................................... 605
1998 and 1999....................................................................... 690
2000 and 2001....................................................................... 865
2002................................................................................ 6,725
2005 through 2008................................................................... $ 3,250
2009................................................................................ 42,000
LONG-TERM DEBT OF CONSTELLATION COMPANIES
The mortgage and construction loans and other collateralized notes have
varying terms. Of the $151.2 million of variable rate notes, $51.1 million
requires periodic interest only payments with various maturities from September
1995 through March 1996, and $100.1 million requires periodic payment of
principal and interest with various maturities from January 1995 through January
2009. The $6.5 million, 7.73% mortgage note requires quarterly principal and
interest payments through March 15, 2009.
The unsecured notes outstanding as of December 31, 1993 mature in accordance
with the following schedule:
(IN THOUSANDS)
8.35%, due August 28, 1995.................................................................... $ 20,000
8.71%, due August 28, 1996.................................................................... 23,000
6.19%, due September 9, 1996.................................................................. 10,000
8.93%, due August 28, 1997.................................................................... 52,000
6.65%, due September 9, 1997.................................................................. 15,000
8.23%, due October 15, 1997................................................................... 30,000
7.05%, due April 22, 1998..................................................................... 25,000
7.06%, due September 9, 1998.................................................................. 20,000
8.48%, due October 15, 1998................................................................... 75,000
7.30%, due April 22, 1999..................................................................... 90,000
8.73%, due October 15, 1999................................................................... 15,000
7.55%, due April 22, 2000..................................................................... 35,000
7.43%, due September 9, 2000.................................................................. 30,000
--------------
Total......................................................................................... $ 440,000
--------------
--------------
WEIGHTED AVERAGE INTEREST RATES FOR VARIABLE RATE DEBT
The weighted average interest rates for variable rate debt during 1993 and
1992 were as follows:
1993 1992
----------- -----------
BGE
Loans under revolving credit agreements................................................ -- % 4.23%
Floating rate notes Series II.......................................................... -- 7.90
Pollution control loan................................................................. 2.39 2.90
Port facilities loan................................................................... 2.53 3.04
Adjustable rate pollution control loan................................................. 3.00 4.13
Economic development loan.............................................................. 2.49 3.11
Constellation Companies
Mortgage and construction loans and other collateralized notes......................... 6.26 6.74
Loans under credit agreements.......................................................... 5.94 6.15
49
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 9. LONG-TERM DEBT (CONTINUED)
AGGREGATE MATURITIES
The combined aggregate maturities and sinking fund requirements for all of
the Company's long-term borrowings for each of the next five years are as
follows:
CONSTELLATION
YEAR BGE COMPANIES
- --------------------------------------------------------------------------------- ----------- ------------
(IN THOUSANDS)
1994............................................................................. $ 32,728 $ 8,788
1995............................................................................. 218,429 81,260
1996............................................................................. 72,330 77,213
1997............................................................................. 80,754 112,359
1998............................................................................. 84,112 128,355
NOTE 10. REDEEMABLE PREFERENCE STOCK
The 6.95%, 1987 Series and the 7.80%, 1989 Series are subject to mandatory
redemption in their entirety at par on October 1, 1995 and July 1, 1997,
respectively.
The following series are subject to an annual mandatory redemption of the
number of shares shown below at par beginning in the year shown below. At BGE's
option, an additional number of shares, not to exceed the same number as are
mandatory, may be redeemed at par in any year, commencing in the same year in
which the mandatory redemption begins. The 8.25%, 1989 Series, the 8.625%, 1990
Series, and the 7.85%, 1991 Series listed below are not redeemable except
through operation of a sinking fund.
BEGINNING
SERIES SHARES YEAR
- ------------------------------------------------------------------------------------- ---------- -----------
7.50%, 1986 Series................................................................... 15,000 1992
6.75%, 1987 Series................................................................... 15,000 1993
8.25%, 1989 Series................................................................... 100,000 1995
8.625%, 1990 Series.................................................................. 130,000 1996
7.85%, 1991 Series................................................................... 70,000 1997
The combined aggregate redemption requirements for all series of redeemable
preference stock for each of the next five years are as follows:
YEAR
- ---------------------------------------------------------------------------------------------- (IN THOUSANDS)
1994.......................................................................................... $ 3,000
1995.......................................................................................... 63,000
1996.......................................................................................... 26,000
1997.......................................................................................... 83,000
1998.......................................................................................... 33,000
With regard to payment of dividends or assets available in the event of
liquidation, preferred stock ranks prior to preference and common stock; all
issues of preference stock, whether subject to mandatory redemption or not, rank
equally; and all preference stock ranks prior to common stock.
NOTE 11. LEASES
The Company, as lessee, contracts for certain facilities and equipment under
lease agreements with various expiration dates and renewal options. Consistent
with the regulatory treatment, BGE lease payments are charged to expense. Lease
expense, which is comprised primarily of operating leases, totaled $13.8
million, $14 million, and $12.6 million for the years ended 1993, 1992, and
1991, respectively.
50
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 11. LEASES (CONTINUED)
The future minimum lease payments at December 31, 1993 for long-term
noncancelable operating leases are as follows:
YEAR
- ---------------------------------------------------------------------------------------------- (IN THOUSANDS)
1994.......................................................................................... $ 4,439
1995.......................................................................................... 4,185
1996.......................................................................................... 3,627
1997.......................................................................................... 2,755
1998.......................................................................................... 1,751
Thereafter.................................................................................... 2,770
--------------
Total minimum lease payments.................................................................. $ 19,527
--------------
--------------
Certain of the Constellation Companies, as lessor, have entered into
operating leases for office and retail space. These leases expire over periods
ranging from 1 to 23 years, with options to renew. The net book value of
property under operating leases was $187 million at December 31, 1993. The
future minimum rentals to be received under operating leases in effect at
December 31, 1993 are as follows:
YEAR
- ---------------------------------------------------------------------------------------------- (IN THOUSANDS)
1994.......................................................................................... $ 16,685
1995.......................................................................................... 15,222
1996.......................................................................................... 13,826
1997.......................................................................................... 12,398
1998.......................................................................................... 10,744
Thereafter.................................................................................... 62,888
--------------
Total minimum rentals......................................................................... $ 131,763
--------------
--------------
NOTE 12. TAXES OTHER THAN INCOME TAXES
Taxes other than income taxes were as follows:
YEAR ENDED DECEMBER 31,
-------------------------------------
1993 1992 1991
----------- ----------- -----------
(DOLLAR AMOUNTS IN THOUSANDS)
Real and personal property............................................................... $ 107,958 $ 100,419 $ 89,379
Public service company franchise......................................................... 48,693 45,654 46,041
Social security.......................................................................... 35,724 34,911 33,121
Other.................................................................................... 9,836 9,355 9,026
----------- ----------- -----------
Total taxes other than income taxes...................................................... 202,211 190,339 177,567
Amounts included above charged to accounts other than taxes.............................. (7,379) (7,335) (6,786)
----------- ----------- -----------
Taxes other than income taxes per Consolidated Statements of Income...................... $ 194,832 $ 183,004 $ 170,781
----------- ----------- -----------
----------- ----------- -----------
NOTE 13. COMMITMENTS, GUARANTEES, AND CONTINGENCIES
COMMITMENTS
BGE has made substantial commitments in connection with its construction
program for 1994 and subsequent years. In addition, BGE has entered into two
long-term contracts for the purchase of electric generating
51
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 13. COMMITMENTS, GUARANTEES, AND CONTINGENCIES (CONTINUED)
capacity and energy. The contracts expire in 2001 and 2013. Total payments under
these contracts were $68.7 million, $60.6 million, and $30 million during 1993,
1992, and 1991, respectively. At December 31, 1993, the estimated future
payments for capacity and energy that BGE is obligated to buy under these
contracts are as follows:
YEAR
- ---------------------------------------------------------------------------------------------- (IN THOUSANDS)
1994.......................................................................................... $ 63,675
1995.......................................................................................... 71,884
1996.......................................................................................... 71,051
1997.......................................................................................... 67,496
1998.......................................................................................... 67,556
Thereafter.................................................................................... 415,736
--------------
Total payments................................................................................ $ 757,398
--------------
--------------
Certain of the Constellation Companies have committed to contribute
additional capital and to make additional loans to certain affiliates, joint
ventures, and partnerships in which they have an interest. As of December 31,
1993, the total amount of investment requirements committed to by the
Constellation Companies is $44 million.
GUARANTEES
BGE has agreed to guarantee two-thirds of certain indebtedness incurred by
Safe Harbor Water Power Corporation. The amount of such indebtedness totals $40
million, of which $26.7 million represents BGE's share of the guarantee. BGE
believes that the risk of material loss on the loans guaranteed is minimal.
As of December 31, 1993, the total outstanding loans and letters of credit
of certain power generation and real estate projects guaranteed by the
Constellation Companies were $50 million. Also, the Constellation Companies have
agreed to guarantee certain other borrowings of various power generation and
real estate projects. The Company believes that the risk of material loss on the
loans guaranteed and performance guarantees is minimal.
ENVIRONMENTAL MATTERS
The Clean Air Act of 1990 (the Act) contains provisions designed to reduce
sulfur dioxide and nitrogen oxide emissions from electric generating stations in
two separate phases. Under Phase I of the Act, which must be implemented by
1995, BGE expects to incur expenditures of approximately $55 million, most of
which is attributable to its portion of the cost of installing a flue gas
desulfurization system at the Conemaugh generating station, in which BGE owns a
10.56% interest. BGE is currently examining what actions will be required in
order to comply with Phase II of the Act, which must be implemented by 2000.
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 nitrogen oxide (NOx) control
requirements under the Act are less certain because all implementation
regulations have not yet been finalized by the government. It is expected that
by the year 2000 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 $70 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 (EPA) 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. Although the cleanup costs for certain
environmentally contaminated 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 coal
tar. However, no formal legal proceedings have been instituted. In 1993, BGE
accrued a liability of approximately $25.4 million for estimated future
environmental costs at these sites. Based on previous actions of the PSC, BGE
has deferred these estimated future costs, as well as actual costs
52
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 13. COMMITMENTS, GUARANTEES, AND CONTINGENCIES (CONTINUED)
which have been incurred to date, as a regulatory asset (see Note 5). 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.
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. Although BGE maintains the various insurance policies currently
available to provide coverage for portions of these contingencies, BGE does not
consider the available insurance to be adequate to cover the costs that could
result from a major accident or an extended outage at either of the Calvert
Cliffs units.
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 $9.4 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 $6.2 million in any one year.
For physical damage to Calvert Cliffs, BGE has $2.7 billion of property
insurance, including $1.4 billion from an industry mutual insurance company. If
accidents at any insured plants cause a shortfall of funds at the industry
mutual, BGE and all policyholders could be assessed, with BGE's share being up
to $14.6 million.
If an outage at Calvert Cliffs is caused by an insured physical damage loss
and lasts more than 21 weeks, BGE has up to $426 million per unit of insurance,
provided by a different industry mutual insurance company for replacement power
costs. This amount can be reduced by up to $85 million per unit if an outage to
both units at Calvert Cliffs is caused by a singular insured physical damage
loss. If an outage at any insured plant causes a short-fall of funds at the
industry mutual, BGE and all policyholders could be assessed, with BGE's share
being up to $9.4 million.
RECOVERABILITY OF ELECTRIC FUEL COSTS
By statute, actual electric fuel costs are recoverable so long as the 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 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 the
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 units 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 the GUPP program. 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
53
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 13. COMMITMENTS, GUARANTEES, AND CONTINGENCIES (CONTINUED)
1987. In November 1989, testimony was filed on behalf of Maryland 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.
In May 1989, BGE filed its fuel rate case in which 1988 performance was to
be examined. BGE met the system-wide and nuclear plant performance targets in
1988. People's Counsel alleges 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 Calvert
Cliffs. 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 Commission 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 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
proceedings in excess of the provision, but such amounts could be material.
NOTE 14. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following table presents the carrying amount and fair value of financial
instruments included in the Consolidated Balance Sheets.
AT DECEMBER 31,
----------------------------------------------------------
1993 1992
---------------------------- ----------------------------
CARRYING CARRYING
AMOUNT FAIR VALUE AMOUNT FAIR VALUE
------------- ------------- ------------- -------------
(IN THOUSANDS)
Current assets..................................................... $ 496,919 $ 496,919 $ 408,790 $ 408,790
Investments and other assets....................................... 125,046 129,752 93,834 97,135
Current liabilities................................................ 443,968 443,968 649,650 649,650
Capitalization..................................................... 3,165,644 3,303,615 2,772,450 2,871,291
The carrying amount of current assets and current liabilities approximates
fair value because of the short maturity of these instruments.
The fair value of investments and other assets is based on quoted market
prices where available. Certain investments with a carrying amount of $70
million at December 31, 1993 and $71 million at December 31, 1992 are excluded
from the amounts shown in investments and other assets because it was not
practicable to
54
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 14. FAIR VALUE OF FINANCIAL INSTRUMENTS (CONTINUED)
determine their fair values. These investments include partnership investments
in public and private equity and debt securities, partnership investments in
solar powered energy production facilities, and investments in stock trusts.
Financial instruments included in capitalization are long-term debt and
redeemable preference stock. The fair value of fixed-rate long-term debt and
redeemable preference stock is estimated using quoted market prices where
available, or by discounting remaining cash flows at the current market rate.
The carrying amount of variable-rate long-term debt approximates fair value.
BGE and the Constellation Companies have loan guarantees totalling $26.7
million and $36 million, respectively, at December 31, 1993 and $30 and $38
million, respectively, at December 31, 1992 for which it is not practicable to
determine fair value. It is not anticipated that these loan guarantees will need
to be funded.
NOTE 15. QUARTERLY FINANCIAL DATA (UNAUDITED)
The following data are unaudited but, in the opinion of Management, include
all adjustments necessary for a fair presentation. BGE's utility business is
seasonal in nature with the peak sales periods generally occurring during the
summer and winter months. Accordingly, comparisons among quarters of a year may
not be indicative of overall trends and changes in operations.
QUARTER ENDED
---------------------------------------------------- YEAR ENDED
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 DECEMBER 31
----------- ----------- ------------ ------------ -------------
(IN THOUSANDS, EXCEPT PER-SHARE AMOUNTS)
1993
Revenues................................................. $ 683,825 $ 564,721 $ 774,064 $ 646,104 $ 2,668,714
Income from operations................................... 136,094 107,387 287,461 90,058 621,000
Net income............................................... 65,796 55,876 157,058 31,136 309,866
Earnings applicable to common stock...................... 55,276 45,300 146,511 20,940 268,027
Earnings per share of common stock....................... 0.38 0.31 1.01 0.14 1.85
----------- ----------- ------------ ------------ -------------
----------- ----------- ------------ ------------ -------------
1992
Revenues................................................. $ 669,253 $ 540,895 $ 677,059 $ 604,136 $ 2,491,343
Income from operations................................... 127,121 91,309 222,627 94,288 535,345
Net income............................................... 59,254 38,049 124,620 42,424 264,347
Earnings applicable to common stock...................... 48,680 27,475 114,047 31,898 222,100
Earnings per share of common stock....................... 0.37 0.20 0.84 0.22 1.63
----------- ----------- ------------ ------------ -------------
----------- ----------- ------------ ------------ -------------
RESULTS FOR THE SECOND QUARTER OF 1993 REFLECT THE REVERSAL OF THE COST OF
THE TERMINATION BENEFITS ASSOCIATED WITH THE 1992 VOLUNTARY SPECIAL EARLY
RETIREMENT PROGRAM (SEE NOTE 7).
RESULTS FOR THE THIRD QUARTER OF 1993 REFLECT THE EFFECTS OF THE OMNIBUS
BUDGET RECONCILIATION ACT OF 1993.
RESULTS FOR THE FOURTH QUARTER OF 1993 REFLECT THE COST OF CERTAIN
TERMINATION BENEFITS (SEE NOTE 7).
RESULTS FOR THE FIRST AND THIRD QUARTERS OF 1992 REFLECT THE COST OF
TERMINATION BENEFITS ASSOCIATED WITH THE 1992 VOLUNTARY SPECIAL EARLY RETIREMENT
PROGRAM (SEE NOTE 7).
THE SUM OF THE QUARTERLY EARNINGS PER SHARE AMOUNTS MAY NOT EQUAL THE TOTAL
FOR THE YEAR DUE TO CHANGES IN THE AVERAGE NUMBER OF SHARES OUTSTANDING
THROUGHOUT THE YEAR.
55
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Not applicable.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this item with respect to directors is set forth
on pages 2 through 4 under "Item 1. Election of 14 Directors" in the Proxy
Statement and is incorporated herein by reference.
The information required by this item with respect to executive officers is,
pursuant to instruction 3 of paragraph (b) of Item 401 of Regulation S-K, set
forth in Item 10 of Part I of this Form 10-K under "Executive Officers of the
Registrant."
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item is set forth on pages 7 through 11
under "Item 1. Election of 14 Directors -- Compensation of Executive Officers by
the Company" in the Proxy Statement and is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this item is set forth on page 6 under "Item 1.
Election of 14 Directors -- Security Ownership of Directors and Executive
Officers" in the Proxy Statement and is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this item is set forth on page 5 under "Item 1.
Election of 14 Directors -- Certain Relationships and Transactions" in the Proxy
Statement and is incorporated herein by reference.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) The following documents are filed as a part of this Report:
1. Financial Statements:
Auditors' Report dated January 21, 1994 of Coopers & Lybrand,
Independent Auditors
Consolidated Statements of Income for three years ended December 31,
1993
Consolidated Balance Sheets at December 31, 1993 and December 31,
1992
Consolidated Statements of Cash Flows for three years ended December
31, 1993
Consolidated Statements of Common Shareholders' Equity for three
years ended December 31, 1993
Consolidated Statements of Capitalization at December 31, 1993 and
December 31, 1992
Consolidated Statements of Income Taxes for three years ended
December 31, 1993
Notes to Consolidated Financial Statements
2. Financial Statement Schedules:
Schedule V -- Property, Plant and Equipment
Schedule VI -- Accumulated Depreciation, Depletion and Amortization of Property, Plant
and Equipment
Schedule VII -- Guarantees of Securities of Other Issuers
Schedule VIII -- Valuation and Qualifying Accounts
Schedules other than those listed above are omitted as not applicable or
not required.
56
3. Exhibits Required by Item 601 of Regulation S-K Including Each
Management Contract or Compensatory Plan or Arrangement Required to be
Filed as an Exhibit.
EXHIBIT
NUMBER
- -------
*3(a) -- Charter of BGE, restated as of October 13, 1993. (Designated as
Exhibit No. 3(b) in Form 10-Q dated November 12, 1993, File No.
1-1910.)
*3(b) -- By-Laws of BGE, as amended to March 1, 1993. (Designated as
Exhibit No. 3(c) in Form 10-K Annual Report for 1992, File No.
1-1910.)
4(a) -- Indenture and Supplemental Indentures between BGE and Bankers
Trust Company, Trustee:
DESIGNATED IN
----------------------------------------------------------------------------------------
EXHIBIT
DATED FILE NO. NUMBER
- ------------------------- ----------- --------------
*February 1, 1919 2-2640 B-3
*December 1, 1920 2-2640 B-4
*October 1, 1921 2-2640 B-5
*September 1, 1922 2-2640 B-6
*June 1, 1925 2-2640 B-7
*March 1, 1929 2-2640 B-8
*July 1, 1930 2-2640 B-9
*June 1, 1931 2-2640 B-10
*November 1, 1934 2-2640 B-11
*May 1, 1935 2-2640 B-12
*July 1, 1935 2-2640 B-13
*December 1, 1936 2-3708 B-14
*June 15, 1938 1-1910-2 (Form 8-K Report for June 1938) 1
*June 1, 1939 2-4625 B-15
*January 1, 1941 2-6296 B-16
*April 1, 1946 2-7020 7-17
*March 1, 1948 1-1910-2 (Form 8-K Report for March 1948) 1
*December 19, 1949 2-8740 7-19
*December 20, 1949 2-8740 7-20
*June 15, 1950 2-8740 7-21
*January 15, 1951 2-9916 4-30
*June 1, 1953 2-9916 4-33
*July 15, 1954 2-11676 4-3
*December 1, 1955 2-13127 4-3
*March 1, 1958 1-1910-P (Form 8-A dated March 12, 1958) 1-2
*June 1, 1960 1-1910 (Form 8-K for June 1960) 1
*July 15, 1962 1-1910 (Form 8-K for July 1962) 1
*July 15, 1964 2-23763 2-3
*July 26, 1965 2-24800 2-3
*April 15, 1966 2-26278 4-3
*June 16, 1967 2-27005 2-3
*August 1, 1967 1-1910 (Form 10-K Annual Report for 1967) D-1
*December 15, 1968 1-1910 (Form 10-K Annual Report for 1968) D-1
*September 15, 1969 2-35453 2-6
*April 1, 1970 1-1910 (Form 8-A dated March 30, 1970) 2(b)
*July 1, 1970 1-1910 (Form 8-A dated June 30, 1970) 2(c)
*September 15, 1970 2-39561 2-4
*April 15, 1971 2-41252 2-4
*September 1, 1971 2-42574 2-4
*January 1, 1972 1-1910 (Form 10-K Annual Report for 1971) A-2
*July 1, 1972 2-45452 2-3
57
DESIGNATED IN
----------------------------------------------------------------------------------------
EXHIBIT
DATED FILE NO. NUMBER
- ------------------------- ----------- --------------
*September 15, 1972 1-1910 (Form 10-K Annual Report for 1972) A-1
*August 15, 1973 1-1910 (Form 8-K Report for August 1973) 3-4
*February 1, 1974 1-1910 (Form 10-K Annual Report for 1973) A-1
*July 1, 1974 1-1910 (Form 8-A dated July 5, 1974) 2(b)
*September 15, 1974 1-1910 (Form 8-A dated September 13, 1974) 2(b)
*August 1, 1975 1-1910 (Form 8-A dated August 5, 1975) 2(b)
*September 15, 1976 1-1910 (Form 8-A dated September 24, 1976) 2(b)
*July 15, 1977 2-59772 2-3
(3 Indentures)
*September 15, 1977 1-1910 (Form 8-A dated September 23, 1977) 2(c)
*July 1, 1978 1-1910 (Form 8-A dated June 30, 1978) 2(b)
*September 15, 1979 1-1910 (Form 10-Q dated November 14, 1979) 2-5 and 2-6
(2 Indentures)
*September 15, 1980 1-1910 (Form 8-A dated September 12, 1980) 2(b)
*July 8, 1981 1-1910 (Form 10-Q dated August 17, 1981) 20-2(c)
*October 1, 1981 1-1910 (Form 8-A dated September 29, 1981) 2(b)
*July 15, 1982 1-1910 (Form 8-A dated July 28, 1982) 2(b)
*March 1, 1986 1-1910 (Form 8-A dated February 24, 1986, as amended by Form 8 2
dated March 3, 1986)
*June 15, 1987 1-1910 (Form 8-K Report for July 29, 1987) 4(a)
*October 15, 1989 1-1910 (Form 10-Q dated November 14, 1989) 4(a)
*October 15, 1990 33-38803 (Form S-3 Registration) 4(a)
*August 15, 1991 33-45259 (Form S-3 Registration) 4(a)(i)
*January 15, 1992 33-45259 (Form S-3 Registration) 4(a)(ii)
*July 1, 1992 1-1910 (Form 8-K Report for January 29, 1993) 4(a)
*February 15, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(i)
*March 1, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(ii)
*March 15, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(iii)
*April 15, 1993 1-1910 (Form 10-Q dated May 13, 1993) 4
*July 1, 1993 1-1910 (Form 10-Q dated August 13, 1993) 4(a)
*July 15, 1993 1-1910 (Form 10-Q dated August 13, 1993) 4(b)
*October 15, 1993 1-1910 (Form 10-Q dated November 12, 1993) 4
March 15, 1994 (Filed Herewith) 4(a)
*4(b) -- Indenture dated July 1, 1985, between BGE and Mercantile-Safe Deposit and Trust Company,
Trustee. (Designated in Registration File No. 2-98443 as Exhibit 4(a)); as supplemented by
Supplemental Indentures dated as of October 1, 1987 (Designated in Form 8-K, dated
November 13, 1987, File No. 1-1910 as Exhibit 4(a)) and as of January 26, 1993 (Designated
in Form 8-K, dated January 29, 1993, File No. 1-1910 as Exhibit 4(b).)
*10(a) -- Baltimore Gas and Electric Company Executive Benefits Plan. (Designated as Exhibit No.
10(a) in the Form 10-K Annual Report for the year ended December 31, 1992, File No.
1-1910.)
10(b) -- Summary of amendment to the Baltimore Gas and Electric Company Executive Benefits Plan.
*10(c) -- Executive Incentive Plan of the Baltimore Gas and Electric Company. (Designated as Exhibit
No. 10(b) in the Form 10-K Annual Report for the year ended December 31, 1992, File No.
1-1910.)
*10(d) -- Baltimore Gas and Electric Company Long-Term Incentive Plan. (Designated as Exhibit No.
10(c) in the Form 10-K Annual Report for the year ended December 31, 1992, File No.
1-1910.)
*10(e) -- Baltimore Gas and Electric Company Non-qualified Deferred Compensation Plan for Executive
Officers. (Designated as Exhibit No. 10(d) in the Form 10-K Annual Report for the year
ended December 31, 1992, File No. 1-1910.)
58
EXHIBIT
NUMBER
- -----------
10(f) -- Baltimore Gas and Electric Company Non-qualified Deferred Compensation Plan for Non-
Employee Directors (formerly Baltimore Gas and Electric Company Deferred Compensation Plan
for Non-Employee Directors).
10(g) -- Baltimore Gas and Electric Company Retirement Plan for Non-Employee Directors, as amended
and restated.
10(h) -- Summary of Baltimore Gas and Electric Company Long Term Performance Program.
*10(i) -- Constellation Holdings, Inc., Summary of Executive Benefits Plan. (Designated as Exhibit
No. 10(f) in the Form 10-K Annual Report for the year ended December 31, 1992, File No.
1-1910.)
*10(j) -- Summary of Constellation Holdings, Inc. Annual Incentive Plan. (Designated as Exhibit No.
10(g) in the Form 10-K Annual Report for the year ended December 31, 1992, File No.
1-1910.)
10(k) -- Amended Summary 1992 Long Term Incentive Plan of Constellation Holdings, Inc.
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.
21 -- Subsidiaries of the Registrant.
23 -- Consent of Coopers & Lybrand, Independent Auditors (see page 73 in this Form 10-K).
*99(a) -- Indemnification of Directors and Officers of the Company. (Designated as Exhibit No. 28(a)
to the Annual Report on Form 10-K for the year ended December 31, 1988, File No. 1-1910.)
*99(b) -- Corporations and Associations Article, Section 2-418 of the Annotated Code of Maryland.
(Designated as Exhibit 28(b) to the Annual Report on Form 10-K for the year ended December
31, 1987, File No. 1-1910.)
- --------------------------
*Incorporated by Reference.
(b) Reports on Form 8-K: None
59
SCHEDULE V -- PROPERTY, PLANT AND EQUIPMENT
BALANCE, END OF YEAR
----------------------------
1993 1992
------------- -------------
(IN THOUSANDS)
UTILITY PLANT
Electric
Plant in Service
Intangible......................................................................... $ 12,017 $ 10,573
Production......................................................................... 3,409,980 3,307,453
Transmission....................................................................... 437,907 411,891
Distribution....................................................................... 1,726,010 1,634,357
General............................................................................ 127,345 110,316
Property Under Capital Leases........................................................ -- --
Plant Held for Future Use............................................................ 22,324 19,743
Construction Work in Progress........................................................ 385,207 273,140
Nuclear Fuel......................................................................... 856,406 809,077
------------- -------------
Total............................................................................ 6,977,196 6,576,550
------------- -------------
Gas
Plant in Service
Intangible......................................................................... 585 604
Production......................................................................... 15,710 15,101
Storage............................................................................ 23,547 21,519
Distribution....................................................................... 514,230 485,308
General............................................................................ 3,869 3,526
Construction Work in Progress........................................................ 26,582 18,632
------------- -------------
Total............................................................................ 584,523 544,690
------------- -------------
Common
Plant in Service
Intangible......................................................................... 70,892 69,176
General............................................................................ 416,848 399,087
Property Under Capital Leases........................................................ -- --
Plant Held for Future Use............................................................ 1,743 1,743
Construction Work in Progress........................................................ 24,651 17,136
------------- -------------
Total............................................................................ 514,134 487,142
------------- -------------
Total Utility Plant............................................................ 8,075,853 7,608,382
------------- -------------
OTHER PHYSICAL PROPERTY
Land, Aquaculture Facility, Merchandising Facilities, and Capital Leases............... 12,602 12,398
------------- -------------
Total Property, Plant and Equipment............................................ $ 8,088,455 $ 7,620,780
------------- -------------
------------- -------------
DIVERSIFIED BUSINESSES
Constellation Holdings, Inc............................................................ $ 518,274 $ 512,565
------------- -------------
------------- -------------
BNG, Inc............................................................................... $ 6,637 $ 8,848
------------- -------------
------------- -------------
1991
-------------
UTILITY PLANT
Electric
Plant in Service
Intangible......................................................................... $ 10,240
Production......................................................................... 3,217,154
Transmission....................................................................... 382,185
Distribution....................................................................... 1,503,798
General............................................................................ 101,974
Property Under Capital Leases........................................................ 48
Plant Held for Future Use............................................................ 16,247
Construction Work in Progress........................................................ 273,921
Nuclear Fuel......................................................................... 769,591
-------------
Total............................................................................ 6,275,158
-------------
Gas
Plant in Service
Intangible......................................................................... 487
Production......................................................................... 14,714
Storage............................................................................ 20,738
Distribution....................................................................... 455,695
General............................................................................ 3,316
Construction Work in Progress........................................................ 15,428
-------------
Total............................................................................ 510,378
-------------
Common
Plant in Service
Intangible......................................................................... 69,569
General............................................................................ 376,602
Property Under Capital Leases........................................................ 29
Plant Held for Future Use............................................................ 1,743
Construction Work in Progress........................................................ 18,416
-------------
Total............................................................................ 466,359
-------------
Total Utility Plant............................................................ 7,251,895
-------------
OTHER PHYSICAL PROPERTY
Land, Aquaculture Facility, Merchandising Facilities, and Capital Leases............... 10,797
-------------
Total Property, Plant and Equipment............................................ $ 7,262,692
-------------
-------------
DIVERSIFIED BUSINESSES
Constellation Holdings, Inc............................................................ $ 494,571
-------------
-------------
BNG, Inc............................................................................... $ 8,842
-------------
-------------
The information required by Columns B, C, D, and E is omitted because
neither the total additions nor the total deductions during the periods amounted
to more than 10% of the closing balances of total property, plant and equipment.
Additions and retirements of property, plant and equipment for 1991 through 1993
are set forth below.
1993 1992
---------- ----------
(IN THOUSANDS)
Additions, at cost
Other Than Nuclear Fuel........................................................................ 470,476 382,501
Nuclear Fuel................................................................................... 47,329 39,486
Other............................................................................................ (206) 901
Retirements, at cost or estimated amounts approximately book cost................................ 49,924 64,800
1991
------------
Additions, at cost
Other Than Nuclear Fuel........................................................................ 456,244
Nuclear Fuel................................................................................... 1,854
Other............................................................................................ 97,633*
Retirements, at cost or estimated amounts approximately book cost................................ 88,884**
- --------------------------
*The 1991 other includes $57,780,000 of AFC resulting from the adoption by the
Company of Statement of Financial Accounting Standards No. 109 and $40,259,000
of deferred income taxes on AFC in connection with adopting Statement of
Financial Accounting Standards No. 96.
**The 1991 retirements reflect the $46,031,000 retirement of the Riverside SNG
Plant.
60
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
SCHEDULE VI -- ACCUMULATED DEPRECIATION, DEPLETION AND
AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT
YEAR 1993
COLUMN C COLUMN E
COLUMN B ----------- --------------
------------- ADDITIONS COLUMN D OTHER CHANGES COLUMN F
COLUMN A BALANCE AT CHARGED TO ----------- -- ADD -------------
- ----------------------------------------------------- BEGINNING OF COSTS AND RETIREMENTS (DEDUCT) -- BALANCE AT
DESCRIPTION PERIOD EXPENSES (DEDUCT) DESCRIBE END OF PERIOD
- ----------------------------------------------------- ------------- ----------- ----------- -------------- -------------
(IN THOUSANDS)
Accumulated Provision for Depreciation of Utility
Plant:
Electric........................................... $ 1,709,591 $ 183,816 $ (27,643) $ (5,051)(A) $ 1,860,713
Gas................................................ 163,161 19,498 (4,682) (658)(A) 177,319
Common............................................. 86,732 21,232 (15,671) 3,112(A) 95,405
------------- ----------- ----------- ------- -------------
Total............................................ 1,959,484 224,546 (47,996) (2,597) 2,133,437
------------- ----------- ----------- ------- -------------
Accumulated Provision for Amortization of Utility
Plant............................................... 20,877 8,959 -- (1,289)(B) 28,547
------------- ----------- ----------- ------- -------------
Total Accumulated Provision for Depreciation and
Amortization of Utility Plant....................... $ 1,980,361 $ 233,505 $ (47,996) $ (3,886) $ 2,161,984
------------- ----------- ----------- ------- -------------
------------- ----------- ----------- ------- -------------
Accumulated Provision for Amortization of Nuclear
Fuel Assemblies..................................... $ 708,977
-------------
-------------
Accumulated Provision for Amortization of Other
Physical Property................................... $ 2,471
-------------
-------------
Accumulated Provision for Amortization and
Depreciation of Property of:
Constellation Holdings, Inc........................ $ 27,901
-------------
-------------
BNG, Inc........................................... $ 3,312
-------------
-------------
- --------------------------
(A) Represents principally net cost of removal and salvage applicable to
retired property.
(B) Represents principally write-off of equipment which is fully amortized.
NOTE: For a statement of the Company's depreciation policy, see NOTE 1 TO
CONSOLIDATED FINANCIAL STATEMENTS. The Company's Accumulated Provision for
Depreciation is not segregated according to the "Classification" of
property shown under "Plant in Service" in Schedule V.
61
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
SCHEDULE VI -- ACCUMULATED DEPRECIATION, DEPLETION AND
AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT
YEAR 1992
COLUMN E
COLUMN C --------------
COLUMN B ----------- OTHER CHANGES
------------- ADDITIONS COLUMN D -- COLUMN F
COLUMN A BALANCE AT CHARGED TO ----------- ADD (DEDUCT) -------------
- ----------------------------------------------------- BEGINNING OF COSTS AND RETIREMENTS -- BALANCE AT
DESCRIPTION PERIOD EXPENSES (DEDUCT) DESCRIBE END OF PERIOD
- ----------------------------------------------------- ------------- ----------- ----------- -------------- -------------
(IN THOUSANDS)
Accumulated Provision for Depreciation of Utility
Plant:
Electric........................................... $ 1,579,290 $ 173,461 $ (41,968) $ (1,192)(A) $ 1,709,591
Gas................................................ 148,002 18,517 (2,556) (802)(A) 163,161
Common............................................. 79,341 22,107 (16,623) 1,907(A) 86,732
------------- ----------- ----------- ------- -------------
Total............................................ 1,806,633 214,085 (61,147) (87) 1,959,484
------------- ----------- ----------- ------- -------------
Accumulated Provision for Amortization of Utility
Plant............................................... 15,747 8,587 -- (3,457)(B) 20,877
------------- ----------- ----------- ------- -------------
Total Accumulated Provision for Depreciation and
Amortization of Utility Plant....................... $ 1,822,380 $ 222,672 $ (61,147) $ (3,544) $ 1,980,361
------------- ----------- ----------- ------- -------------
------------- ----------- ----------- ------- -------------
Accumulated Provision for Amortization of Nuclear
Fuel Assemblies..................................... $ 659,697
-------------
-------------
Accumulated Provision for Amortization of Other
Physical Property................................... $ 2,341
-------------
-------------
Accumulated Provision for Amortization and
Depreciation of Property of:
Constellation Holdings, Inc........................ $ 26,998
-------------
-------------
BNG, Inc. ......................................... $ 4,927
-------------
-------------
- --------------------------
(A) Represents principally net cost of removal and salvage applicable to
retired property.
(B) Represents principally write-off of equipment which is fully amortized.
NOTE: For a statement of the Company's depreciation policy, see NOTE 1 TO
CONSOLIDATED FINANCIAL STATEMENTS. The Company's Accumulated Provision for
Depreciation is not segregated according to the "Classification" of
property shown under "Plant in Service" in Schedule V.
62
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
SCHEDULE VI -- ACCUMULATED DEPRECIATION, DEPLETION AND
AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT
YEAR 1991
COLUMN E
COLUMN C --------------
COLUMN B ----------- OTHER
------------- ADDITIONS COLUMN D CHANGES -- COLUMN F
COLUMN A BALANCE AT CHARGED TO ----------- ADD (DEDUCT) -------------
- ----------------------------------------------------- BEGINNING OF COSTS AND RETIREMENTS -- BALANCE AT
DESCRIPTION PERIOD EXPENSES (DEDUCT) DESCRIBE END OF PERIOD
- ----------------------------------------------------- ------------- ----------- ----------- -------------- -------------
(IN THOUSANDS)
Accumulated Provision for Depreciation of Utility
Plant:
Electric........................................... $ 1,434,259 $ 154,962 $ (31,599) $ 21,668(A) $ 1,579,290
Gas................................................ 180,050 16,049 (44,663) (3,434)(B) 148,002
Common............................................. 69,193 18,838 (9,393) 703(B) 79,341
------------- ----------- ----------- -------------- -------------
Total............................................ 1,683,502 189,849 (85,655) 18,937 1,806,633
------------- ----------- ----------- -------------- -------------
Accumulated Provision for Amortization of Utility
Plant............................................... 10,664 7,893 -- (2,810)(C) 15,747
------------- ----------- ----------- -------------- -------------
Total Accumulated Provision for Depreciation and
Amortization of Utility Plant....................... $ 1,694,166 $ 197,742 $ (85,655) $ (16,127) $ 1,822,380
------------- ----------- ----------- -------------- -------------
------------- ----------- ----------- -------------- -------------
Accumulated Provision for Amortization of Nuclear
Fuel Assemblies..................................... $ 616,709
-------------
-------------
Accumulated Provision for Amortization of Other
Physical Property................................... $ 1,891
-------------
-------------
Accumulated Provision for Amortization and
Depreciation of Property of:
Constellation Holdings, Inc........................ $ 19,889
-------------
-------------
BNG, Inc........................................... $ 4,274
-------------
-------------
- --------------------------
(A) Represents principally AFC resulting from the adoption by the Company of
Statement of Financial Accounting Standards No. 109.
(B) Represents principally net cost of removal and salvage applicable to
retired property.
(C) Represents principally write-off of utility plant which is fully
amortized.
NOTE: For a statement of the Company's depreciation policy, see NOTE 1 TO
CONSOLIDATED FINANCIAL STATEMENTS. The Company's Accumulated Provision for
Depreciation is not segregated according to the "Classification" of
property shown under "Plant in Service" in Schedule V.
63
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
SCHEDULE VII -- GUARANTEES OF SECURITIES OF OTHER ISSUERS
AS OF DECEMBER 31, 1993
COLUMN G
--------------------
NATURE OF ANY
COLUMN E DEFAULT BY ISSUER OF
COLUMN B COLUMN D ---------- SECURITIES
COLUMN A ------------- --------------- AMOUNT IN GUARANTEED IN
- ------------------------ TITLE OF COLUMN C AMOUNT OWNED BY TREASURY PRINCIPAL, INTEREST,
NAME OF ISSUER OF ISSUE OF EACH --------------- PERSON OR OF ISSUER COLUMN F SINKING FUND OR
SECURITIES CLASS OF TOTAL AMOUNT PERSONS FOR OF ------------- REDEMPTION
GUARANTEED BY PERSON FOR SECURITIES GUARANTEED AND WHICH STATEMENT SECURITIES NATURE OF PROVISIONS, OR
WHICH STATEMENT IS FILED GUARANTEED OUTSTANDING IS FILED GUARANTEED GUARANTEE PAYMENT OF DIVIDENDS
- ------------------------ ------------- --------------- --------------- ---------- ------------- --------------------
(IN THOUSANDS)
BGE:
Safe Harbor Water Power
Corporation............ Serial Notes $ 26,667(A) -- -- Principal and --
interest (C)
CONSTELLATION COMPANIES:
Puna.................... Note(s) (B) 15,000 -- -- Principal and Default (D)
interest (C)
Aspenwood L.P........... Note(s) (B) 9,953 -- -- Principal and --
interest (C)
Piney Orchard L.P....... Note(s) (B) 6,909 -- -- Principal and --
interest (C)
Pacific-Ultrapower
Chinese Station........ Note(s) (B) 5,637 -- -- Principal and --
interest (C)
Sunrise Falls Church.... Note(s) (B) 4,950 -- -- Principal and --
interest (C)
Jolly Acres L.P......... Note(s) (B) 2,593 -- -- Principal and --
interest (C)
Mammoth Lakes........... Note(s) (B) 1,765 -- -- Principal and --
interest (C)
Ace Cogeneration
Company................ Note(s) (B) 1,750 -- -- Principal and --
interest (C)
Troutman................ Note(s) (B) 840 -- -- Principal and --
interest (C)
Constellation Real
Estate, Inc............ Note(s) (B) 355 -- -- Principal and --
interest (C)
Hickory Ridge........... Note(s) (B) 186 -- -- Principal and --
interest (C)
Panther Creek........... Note(s) (E) 37 -- -- Rent (E) --
---------------
$ 76,642
---------------
---------------
- ----------------------------------
(A) BGE has agreed to guarantee 66 2/3% of up to $125 million of indebtedness
incurred by Safe Harbor Water Power Corporation in connection with the
1985-1986 expansion of its hydroelectric generating facilities. Such
borrowings are to mature in various years through 2001. The outstanding
loans totaled $40,000,000 and $45,000,000 as of December 31, 1993 and
1992, respectively, of which $26,666,667 and $30,000,000, respectively,
was guaranteed by BGE. Also, as of December 31, 1993, interest payable on
the loans totaled $779,167 of which $519,445 is guaranteed by BGE.
(B) Wholly owned subsidiaries of Constellation Holdings, Inc. have guaranteed
loans for power facilities and real estate projects.
(C) No material amount of interest was outstanding during the period as
substantially all interest is due and has been paid monthly, quarterly, or
semi-annually on the related notes.
(D) As of December 31, 1993, the Puna debt is in technical default due to a
delay in converting the construction debt to permanent financing. No
formal default notice has been issued concerning these delays. None of the
Constellation Companies was the borrower under the Puna debt that was in
default, and none of the Constellation Companies defaulted on its guaranty
obligations relating to such debt.
(E) A wholly owned subsidiary of Constellation Holdings, Inc. has made a rent
guarantee for an energy project.
64
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
SCHEDULE VIII -- VALUATION AND QUALIFYING ACCOUNTS
COLUMN C
COLUMN B ------------------------------
--------
BALANCE ADDITIONS COLUMN E
AT ------------------------------ COLUMN D ----------
COLUMN A BEGINNING CHARGED TO CHARGED TO OTHER ---------------- BALANCE AT
- ----------------------------------------------------- OF COSTS AND ACCOUNTS -- (DEDUCTIONS) -- END OF
DESCRIPTION PERIOD EXPENSES DESCRIBE DESCRIBE PERIOD
- ----------------------------------------------------- -------- ------------ ---------------- ---------------- ----------
(IN THOUSANDS)
Reserves deducted in the Balance Sheet from the
assets to which they apply:
Accumulated Provision for Uncollectibles
1993............................................. $ 12,484 $ 19,155 $ -- $ (17,682)(A) $ 13,957
1992............................................. 11,911 18,910 -- (18,337)(A) 12,484
1991............................................. 10,708 15,095 -- (13,892)(A) 11,911
Valuation Allowance --
Net unrealized loss on marketable securities
1993............................................. -- -- -- -- --
1992............................................. -- -- -- -- --
1991............................................. 13,988 -- -- (13,988)(B) --
Provision for possible disallowance of replacement
energy costs
1993............................................. 35,000 -- -- -- 35,000
1992............................................. 35,000 -- -- -- 35,000
1991............................................. 35,000 -- -- -- 35,000
Loan loss reserve
1993............................................. 4,382 741 -- -- 5,123
1992............................................. 3,856 526 -- -- 4,382
1991............................................. -- 3,856 -- -- 3,856
Energy project reserves
1993............................................. 492 1,286 -- -- 1,778
1992............................................. 494 -- -- (2)(C) 492
1991............................................. 63 555 -- (124)(C) 494
- --------------------------
(A) Represents principally net amounts charged off as uncollectible.
(B) Represents change in common shareholders' equity to reflect reversal of
previous temporary decline in market value of subsidiary's noncurrent
investment securities.
(C) Represents recovery of subsidiary's project development costs previously
reversed as uncollectible.
65
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, Baltimore Gas and Electric Company, the Registrant, has
duly caused this Report to be signed on its behalf by the undersigned, thereunto
duly authorized.
BALTIMORE GAS AND ELECTRIC COMPANY
(Registrant)
Date: March 18, 1994 By /s/ C. H. POINDEXTER
-------------------------------------------------
C. H. Poindexter
CHAIRMAN OF THE BOARD
Pursuant to the requirements of the Securities Exchange Act of 1934, this
Report has been signed below by the following persons on behalf of Baltimore Gas
and Electric Company, the Registrant, and in the capacities and on the dates
indicated.
SIGNATURE TITLE DATE
- ------------------------------------------------------------------------------------ ---------------------- -------------------
Principal executive officer and director:
By /s/ C. H. POINDEXTER
-------------------------------------------------------------------------------- Chairman of the Board March 18, 1994
C. H. Poindexter and Director
Principal financial and accounting officer:
By /s/ C. W. SHIVERY
-------------------------------------------------------------------------------- Vice President and March 18, 1994
C. W. Shivery Secretary
Directors:
/s/ H. F. BALDWIN
- ----------------------------------------------------------------------------------- Director March 18, 1994
H. F. Baldwin
/s/ B. B. BYRON
- ----------------------------------------------------------------------------------- Director March 18, 1994
B. B. Byron
/s/ J. O. COLE
- ----------------------------------------------------------------------------------- Director March 18, 1994
J. O. Cole
/s/ D. A. COLUSSY
- ----------------------------------------------------------------------------------- Director March 18, 1994
D. A. Colussy
/s/ E. A. CROOKE
- ----------------------------------------------------------------------------------- Director March 18, 1994
E. A. Crooke
/s/ J. R. CURTISS
- ----------------------------------------------------------------------------------- Director March 18, 1994
J. R. Curtiss
/s/ J. W. GECKLE
- ----------------------------------------------------------------------------------- Director March 18, 1994
J. W. Geckle
/s/ F. A. HRABOWSKI III
- ----------------------------------------------------------------------------------- Director March 18, 1994
F. A. Hrabowski III
/s/ N. LAMPTON
- ----------------------------------------------------------------------------------- Director March 18, 1994
N. Lampton
/s/ G. V. MCGOWAN
- ----------------------------------------------------------------------------------- Director March 18, 1994
G. V. McGowan
/s/ P. G. MILLER
- ----------------------------------------------------------------------------------- Director March 18, 1994
P. G. Miller
/s/ G. L. RUSSELL, JR.
- ----------------------------------------------------------------------------------- Director March 18, 1994
G. L. Russell, Jr.
/s/ M. D. SULLIVAN
- ----------------------------------------------------------------------------------- Director March 18, 1994
M. D. Sullivan
66
EXHIBIT INDEX
EXHIBIT PAGE
NUMBER NUMBER
- ------------ ---------
*3(a) --
*3(b) --
4(a) 70 --
EXHIBIT
NUMBER
- ------------
*3(a) Charter of BGE, restated as of October 13, 1993. (Designated as Exhibit No. 3(b) in Form 10-Q dated November
12, 1993, File No. 1-1910.)
*3(b) By-Laws of BGE, as amended to March 1, 1993. (Designated as Exhibit No. 3(c) in Form 10-K Annual Report for
1992, File No. 1-1910.)
4(a) Indenture and Supplemental Indentures between BGE and Bankers Trust Company, Trustee:
DESIGNATED IN
----------------------------------------------------------------------------------
EXHIBIT
DATED FILE NO. NUMBER
------------------------- ----------- --------------
*February 1, 1919 2-2640 B-3
*December 1, 1920 2-2640 B-4
*October 1, 1921 2-2640 B-5
*September 1, 1922 2-2640 B-6
*June 1, 1925 2-2640 B-7
*March 1, 1929 2-2640 B-8
*July 1, 1930 2-2640 B-9
*June 1, 1931 2-2640 B-10
*November 1, 1934 2-2640 B-11
*May 1, 1935 2-2640 B-12
*July 1, 1935 2-2640 B-13
*December 1, 1936 2-3708 B-14
*June 15, 1938 1-1910-2 (Form 8-K Report for June 1938) 1
*June 1, 1939 2-4625 B-15
*January 1, 1941 2-6296 B-16
*April 1, 1946 2-7020 7-17
*March 1, 1948 1-1910-2 (Form 8-K Report for March 1948) 1
*December 19, 1949 2-8740 7-19
*December 20, 1949 2-8740 7-20
*June 15, 1950 2-8740 7-21
*January 15, 1951 2-9916 4-30
*June 1, 1953 2-9916 4-33
*July 15, 1954 2-11676 4-3
*December 1, 1955 2-13127 4-3
*March 1, 1958 1-1910-P (Form 8-A dated March 12, 1958) 1-2
*June 1, 1960 1-1910 (Form 8-K for June 1960) 1
*July 15, 1962 1-1910 (Form 8-K for July 1962) 1
*July 15, 1964 2-23763 2-3
*July 26, 1965 2-24800 2-3
*April 15, 1966 2-26278 4-3
*June 16, 1967 2-27005 2-3
*August 1, 1967 1-1910 (Form 10-K Annual Report for 1967) D-1
*December 15, 1968 1-1910 (Form 10-K Annual Report for 1968) D-1
*September 15, 1969 2-35453 2-6
*April 1, 1970 1-1910 (Form 8-A dated March 30, 1970) 2(b)
*July 1, 1970 1-1910 (Form 8-A dated June 30, 1970) 2(c)
*September 15, 1970 2-39561 2-4
*April 15, 1971 2-41252 2-4
*September 1, 1971 2-42574 2-4
*January 1, 1972 1-1910 (Form 10-K Annual Report for 1971) A-2
*July 1, 1972 2-45452 2-3
*September 15, 1972 1-1910 (Form 10-K Annual Report for 1972) A-1
*August 15, 1973 1-1910 (Form 8-K Report for August 1973) 3-4
67
DESIGNATED IN
----------------------------------------------------------------------------------
EXHIBIT
DATED FILE NO. NUMBER
------------------------- ----------- --------------
*February 1, 1974 1-1910 (Form 10-K Annual Report for 1973) A-1
*July 1, 1974 1-1910 (Form 8-A dated July 5, 1974) 2(b)
*September 15, 1974 1-1910 (Form 8-A dated September 13, 1974) 2(b)
*August 1, 1975 1-1910 (Form 8-A dated August 5, 1975) 2(b)
*September 15, 1976 1-1910 (Form 8-A dated September 24, 1976) 2(b)
*July 15, 1977 2-59772 2-3
(3 Indentures)
*September 15, 1977 1-1910 (Form 8-A dated September 23, 1977) 2(c)
*July 1, 1978 1-1910 (Form 8-A dated June 30, 1978) 2(b)
*September 15, 1979 1-1910 (Form 10-Q dated November 14, 1979) 2-5 and 2-6
(2 Indentures)
*September 15, 1980 1-1910 (Form 8-A dated September 12, 1980) 2(b)
*July 8, 1981 1-1910 (Form 10-Q dated August 17, 1981) 20-2(c)
*October 1, 1981 1-1910 (Form 8-A dated September 29, 1981) 2(b)
*July 15, 1982 1-1910 (Form 8-A dated July 28, 1982) 2(b)
*March 1, 1986 1-1910 (Form 8-A dated February 24, 1986, as amended by Form 2
8 dated March 3, 1986)
*June 15, 1987 1-1910 (Form 8-K Report for July 29, 1987) 4(a)
*October 15, 1989 1-1910 (Form 10-Q dated November 14, 1989) 4(a)
*October 15, 1990 33-38803 (Form S-3 Registration) 4(a)
*August 15, 1991 33-45259 (Form S-3 Registration) 4(a)(i)
*January 15, 1992 33-45259 (Form S-3 Registration) 4(a)(ii)
*July 1, 1992 1-1910 (Form 8-K Report for January 29, 1993) 4(a)
*February 15, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(i)
*March 1, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(ii)
*March 15, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(iii)
*April 15, 1993 1-1910 (Form 10-Q dated May 13, 1993) 4
*July 1, 1993 1-1910 (Form 10-Q dated August 13, 1993) 4(a)
*July 15, 1993 1-1910 (Form 10-Q dated August 13, 1993) 4(b)
*October 15, 1993 1-1910 (Form 10-Q dated November 12, 1993) 4
70 March 15, 1994 (Filed Herewith) 4(a)
*4(b) -- Indenture dated July 1, 1985, between BGE and Mercantile-Safe Deposit and Trust
Company, Trustee. (Designated in Registration File No. 2-98443 as Exhibit 4(a)); as
supplemented by Supplemental Indentures dated as of October 1, 1987 (Designated in
Form 8-K, dated November 13, 1987, File No. 1-1910 as Exhibit 4(a)) and as of
January 26, 1993 (Designated in Form 8-K, dated January 29, 1993, File No. 1-1910 as
Exhibit 4(b).)
*10(a) -- Baltimore Gas and Electric Company Executive Benefits Plan. (Designated as Exhibit
No. 10(a) in the Form 10-K Annual Report for the year ended December 31, 1992, File
No. 1-1910.)
10(b) 78 -- Summary of amendment to the Baltimore Gas and Electric Company Executive Benefits
Plan.
*10(c) -- Executive Incentive Plan of the Baltimore Gas and Electric Company. (Designated as
Exhibit No. 10(b) in the Form 10-K Annual Report for the year ended December 31,
1992, File No. 1-1910.)
*10(d) -- Baltimore Gas and Electric Company Long-Term Incentive Plan. (Designated as Exhibit
No. 10(c) in the Form 10-K Annual Report for the year ended December 31, 1992, File
No. 1-1910.)
*10(e) -- Baltimore Gas and Electric Company Non-qualified Deferred Compensation Plan for
Executive Officers. (Designated as Exhibit No. 10(d) in the Form 10-K Annual Report
for the year ended December 31, 1992, File No. 1-1910.)
68
EXHIBIT PAGE
NUMBER NUMBER
- ----------- ---------
10(f) 79 -- Baltimore Gas and Electric Company Non-qualified Deferred Compensation Plan for Non-
Employee Directors (formerly Baltimore Gas and Electric Company Deferred
Compensation Plan for Non-Employee Directors).
10(g) 82 -- Baltimore Gas and Electric Company Retirement Plan for Non-Employee Directors, as
amended and restated.
10(h) 83 -- Summary of Baltimore Gas and Electric Company Long Term Performance Program.
*10(i) -- Constellation Holdings, Inc., Summary of Executive Benefits Plan. (Designated as
Exhibit No. 10(f) in the Form 10-K Annual Report for the year ended December 31,
1992, File No. 1-1910.)
*10(j) -- Summary of Constellation Holdings, Inc. Annual Incentive Plan. (Designated as Exhibit
No. 10(g) in the Form 10-K Annual Report for the year ended December 31, 1992, File
No. 1-1910.)
10(k) 84 -- Amended Summary 1992 Long Term Incentive Plan of Constellation Holdings, Inc.
12 85 -- Computation of Ratio of Earnings to Fixed Charges and Computation of Ratio of
Earnings to Combined Fixed Charges and Preferred and Preference Dividend
Requirements.
21 86 -- Subsidiaries of the Registrant.
23 87 -- Consent of Coopers & Lybrand, Independent Auditors (see page 73 in this Form 10-K).
*99(a) -- Indemnification of Directors and Officers of the Company. (Designated as Exhibit No.
28(a) to the Annual Report on Form 10-K for the year ended December 31, 1988, File
No. 1-1910.)
*99(b) -- Corporations and Associations Article, Section 2-418 of the Annotated Code of
Maryland. (Designated as Exhibit 28(b) to the Annual Report on Form 10-K for the
year ended December 31, 1987, File No. 1-1910.)
- --------------------------
*Incorporated by Reference.
69