SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
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, 1994 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,
BALTIMORE, MARYLAND 21201
(Address of principal executive offices) (Zip Code)
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
Common Stock -- Without Par Value New York Stock Exchange, Inc.
Common Stock -- Without Par Value Chicago Stock Exchange, Inc.
Common Stock -- Without Par Value 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: Philadelphia Stock Exchange, Inc.
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, 1995 was approximately
$3,602,357,255 based upon New York Stock Exchange composite transaction
closing price.
COMMON STOCK, WITHOUT PAR VALUE -- 147,527,114 SHARES
OUTSTANDING ON FEBRUARY 28, 1995.
DOCUMENTS INCORPORATED BY REFERENCE
PART OF FORM 10-K DOCUMENT INCORPORATED BY REFERENCE
III Definitive Proxy Statement for the Annual Meeting of Shareholders of Baltimore Gas and
Electric Company to be held on April 18, 1995 (Proxy Statement).
TABLE OF CONTENTS
PAGE
PART I
Item 1 -- Business
General..................................................................................... 1
Capital Requirements........................................................................ 2
Regulatory Matters and Competition.......................................................... 3
Rate Matters................................................................................ 4
Nuclear Operations.......................................................................... 4
Electric Load Management, Energy, and Capacity Purchases.................................... 6
Fuel for Electric Generation................................................................ 7
Gas Operations.............................................................................. 8
Environmental Matters....................................................................... 9
Electric Operating Statistics............................................................... 12
Gas Operating Statistics.................................................................... 13
Franchises.................................................................................. 14
Diversified Businesses...................................................................... 14
Employees................................................................................... 16
Item 2 -- Properties.................................................................................. 17
Item 3 -- Legal Proceedings........................................................................... 17
Item 4 -- Submission of Matters to a Vote of Security Holders......................................... 18
Item 10 -- Executive Officers of the Registrant (Instruction 3 to Item 401(b) of Regulation S-K)....... 19
PART II
Item 5 -- Market for Registrant's Common Equity and Related Stockholder Matters....................... 20
Item 6 -- Selected Financial Data..................................................................... 21
Item 7 -- Management's Discussion and Analysis of Financial Condition and Results of
Operations.................................................................................. 22
Item 8 -- Financial Statements and Supplementary Data................................................. 30
Item 9 -- Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure.................................................................................. 54
PART III
Item 10 -- Directors and Executive Officers of the Registrant.......................................... 54
Item 11 -- Executive Compensation...................................................................... 54
Item 12 -- Security Ownership of Certain Beneficial Owners and Management.............................. 54
Item 13 -- Certain Relationships and Related Transactions.............................................. 54
PART IV
Item 14 -- Exhibits, Financial Statement Schedules and Reports on Form 8-K............................. 54
Signatures................................................................................................. 59
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 two wholly owned subsidiaries of BGE, Constellation
Holdings, Inc. and its subsidiaries (collectively, the Constellation
Companies) and BGE Home Products & Services, Inc. (HPS) and its
subsidiary Maryland Environmental Systems, Inc. (MES).
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 engages
in natural gas brokering. 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 2,625,000. The gas service
territory includes an area of approximately 627 square miles with an
estimated population of 1,980,000. There are no municipal or cooperative
bulk power markets within BGE's service territory.
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. (SEE NUCLEAR OPERATIONS AND
NOTE 13 TO CONSOLIDATED FINANCIAL STATEMENTS for information regarding
prior outages at the Plant.) Also, the utility industry is facing
potentially substantial regulatory change designed to foster competition
in the provision of gas and electric services. It is not possible to
predict the ultimate effect competition will have on BGE's earnings in
future years. These matters are discussed under REGULATORY MATTERS AND
COMPETITION on page 3.
Diversified businesses conducted by the Constellation Companies,
HPS and MES are discussed under DIVERSIFIED BUSINESSES on page 14 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
1994............................... 76% 15 % 9% 85% 6 % 9%
1993............................... 77 16 7 87 6 7
1992............................... 77 16 7 82 8 10
1991............................... 79 14 7 90 6 4
1990............................... 76 17 7 80 10 10
<FN>
Certain prior-year amounts have been reclassified to conform to the
current year's presentation.
*Net of income taxes.
BGE currently derives approximately 23% of electric revenues and
43% of gas revenues from customers located in the City of Baltimore and
77% and 57%, 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.
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
1
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 $4.7 billion while the comparable
investment in its gas business is approximately $500 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 (53%) is greater than electric fuel and
purchased energy as a percentage of electric revenues (26%). 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 1992 through 1994,
along with estimated amounts for 1995 through 1997, are set forth below:
1992 1993 1994 1995 1996 1997
(IN MILLIONS)
Utility Business
Construction expenditures (excluding AFC)
Electric.................................................. $ 292 $ 360 $ 339 $ 233 $ 219 $ 206
Gas....................................................... 36 51 68 61 71 84
Common.................................................... 39 44 42 56 50 35
Total construction expenditures......................... 367 455 449 350 340 325
AFC (a)...................................................... 22 23 34 35 18 13
Nuclear fuel (uranium purchases and processing charges)...... 40 47 42 48 50 52
Deferred energy conservation expenditures (b)................ 20 33 41 44 43 29
Deferred nuclear expenditures (b)............................ 16 14 8 - - -
Retirement of long-term debt and redemption of preference
stock..................................................... 486 907 203 268 98 164
Total utility business.................................. 951 1,479 777 745 549 583
Diversified Businesses......................................... 198 300 88 122 135 165
Total................................................... $ 1,149 $ 1,779 $ 865 $ 867 $ 684 $ 748
<FN>
(a) Allowance for Funds Used During Construction (AFC) is accrued for
all construction projects with a construction period of more than
one month. (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.
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 29.
BGE's estimated construction, nuclear fuel, and deferred energy
conservation expenditures are expected to amount to approximately $1.7
billion, $260 million, and $170 million, respectively, for the five-year
period 1995-1999. Electric construction expenditures reflect the
installation of two 5,000-kilowatt diesel generators at Calvert Cliffs
Nuclear Power Plant, one of which is scheduled to be placed in service
in 1995 and the second in 1996; the construction of a 140-megawatt
combustion turbine at Perryman, scheduled to be placed in service in
1995, which the Public Service Commission of Maryland (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.
2
During the period January 1, 1990 through December 31, 1994, BGE
expended $2,349 million for gross additions to utility plant or
approximately 31% of its total utility plant (exclusive of nuclear fuel)
at December 31, 1994. During the same period, a total of $338 million of
utility plant was retired. Nuclear fuel expenditures include uranium
purchases and processing charges.
BGE presently estimates that approximately $900 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 1995-1999.
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.
REGULATORY MATTERS AND COMPETITION
Regulatory changes in the natural gas business are well under way.
In 1992, the Federal Energy Regulatory Commission (FERC) issued Order
636, which unbundled gas-service elements. This gave gas users the
ability to choose various gas purchasing, transportation, brokering, and
storage options. Prior to Order 636, BGE purchased gas, transportation
and storage services primarily from pipeline companies. Now, BGE and
other local distribution companies buy gas directly from various
suppliers and arrange separately for transportation and storage. BGE's
large gas customers are arranging for their own gas supplies and are
contracting with BGE for transportation. The PSC is encouraging BGE and
other utilities to offer options for unbundling the gas services offered
by local distribution companies and allowing smaller customers to
arrange for their own gas supplies.
Regulatory changes in the electric business are in process. FERC is
implementing the Energy Policy Act of 1992, focusing upon promoting
efficiency by creating a competitive bulk power market through equal
access to utility transmission systems. FERC also is examining the role
of power pooling and electric utility restructuring in an era of
increased competition. FERC has indicated its intent to determine terms
for the industry about open-access transmission, comparable transmission
service and recovery of stranded costs in the near future.
State regulators around the United States are also redefining the
regulatory scheme for the electric utility industry. In September, 1994,
the PSC announced it would hold hearings in 1995 to consider electric
utility restructuring, the impact of competition, and regulatory reform.
The PSC issued a paper defining possible scenarios ranging from limited
to full competition. The PSC plans to issue a general policy statement
in June, 1995 on changes recommended for Maryland's electric industry.
BGE is unable to predict what position the PSC will take or the impact,
if any, on its financial condition or competitive position.
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 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 the future.
In BGE's last rate proceeding, the PSC directed that an independent
study be performed regarding the distribution of costs between BGE's
regulated utility operations and unregulated merchandise and appliance
services activities. During that rate proceeding, a coalition of HVAC
contractors had alleged that the unregulated operations were being
subsidized by the utility. A subsequent proceeding was held to examine
the Company's allocation procedures as well as to deal with the demand
by the coalition that the unregulated activities be required to pay a
royalty based on unregulated revenues to compensate ratepayers for the
use of the BGE name and its goodwill. In July, 1994, BGE formed its HPS
subsidiary to conduct its merchandise and appliance service activities.
When HPS acquired MES in December, 1994, these activities expanded into
HVAC installation and servicing. On December 30, 1994, the Hearing
Examiner in the cost allocation case made a finding that HPS should be
required to pay BGE a royalty payment equivalent to 2% of its gross
revenues. BGE strongly disagrees with the reasoning set forth in the
Hearing Examiner's opinion and has appealed this matter to the PSC. If
the order were allowed to stand, it would be virtually impossible to
profitably operate HPS as a subsidiary of BGE.
In response to the competitive forces and regulatory changes under
consideration at the PSC and FERC, as discussed above, BGE from time to
time will consider various strategies designed to enhance its
competitive position and to increase its ability to adapt to and
anticipate regulatory changes in its utility business. These strategies
may include internal restructurings involving the complete or partial
separation of its generation, transmission and distribution businesses,
acquisitions of related or unrelated businesses, business combinations,
and additions to or dispositions of portions of its franchised service
territories. BGE and its subsidiaries may from
3
time to time be engaged in preliminary discussions, either internally or
with third parties, regarding one or more of these potential strategies.
No assurances can be given as to whether any potential transaction of
the type described above may actually occur, or as to the ultimate
effect thereof on the financial condition or competitive position of
BGE.
RATE MATTERS
REVISED DEPRECIATION RATES
The PSC issued an Order, which became effective in January, 1995,
adjusting BGE's utility plant depreciation rates to reflect the results
of a detailed depreciation study. The new depreciation rates are
expected to result in an increase in depreciation accruals of
approximately $21 million annually. BGE plans to defer the increased
depreciation accruals for recovery in future base rate proceedings,
consistent with previous rate actions of the PSC.
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 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. 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 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.
4
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 alleged that a
number of the outages at the Plant, including the 66-day outage to
document compliance with NRC mandated environmental qualification
requirements, were due to management imprudence and requested that the
PSC disallow recovery of the associated replacement energy costs which
BGE estimated to be approximately $33 million. On January 23, 1995, the
Hearing Examiner issued his decision in the 1987 fuel rate proceeding
and found that the Company had met the GUPP standard which establishes a
presumption that BGE had operated the Plant at a reasonably productive
capacity level. However, the Order found that the presumption of
reasonableness would be overcome by a showing of mismanagement and that
such a showing was made with respect to the environmental qualifications
outage time. In mitigation for meeting the GUPP standard, the Hearing
Examiner disallowed replacement energy costs recovery for 15.5 days of
the 66-day outage time. The Hearing Examiner's Order was appealed to the
PSC by both BGE and People's Counsel. If the PSC upholds the Hearing
Examiner, the Company's earnings would be impacted by approximately $4.5
million.
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.
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 is 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
5
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 filed
rebuttal testimony in January 1995 in which it vigorously contested the
findings of Staff and People's Counsel. Further hearings in this matter
are not expected until 1996.
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 SUBSEQUENT TO THE EXTENDED OUTAGE
The Plant generated 10,663,950 MWH in 1992, which resulted in a
capacity factor of 74%. There were no contested performance issues based
on 1992 performance. The Plant generated 12,300,816 MWH in 1993, which
resulted in a capacity factor of 85%. In 1994, the Plant generated
11,225,977 MWH achieving a capacity factor of 77%. Review of the GUPP
filings in 1993 and 1994 have not been completed, but BGE is not aware
of any significant performance issues in either of these years.
ELECTRIC 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 1995 from active load management is expected to be
approximately 430 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.
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 FERC, is
designed to help maintain adequate reserve margins through this decade
and provide flexibility in meeting capacity obligations. The PP&L
agreement entitles BGE to 5.94% of the energy output, and net capacity
(currently 127 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, 1994 represented 170 MW of rated
6
zcapacity of Bethlehem Steel Corporation's Sparrows Point complex, 57 MW
of rated capacity of the Baltimore Refuse Energy Systems Company, and
the 127 MW of Susquehanna capacity from PP&L.
In 1994 PECO Energy won a competitive bidding program to supply 140
MW for firm electric capacity and associated energy for 25 years
beginning June 1, 1997. FERC acceptance of the contract is pending, and
Duquesne Light Company has filed a protest and motion to intervene with
FERC.
FUEL FOR ELECTRIC GENERATION
Information regarding BGE's electric generation by fuel type and
the cost of fuels in the five-year period 1990-1994 is set forth in the
following tables:
AVERAGE COST OF FUEL CONSUMED
GENERATION BY FUEL TYPE ((CENTS) PER MILLION BTU)
1994 1993 1992 1991 1990 1994 1993 1992 1991 1990
Nuclear (a)................... 39 % 43 % 40 % 33 % 5 % 52.06 53.01 45.54 48.64 54.86
Coal.......................... 56 55 54 44 44 148.64 151.85 154.76 160.74 154.56
Oil........................... 3 3 1 5 7 245.28 253.36 254.19 284.87 319.44
Hydro & Gas................... 3 3 3 4 6 - - - - -
101 104 98 86 62
Interchange/Purchases (b)..... (1) (4) 2 14 38
100 % 100 % 100 % 100 % 100 %
<FN>
(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 3,400,000 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 1990 through 1994 were $39.00, $39.80, $39.98, $39.49, and
$37.55, 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 1990 through 1994 were $40.45, $38.88, $38.37,
$37.25, and $37.42, 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
1990 through 1994 were $41.28, $44.49, $43.19, $40.62, and $37.54,
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 1990 through 1994 were $36.69, $33.07, $31.53,
$32.42, and $33.22, 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 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 1990 through 1994
were $20.24, $15.53, $17.25, $15.69, and $16.30, respectively.
7
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 Fabrication: BGE has contracted for the fabrication of fuel assemblies for reloads it
requires through 1996.
The nuclear fuel market is very competitive and BGE does not
anticipate any problem in meeting its requirements beyond the periods
noted above. Expenditures for nuclear fuel are discussed in MD&A --
LIQUIDITY AND CAPITAL RESOURCES on page 28.
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 40
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 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.
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).
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
8
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. BGE is in the process of expanding its
transportation service to smaller customers. 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 balancing and gas
brokering services 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 $206 million during the five-year period 1990-1994. It is
estimated that the capital expenditures necessary to comply with such
standards and regulations will be approximately $16 million, $9 million,
and $16 million for 1995, 1996, and 1997, 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.
The Clean Air Act Amendments of 1990 contain two titles designed to
reduce emissions of sulfur dioxide and nitrogen oxide (NOx) from
electric generating stations. Title IV contains provisions for
compliance in two phases. Phase I of Title IV became effective January
1, 1995, and Phase II of Title IV must be implemented by 2000. BGE met
the requirements of Phase I by installing flue gas desulfurization
systems and through fuel switching and unit retirements. BGE is
currently examining what actions will be required in order to comply
with Phase II. 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 Title I of the Act are less certain because all
implementation regulations have not yet been finalized by the
government. It is
9
expected that by the year 1999 these regulations will require additional
NOx controls for ozone 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 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.
WATER: The discharge of effluents into the waters of the State of
Maryland is regulated by the Maryland Department of the Environment
(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.
The State of Maryland may require changes in plant operations. At this
time BGE continually performs studies to determine whether any
modifications will be required to comply with these 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. Settlement discussions continue 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 nine other
utilities that they are considered potentially responsible parties
(PRPs) with respect to the cleanup of the site. A remedial investigation
and feasibility study (RI/FS) by BGE and the other PRPs was submitted to
the EPA on October 14, 1994. Estimated costs for the various remedies
included in the RI/FS range greatly (from $2 million to $90 million).
Until a specific remedy is chosen, BGE is not able to predict where
within the range the actual cleanup costs will fall. BGE's share of the
cleanup costs, estimated to be approximately 15.79%, 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 approximtaely 800 PRPs. A RI/FS 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
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
10
(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. The PRPs have agreed to perform
waste characterization, remove and dispose of all tanks and drums of
waste, and perform a remedial investigation at the site. 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 August 30, 1994, BGE was named as a defendant in UNITED STATES
V. KEYSTONE SANITATION COMPANY, ET AL. The litigation was instituted by
EPA in the United States District Court for the Middle District of
Pennsylvania involving contamination of the Keystone Sanitation Company
landfill Superfund site located in Adams County, Pennsylvania. BGE was
named as a third party defendant based upon allegations that BGE had
drums of asbestos shipped to the site. There are eleven original
defendants and approximately 150 other third party defendants. Neither
the costs of future site remediation, nor the extent of BGE's potential
liability can be estimated at this time.
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 against
BGE 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, BGE has recognized estimated
environmental costs at these sites totaling $37.9 million as of December
31, 1994. Any cleanup costs for these sites in excess of the amount
accrued, which could be significant in total, cannot presently be
estimated.
On May 3, 1994 Constellation Energy was named as a defendant in
REPUBLIC IMPERIAL ACQUISITION V. STOCKMAR ENERGY, INC., ET AL. Civil No.
940120R(LSP) (Dist. Ct., So. Dist. California). The plaintiffs are
owners of a non-hazardous waste landfill located in Imperial County,
California. The plaintiffs allege that defendants delivered hazardous
materials consisting of spent geothermal filters containing certain
metals used in the operation of four geothermal projects. The claims are
made under the Superfund statute and state and common law against the
operators, project owners and others. Certain Constellation Energy
subsidiaries have ownership interests in three of the projects. These
Constellation Companies have indemnification rights from project lessees
and operators. Approximately 45 other defendants, in addition to
Constellation Energy, have been named to date. The Constellation
Companies are currently evaluating the claims and site investigation is
at a preliminary stage. As a result, total investigation and clean up
costs, as well as the Constellation Companies' share of such costs,
cannot presently be estimated.
11
ELECTRIC OPERATING STATISTICS
YEAR ENDED DECEMBER 31,
1994 1993 1992 1991 1990
Electric Output (In Thousands) -- MWH:
Generated................................ 28,413 28,907 25,626 22,767 15,193
Purchased (A)............................ 4,857 2,627 4,323 5,522 11,859
Subtotal............................ 33,270 31,534 29,949 28,289 27,052
Less Interchange Sales................... 5,684 4,149 3,180 1,167 1,088
Total Output........................ 27,586 27,385 26,769 27,122 25,964
Power Generated and Purchased at
Times of Peak Load (MW) (one hour):
Generated by Company..................... 3,384 5,245 3,679 4,948 3,032
Net Purchased (A)........................ 2,654 631 1,879 962 2,445
Peak Load (B)............................ 6,038 5,876 5,558 5,910 5,477
Annual System Load Factor (%).............. 54.7 55.2 54.8 52.4 54.1
Revenues (In Thousands)
Residential.............................. $ 931,711 $ 931,643 $ 839,954 $ 882,591 $ 718,032
Commercial............................... 852,989 869,829 842,694 850,038 758,573
Industrial............................... 205,611 199,042 201,950 212,864 194,951
System Sales............................. 1,990,311 2,000,514 1,884,598 1,945,493 1,671,556
Interchange Sales........................ 118,027 91,543 64,323 23,845 26,629
Other.................................... 19,083 20,090 16,611 21,531 13,359
Total............................... $2,127,421 $2,112,147 $1,965,532 $1,990,869 $1,711,544
Sales (In Thousands) -- MWH:
Residential.............................. 10,670 10,614 9,735 10,097 9,283
Commercial............................... 12,351 12,395 11,909 11,707 11,352
Industrial............................... 4,433 3,763 3,663 3,708 3,743
System Sales............................. 27,454 26,772 25,307 25,512 24,378
Interchange Sales........................ 5,684 4,149 3,180 1,166 1,088
Total............................... 33,138 30,921 28,487 26,678 25,466
Customers
Residential.............................. 978,591 968,212 956,570 939,734 930,880
Commercial............................... 101,957 100,820 99,673 98,254 96,567
Industrial............................... 3,967 3,800 3,761 3,584 3,526
Total............................... 1,084,515 1,072,832 1,060,004 1,041,572 1,030,973
Average Cost of Fuel Consumed ((cents) per
million Btu)............................. 112.44 112.77 110.20 127.89 177.00
BGE achieved an all-time peak load of 6,038 megawatts on January 19, 1994.
<FN>
(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 6 for a discussion of active load management programs which
may be activated at times of peak load. Certain prior-year amounts
have been reclassified to conform to the current year's
presentation.
12
GAS OPERATING STATISTICS
YEAR ENDED DECEMBER 31,
1994 1993 1992 1991 1990
Gas Output (In Thousands) -- DTH:
Purchased.......................................... 68,547 71,204 70,208 63,159 59,470
LNG Withdrawn from Storage......................... 698 725 742 551 333
Produced........................................... 828 259 92 17 5
Total Output.................................. 70,073 72,188 71,042 63,727 59,808
Delivery Service Gas
Delivered (A)...................................... 41,897 38,521 41,048 40,503 43,377
Total......................................... 111,970 110,709 112,090 104,230 103,185
Peak Day Sendout (DTH)............................... 761,900 657,700 609,200 610,200 653,900
Capability on Peak Day (DTH)......................... 847,000 847,000 847,000 817,000 853,000
Revenues (In Thousands)
Residential........................................ $262,736 $265,601 $242,737 $220,653 $218,967
Commercial
Excluding Delivery Service...................... 121,005 121,832 112,147 96,189 89,573
Delivery Service................................ 2,285 3,287 3,591 3,031 3,304
Industrial
Excluding Delivery Service...................... 20,140 22,250 21,123 14,855 32,439
Delivery Service................................ 9,635 12,920 14,290 14,288 17,851
Other.............................................. 5,448 7,273 6,511 6,777 9,197
Total......................................... $421,249 $433,163 $400,399 $355,793 $371,331
Sales (In Thousands) -- DTH:
Residential........................................ 40,279 40,029 39,042 36,519 35,026
Commercial
Excluding Delivery Service...................... 23,712 23,830 23,478 20,687 18,164
Delivery Service................................ 6,490 7,428 7,102 6,433 5,872
Industrial
Excluding Delivery Service...................... 4,410 5,298 5,314 3,605 7,305
Delivery Service................................ 33,837 31,390 33,638 34,240 34,720
Total......................................... 108,728 107,975 108,574 101,484 101,087
Customers
Residential........................................ 498,152 491,165 486,863 482,085 482,680
Commercial......................................... 37,891 37,518 37,000 36,561 35,953
Industrial......................................... 1,354 1,353 1,412 1,385 1,401
Total......................................... 537,397 530,036 525,275 520,031 520,034
<FN>
BGE achieved an all-time peak day sendout of 761,900 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.) Certain prior-year amounts have been reclassified to
conform to the current year's presentation.
13
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 2015 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, HPS and its subsidiary MES 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 $298
million of the Constellation Companies' assets. 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 $7 million has been spent on projects in
development. The Constellation Companies also participate in the operation and
maintenance of 24 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 $224 million of the Constellation
Companies' assets. These assets include $99 million in internally and externally
managed securities portfolios, $88 million in monoline financial guaranty
(credit enhancement) companies, and $37 million in tax-oriented transactions.
Real estate and senior living projects account for $483 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 $177 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
14
2000. As a result of declines in purchasing utilities' avoided costs subsequent
to the inception of these agreements, revenues at these projects based on
current avoided cost levels would be substantially lower than revenues presently
being realized under the fixed price terms of the agreements. 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 and pursuing 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. Two of these wholesale power generating
projects, in which the Constellation Companies' investment totals $27.4 million,
have executed agreements with Pacific Gas & Electric (PG&E) providing for the
curtailment of output through the end of the fixed price period in return for
payments from PG&E. The payments from PG&E during the curtailment period will be
sufficient to fully amortize the existing project finance debt. However,
following the curtailment period, the projects remain contractually obligated to
commence production of electricity at the avoided cost rates, which could result
in reduced earnings or losses for the reasons described above. The Company
cannot predict the impact that these matters regarding any of the 16 projects
may have on the Constellation Companies or the Company, but the impact could be
material.
HPS was formed in mid 1994. HPS is engaged in the sales and service of gas
and electric appliances. This business recently was expanded to include kitchen
remodeling and servicing of heating and air conditioning systems. In December
1994, HPS acquired MES, a company specializing in installation of commercial and
residential heating, air conditioning, and plumbing.
BNG, Inc. is a wholly owned subsidiary of BGE which engages in natural gas
brokering.
CAPITAL REQUIREMENTS
Capital requirements for diversified businesses for 1992 through 1994,
along with estimated amounts for 1995 through 1997, are set forth below:
1992 1993 1994 1995 1996 1997
(IN MILLIONS)
Retirement of long-term debt........................... $118 $222 $37 $ 56 $ 65 $125
Investment requirements................................ 80 78 51 66 70 40
Total diversified businesses......................... $198 $300 $88 $122 $135 $165
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 1995-1997 reflect the Constellation Companies' estimate of funding
during such periods for ongoing and anticipated projects. Also, guarantees of
$17 million may be called which are not included above.
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.
15
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, 1994, BGE employed 7,296 people for its utility
operations. 136 people were employed by the Constellation Holdings, Inc. In
addition, the Constellation Companies employ approximately 800 employees at an
entertainment, dining, and retail complex in Orlando, Florida, 55 employees of
two wholly owned subsidiaries operating two power generation facilities, and 71
employees at a senior living facility. Four hundred sixty-eight people were
employed by BGE Home Products & Services, Inc. (HPS) and 174 people were
employed by HPS' subsidiary, Maryland Environmental Systems, Inc.
16
ITEM 2. PROPERTIES
ELECTRIC: The principal electric generating plants of BGE are as follows:
INSTALLED GENERATION (MWH)
PLANT LOCATION CAPACITY (MW) PRIMARY FUEL 1994 1993
(AT DECEMBER 31, 1994)
Steam
Calvert Cliffs Calvert County, MD 1,675 Nuclear 11,219,516 12,300,816
Brandon Shores Anne Arundel County, MD 1,291 Coal 8,857,557 7,584,610
Herbert A. Wagner Anne Arundel County, MD 1,001 Coal/Oil/Gas 2,940,978 2,953,056
Charles P. Crane Baltimore County, MD 380 Coal 1,847,851 2,102,530
Gould Street Baltimore City, MD 104 Oil 124,323 162,160
Riverside Baltimore County, MD 78 Oil/Gas 9,146 81,710
Westport Baltimore City, MD - Oil - 33,717
Jointly Owned -- Steam
Keystone Armstrong and 359(A) Coal 2,188,760 2,497,351
Indiana Counties, PA
Conemaugh Indiana County, PA 181(A) Coal 1,156,109 1,147,729
Combustion Turbine
Notch Cliff Baltimore County, MD 128 Gas 11,472 12,276
Perryman Harford County, MD 208 Oil 26,960 11,320
Westport Baltimore City, MD 121 Gas 10,266 9,863
Riverside Baltimore County, MD 173 Oil/Gas 8,711 6,632
Philadelphia Road Baltimore City, MD 64 Oil 8,250 2,537
Charles P. Crane Baltimore County, MD 14 Oil 1,804 386
Herbert A. Wagner Anne Arundel County, MD 14 Oil 1,300 172
Totals 5,791 28,413,003 28,906,865
<FN>
(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 8.
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
offices, 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 and 1994, 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.
17
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 482 non-employee plaintiffs each claim $6
million in damages ($2 million compensatory and $4 million punitive). BGE does
not know the specific facts necessary for BGE to assess its potential liability
for these type claims, such as the identity of the BGE facilities at which the
plaintiffs allegedly worked as contractors, the names of the plaintiffs'
employers, and the date on which the exposure allegedly occurred.
The second type are claims by 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. 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, and NOTE 13 TO CONSOLIDATED FINANCIAL STATEMENTS.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not Applicable.
18
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 56 Chairman of the Board (A) Vice Chairman of the Board
(Since January 1, 1993)
Edward A. Crooke 56 President (B) President, Utility Operations
(Since September 1, 1992)
Bruce M. Ambler 55 President and Chief Executive
Officer
Constellation Holdings, Inc.
(Since August 1, 1989)
George C. Creel 61 Senior Vice President Senior Vice President
Generation Vice President, Nuclear Energy
(Since January 1, 1993)
Thomas F. Brady 45 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. 60 Vice President Vice President
Gas Marketing and Gas Operations
(Since October 1, 1994) Vice President
Electric Interconnection and
Transmission
Vice President, Interconnection
and Operations
Robert E. Denton 51 Vice President Plant General Manager, Calvert
Nuclear Energy Cliffs Nuclear Power Plant
(Since September 1, 1992) Manager, Calvert Cliffs Nuclear
Power Plant
Carserlo Doyle 50 Vice President Manager, Telecommunications
Electric Interconnection Principal Engineer -- Electric
and Transmission Interconnection
(Since January 1, 1994)
Jon M. Files 59 Vice President
Management Services
(Since September 1, 1981)
Ronald W. Lowman 50 Vice President Manager, Fossil Engineering
Fossil Energy Manager, Fossil Engineering
(Since January 1, 1993) Services
G. Dowell Schwartz, Jr. 58 Vice President Manager, Auditing
General Services
(Since April 1, 1990)
Charles W. Shivery 49 Vice President Vice President
Finance and Accounting, Corporate Finance Group
Chief Financial Officer and Treasurer and Secretary
Secretary
(Since July 1, 1993)
Joseph A. Tiernan 56 Vice President Vice President
Corporate Affairs Corporate Administration
(Since February 1, 1993)
Stephen F. Wood 42 Vice President Manager, Major Customer Projects
Marketing and Sales Manager, System Engineering
(Since October 1, 1994) and Construction
Manager, Distribution Engineering
Manager, Transportation
<FN>
(A) Chief Executive Officer, Director, and member of the Executive Committee.
(B) Chief Operating Officer, Director, and member of the Executive Committee.
19
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, 1995, there were 81,056 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 1994 and 1993 in the amounts set forth below.
COMMON STOCK DIVIDENDS AND PRICE RANGES
1994 1993
DIVIDEND PRICE* DIVIDEND PRICE*
DECLARED HIGH LOW DECLARED HIGH LOW
First Quarter.......................... $ .37 $ 25 1/2 $ 22 3/8 $ .36 $ 26 3/8 $ 22 3/8
Second Quarter......................... .38 24 3/8 20 1/2 .37 26 5/8 23 7/8
Third Quarter.......................... .38 23 3/4 20 3/4 .37 27 1/2 25 1/8
Fourth Quarter......................... .38 23 5/8 21 1/4 .37 26 7/8 23 1/2
Total................................ $ 1.51 $ 1.47
*Based on New York Stock Exchange Composite Transactions as reported in the
eastern edition of THE WALL STREET JOURNAL.
20
ITEM 6. SELECTED FINANCIAL DATA
1994 1993 1992 1991 1990
(DOLLAR AMOUNTS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
SUMMARY OF OPERATIONS
Total Revenues $2,782,985 $2,741,385 $2,559,536 $2,514,631 $2,248,613
Expenses Other Than Interest and Income Taxes 2,147,726 2,124,993 2,024,227 2,026,910 1,922,498
Income From Operations 635,259 616,392 535,309 487,721 326,115
Other Income 32,365 20,310 22,132 28,095 34,488
Income Before Interest and Income Taxes 667,624 636,702 557,441 515,816 360,603
Interest Expense 190,154 188,764 189,747 196,588 165,205
Income Before Income Taxes 477,470 447,938 367,694 319,228 195,398
Income Taxes 153,853 138,072 103,347 85,547 19,952
Income Before Cumulative Effect of Changes in
Accounting Methods 323,617 309,866 264,347 233,681 175,446
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 323,617 309,866 264,347 253,426 213,200
Preferred and Preference Stock Dividends 39,922 41,839 42,247 42,746 40,261
Earnings Applicable to Common Stock $ 283,695 $268,027 $ 222,100 $ 210,680 $ 172,939
Earnings Per Share of Common Stock
Before Cumulative Effect of Changes
in Accounting Methods $ 1.93 $1.85 $ 1.63 $ 1.51 $ 1.09
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 $ 1.93 $1.85 $ 1.63 $ 1.67 $ 1.40
Dividends Declared Per Share of Common Stock $ 1.51 $1.47 $ 1.43 $ 1.40 $ 1.40
Ratio of Earnings to Fixed Charges 3.14 3.00 2.65 2.27 1.78
Ratio of Earnings to Fixed Charges and Preferred
and Preference Stock Dividends Combined 2.47 2.34 2.08 1.82 1.47
FINANCIAL STATISTICS AT YEAR END
Total Assets $8,143,538 $7,987,039 $7,374,357 $7,137,989 $6,710,375
Capitalization
Long-term debt $2,584,932 $2,823,144 $2,376,950 $2,390,115 $2,193,844
Preferred stock 59,185 59,185 59,185 59,185 59,185
Redeemable preference stock 279,500 342,500 395,500 398,500 365,000
Preference stock not subject to mandatory
redemption 150,000 150,000 110,000 110,000 110,000
Common shareholders' equity 2,717,866 2,620,511 2,534,639 2,153,306 2,073,158
Total capitalization $5,791,483 $5,995,340 $5,476,274 $5,111,106 $4,801,187
Book Value Per Share of Common Stock $ 18.42 $17.94 $ 17.63 $ 17.00 $ 16.58
Number of Common Shareholders 81,505 82,287 80,371 71,131 73,049
CERTAIN PRIOR-YEAR AMOUNTS HAVE BEEN RECLASSIFIED TO CONFORM TO THE
CURRENT YEAR'S PRESENTATION.
21
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.
Effective July 1, 1994, BGE formed a wholly owned subsidiary, BGE
Home Products & Services, Inc. (HPS), consisting of BGE's existing
merchandise and gas and appliance service operations. HPS' revenues and
expenses are included in diversified businesses revenues and diversified
businesses selling, general, and administrative expenses, respectively.
Prior-year amounts have been reclassified to conform with the current
year's presentation.
RESULTS OF OPERATIONS
EARNINGS PER SHARE OF COMMON STOCK
Consolidated earnings per share were $1.93 for 1994 and $1.85 for 1993,
an increase of $.08 and $.22 from prior-year amounts, respectively. The
changes in earnings per share reflect a higher level of earnings
applicable to common stock, offset partially by the larger number of
outstanding common shares. The summary below presents the
earnings-per-share amounts.
1994 1993 1992
Utility business $1.81 $1.77 $1.52
Diversified businesses .12 .08 .11
Total $1.93 $1.85 $1.63
EARNINGS APPLICABLE TO COMMON STOCK
Earnings applicable to common stock increased $15.7 million in 1994
and $45.9 million in 1993. The 1994 increase reflects higher utility and
diversified businesses earnings. The 1993 increase reflects higher
utility earnings, slightly offset by lower earnings from diversified
businesses.
Utility earnings increased in 1994 compared to the prior year due to
three principal factors: lower operations and maintenance expenses; an
increase in the allowance for funds used during construction; and
greater sales of electricity. The higher sales of electricity are
primarily due to an increased number of customers compared to 1993. The
1994 earnings increase was offset partially by higher depreciation and
amortization expense, which includes the write-off of certain Perryman
costs (see discussion on page 29). Utility earnings increased in 1993
over 1992 because BGE sold more electricity than in the previous year
and because of increased base rates. Three 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 offset partially by
higher operations and maintenance expenses, depreciation and
amortization expense, 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%.
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 favorably affected utility earnings
through April 1994. Several electric fuel rate cases now pending before
the PSC discussed in Notes 1 and 13 could also affect future years'
earnings.
Future competition may also affect earnings in ways that are not
possible to predict (see discussion on page 33).
Earnings from diversified businesses, which primarily represent the
operations of Constellation Holdings, Inc. (CHI) and its subsidiaries
(collectively, the Constellation Companies) and BGE Home Products &
Services, Inc. (HPS), increased during 1994 and decreased during 1993.
The reasons for these changes are discussed in the "Diversified
Businesses Earnings" section on pages 30 and 31.
EFFECT OF WEATHER ON UTILITY SALES
Weather conditions affect BGE's utility sales. BGE measures weather
conditions using degree days. A degree day is the difference between the
average daily actual temperature and the baseline temperature of 65
degrees. 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. 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 for 1994 and 1993.
30-Year
1994 1993 Average
Cooling degree days 949 865 804
Percentage change
compared to prior year 9.7% 22.3%
Heating degree days 4,670 4,959 4,901
Percentage change
compared to prior year (5.8)% (0.3)%
22
BGE UTILITY REVENUES AND SALES
Electric revenues changed during 1994 and 1993 because of the following
factors:
1994 1993
(IN MILLIONS)
System sales volumes $ 9.9 $112.4
Base rates 1.4 58.5
Fuel rates (21.5) (55.0)
Revenues from system sales (10.2) 115.9
Interchange sales 26.5 27.2
Other revenues (1.9) 3.5
Total electric revenues $ 14.4 $146.6
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. Below is a
comparison of the changes in electric system sales volumes.
1994 1993
Residential 0.5% 9.0%
Commercial (0.4) 4.1
Industrial 17.8 2.7
Total 2.5 5.8
Sales to residential and commercial customers were essentially
unchanged from the prior year due to three factors: the number of
customers increased; higher sales from extreme weather conditions early
in the year slightly exceeded lower sales from milder weather in the
second half of the year; and usage-per-customer decreased. Sales to
industrial customers reflect primarily an increase in the sale of
electricity to Bethlehem Steel, which purchased more electricity from
BGE due to increased steel production and the fact that Bethlehem Steel
is now purchasing its full electricity requirements from BGE. Bethlehem
Steel is still producing power with its own generating facility, but is
now selling the output from this facility to BGE rather than using the
power to reduce its requirements. Hotter summer weather was the main
reason for the increase in total sales in 1993. The sales increases to
the residential and commercial customers reflect significantly hotter
summer weather, and to a lesser extent, increased usage and customer
growth. Sales to the industrial class reflect increased sales of
electricity to Bethlehem Steel to support its increased steel production
during 1993.
Base rates increased slightly during 1994 due to the remaining
effect of the PSC's April 1993 rate order, offset partially by the
deferral of the portion of energy conservation surcharge billings
subject to refund. Base rates increased in 1993 due to 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%.
Under the energy conservation surcharge, if the PSC determines that
BGE is earning in excess of its authorized rate of return, BGE will have
to refund (by means of lowering future surcharges) a portion of energy
conservation surcharge revenues to its customers. The portion subject to
the refund is compensation for foregone sales from conservation programs
and incentives for achieving conservation goals and will be refunded to
customers with interest beginning in the ensuing July when the annual
resetting of the conservation surcharge rates occurs. BGE earned in
excess of its authorized rate of return on electric operations for the
period July 1, 1993 through June 30, 1994. As a result, BGE deferred the
portion of electric energy conservation revenues subject to refund for
the period December 1993 through November 1994. The deferral of these
billings totaled $20.1 million.
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 1994 and 1993 due to a
lower fuel rate, offset partially by increased electric system sales
volumes. 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 previous year. BGE expects
electric fuel rate revenues to remain relatively constant through 1995.
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 its own system sales of electricity, if BGE' s
available generation is the least costly available to PJM utilities.
Interchange sales increased during 1994 and 1993 because BGE had a
less-costly generation mix than other PJM utilities. The less-costly mix
reflects greater generation from the Brandon Shores Power Plant and the
operation of the Calvert Cliffs Nuclear Power Plant.
23
Gas revenues decreased during 1994 and increased during 1993 because
of the following factors:
1994 1993
(IN MILLIONS)
Sales volumes $ 3.6 $ 0.6
Base rates 2.4 2.6
Gas cost adjustment revenues (16.1) 28.8
Other revenues (1.8) 0.8
Total gas revenues $ (11.9) $32.8
The changes in gas sales volumes compared to the year before were:
1994 1993
Residential 0.6% 2.5%
Commercial (3.4) 2.2
Industrial 4.2 (5.8)
Total 0.7 (0.6)
Total gas sales increased during 1994 because of higher sales to
residential and industrial customers, offset partially by lower sales to
commercial customers. Sales to industrial customers reflect primarily
greater usage of natural gas by Bethlehem Steel. Sales to commercial and
industrial customers were negatively impacted because delivery service
customers either voluntarily switched their fuel source from natural gas
to alternate fuels, or were involuntarily interrupted by BGE as a result
of extreme winter weather conditions in the first quarter of 1994.
Interruptible customers maintain alternate fuel sources and pay reduced
rates in exchange for BGE's right to interrupt service during periods
of peak demand. Total gas sales decreased during 1993 because of lower
sales to industrial customers, offset partially 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 their L-Blast furnace. The increases
in sales to the residential and commercial classes of customers reflect
the colder winter weather during the first quarter of 1993 and an
increase in the number of customers.
Base rates increased slightly in 1994 due to an increased recovery
of eligible gas conservation program costs through the energy
conservation surcharge. Base rates increased in 1993 for two 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 a return on BGE's higher level of gas
rate base.
Changes in gas cost adjustment revenues result primarily from the
operation of the purchased gas adjustment clauses which are designed to
recover actual gas costs (see Note 1). Changes in gas cost adjustment
revenues normally do not affect earnings. Gas cost adjustment revenues
decreased during 1994 primarily because of decreased prices of purchased
gas and slightly lower sales volumes subject to the clauses. Gas cost
adjustment revenues increased during 1993 primarily because of increased
prices to recover higher costs of purchased gas and higher sales volumes
subject to gas cost adjustment clauses. Delivery service sales volumes
are not subject to gas cost adjustment clauses because delivery service
customers purchase their gas directly from third parties.
BGE UTILITY FUEL AND ENERGY EXPENSES
Electric fuel and purchased energy expenses were as follows:
1994 1993 1992
(IN MILLIONS)
Actual costs $541.2 $483.9 $445.2
Net recovery of costs
under electric fuel rate
clause (see Note 1) 1.1 50.7 111.0
Total expense $542.3 $534.6 $556.2
Actual electric fuel and purchased energy costs increased during
1994 as a result of a more costly actual generation mix and an increase
in the net output of electricity generated to meet the demand of BGE's
system and the PJM system. The cost of the actual generation mix
increased due to higher purchased energy costs and scheduled outages at
the Calvert Cliffs Nuclear Power Plant in 1994. Actual electric fuel and
purchased energy costs during 1993 increased for two 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.
Purchased gas expenses were as follows:
1994 1993 1992
(IN MILLIONS)
Actual costs $222.7 $246.4 $213.6
Net (deferral) recovery of costs
under purchased gas adjustment
clause (see Note 1) 1.9 (3.7) 0.5
Total expense $224.6 $242.7 $214.1
24
Actual purchased gas costs decreased during 1994 for two reasons:
lower gas prices and lower output associated with the decreased demand
for BGE gas. The lower gas prices reflect market conditions and
take-or-pay and other supplier refunds, offset by higher costs related
to the implementation of Federal Energy Regulatory Commission (FERC)
Order 636 and higher demand charges. Actual purchased gas costs
increased in 1993 for three 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
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
In 1994, in order to more accurately reflect utility operations
expense, BGE reclassified the amortization of deferred energy
conservation expenditures and deferred nuclear expenditures from
operations expense to depreciation and amortization expense. In
addition, BGE reclassified diversified businesses' expenses from
operations expense to diversified businesses-selling, general, and
administrative expense. Prior-year amounts have been reclassified to
conform with the current year's presentation.
Operations expense decreased during 1994 primarily due to labor
savings achieved as a result of the Company's employee reduction
programs discussed in Note 7 and continuing cost control efforts. These
savings offset higher expense from the amortization of the cost of the
1993 and 1992 Voluntary Special Early Retirement Programs (VSERP) and a
$10.0 million charge for a bonus paid to employees in lieu of a general
wage increase. In addition, operations expense for 1994 decreased
because operations expense for 1993 included a $17.2 million charge for
certain employee reduction programs, offset partially by a credit to
expense equivalent to the $9.8 million cost of termination benefits
associated with the Company' s 1992 VSERP.
Operations expense increased during 1993 due to higher labor costs,
employee reduction expenses (see Note 7), postretirement benefit
expenses resulting from the implementation of Statement of Financial
Accounting Standards No. 106 (see Note 6), and higher nuclear operating
costs. These increases were offset partially by the 1993 reversal of the
$9.8 million charge originally recorded in 1992 for termination benefits
associated with the Company's 1992 VSERP to reflect the ratemaking
treatment adopted by the PSC in its April 1993 rate order.
Operations expense is expected to be reduced in 1995 due to the
realization of a full year of cost savings from the employee reduction
programs and continuing cost control efforts. These lower costs are
expected to exceed other increases in operations expenses.
Maintenance expense decreased during 1994 due primarily to lower
costs at the Calvert Cliffs Nuclear Power Plant. Maintenance expense
increased in 1993 because of higher labor costs and higher costs at the
Calvert Cliffs Nuclear Power Plant.
Depreciation and amortization expense increased during 1994 because
of the write-off of certain Perryman costs discussed below.
Additionally, depreciation and amortization expense increased in 1994
and 1993 because of higher depreciable plant in service and higher
levels of energy conservation program costs. The increase in depreciable
plant in service resulted from the addition of electric transmission and
distribution plant and certain capital additions at the Calvert Cliffs
Nuclear Power Plant during 1994 and 1993.
Initially, BGE had planned to build two combined cycle generating
units at its Perryman site. However, due to significant changes in the
environment in which utilities operate, BGE now has no plans to
construct the second combined cycle generating unit. Accordingly, during
the third quarter of 1994, BGE wrote off $15.7 million of the costs
associated with that second combined cycle unit. This write-off reduced
after-tax earnings during 1994 by $11.0 million or 7 cents per share.
Work on the first 140mw combustion turbine at Perryman continues to be
on schedule for commercial operation in 1995.
Depreciation and amortization expense in 1995 will be affected by
the completion of a facility-specific study of the cost to decommission
the Calvert Cliffs Nuclear Power Plant. This study generated a higher
decommissioning cost than the prior estimate which will increase
depreciation expense $9 million annually. In addition, the PSC issued an
order adjusting BGE' s utility plant depreciation rates to reflect the
results of a detailed depreciation study. The new depreciation rates are
expected to result in an increase in depreciation accruals of
approximately $21 million annually. BGE plans to defer the increased
depreciation accruals for recovery in a future base rate proceeding,
consistent with previous rate actions of the PSC.
25
Taxes other than income taxes increased slightly during 1994 due
primarily to higher property taxes resulting from higher levels of
utility plant in service. Taxes other than income taxes increased during
1993 because of higher property taxes from the addition of Brandon
Shores Unit 2 to the taxable base effective July 1, 1992, 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
The allowance for funds used during construction (AFC) increased
during 1994 because of a higher level of construction work in progress
which was offset partially by the lower AFC rate established by the PSC
in the April 1993 rate order. AFC was essentially unchanged in 1993
because a higher level of construction work in progress was offset by
the lower AFC rate discussed above.
Net other income and deductions increased in 1994 primarily due to a
lower level of charitable contributions and gains realized on the sale
of receivables.
Capitalized interest decreased during 1994 due to lower capitalized
interest on the Constellation Companies' power generation systems,
offset partially by the accrual by BGE of carrying charges on electric
deferred fuel costs excluded from rate base (see Note 5). Capitalized
interest increased during 1993 due to the accrual of carrying charges on
electric deferred fuel costs excluded from rate base.
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 31.
DIVERSIFIED BUSINESSES EARNINGS
Earnings per share from diversified businesses were:
1994 1993 1992
Constellation Holdings, Inc.
Power generation systems $ .10 $ .07 $ .08
Financial investments .03 .10 .09
Real estate development and senior
living facilities (.03) (.04) (.05)
Effect of 1993 Tax Act - (.04) -
Other (.01) (.01) (.01)
Total Constellation Holdings, Inc. .09 .08 .11
BGE Home Products & Services, Inc. .03 - -
Total diversified businesses $ .12 $ .08 $ .11
The Constellation Companies' power generation systems business
includes the development, ownership, management, and operation of
wholesale power generating projects in which the Constellation Companies
hold ownership interests, as well as the provision of services to power
generation projects under operation and maintenance contracts. Power
generation systems earnings increased in 1994 primarily due to payments
for the curtailment of output at two wholesale power generating projects
as discussed below. Power generation systems earnings during 1993 were
essentially unchanged. Earnings for 1993 include $8.0 million of energy
tax credits on the commercial operation of the Puna geothermal plant,
offset by costs incurred at the Panther Creek waste-coal project in
order to resolve fuel quality and other start-up problems.
The Constellation Companies' investment in wholesale power
generating projects includes $177 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 rate for the first ten years of the agreements and at variable
rates based on the utilities' avoided cost for the remaining term of the
agreements. Avoided cost generally represents a utility' s next lowest
cost generation to service the demands on its system. These power
generation projects are scheduled to convert to supplying electricity at
avoided cost rates in various years beginning in late 1996 through the
end of 2000. As a result of declines in purchasing utilities' avoided
costs subsequent to the inception of these agreements, revenues at these
projects based on current avoided cost levels would be substantially
lower than revenues presently being realized under the fixed price terms
of the agreements. 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 and pursuing
26
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 its ownership
interests in the projects. Two of these wholesale power generating
projects, in which the Constellation Companies' investment totals $27.4
million, have executed agreements with Pacific Gas & Electric (PG&E)
providing for the curtailment of output through the end of the fixed
price period in return for payments from PG&E. The payments from PG&E
during the curtailment period will be sufficient to fully amortize the
existing project finance debt. However, following the curtailment
period, the projects remain contractually obligated to commence
production of electricity at the avoided cost rates, which could result
in reduced earnings or losses for the reasons described above. The
Company cannot predict the impact that these matters regarding any of
the 16 projects may have on the Constellation Companies or the Company,
but the impact could be material.
Earnings from the Constellation Companies' portfolio of financial
investments include capital gains and losses, dividends, income from
financial limited partnerships, and income from financial guaranty
insurance companies. Financial investment earnings decreased during 1994
due to reduced earnings from the investment portfolio. Additionally,
1993 results reflected a $6.1 million gain from the sale of a portion of
an investment in a financial guaranty insurance company. Earnings
increased slightly in 1993 as compared to 1992 because this gain was
substantially offset by lower investment income 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.
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 increased slightly during 1994
due to gains recognized from the sale of two retail centers, an office
building, and interests in two senior living facilities. The increases
in diversified businesses' revenues and in selling, general, and
administrative expenses reflect the proceeds of these sales and the cost
of the facilities sold, respectively. Earnings from real estate
development and senior living facilities were essentially unchanged in
1993 because a $2.1 million gain on the sale of a substantial portion of
the 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 Constellation Companies' real estate portfolio has experienced
continuing carrying costs and depreciation. Additionally, the
Constellation Companies have been expensing rather than capitalizing
interest on certain undeveloped land where development activities were
at minimal levels. These factors have affected earnings negatively and
are expected to continue to do so until the levels of undeveloped land
are reduced. Cash flow from real estate operations has been insufficient
to cover the debt service requirements of certain of these projects.
Resulting cash shortfalls have been satisfied through cash infusions
from Constellation Holdings, Inc., which obtained the funds through a
combination of cash flow generated by other Constellation Companies and
its corporate borrowings. To the extent the real estate market continues
to improve, earnings from real estate activities are expected to improve
also.
The Constellation Companies continued investment in real estate
projects is a function of market demand, interest rates, credit
availability, and the strength of the economy in general. The
Constellation Companies' Management believes that although the real
estate market has improved, until the economy reflects sustained growth
and the excess inventory in the market in the Baltimore-Washington
corridor goes down, real estate values will not improve significantly.
If the Constellation Companies were to sell their real estate projects
in the current depressed market, losses would occur in amounts difficult
to determine. Depending upon market conditions, future sales could also
result in losses. In addition, were the Constellation Companies to
change their intent about any project from an intent to hold 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.
BGE Home Products & Services earnings increased during 1994
primarily due to a gain on the sale of receivables.
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 this Report under Item 1.
Business-Environmental Matters.
27
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 1992
through 1994, along with estimated amounts for the years 1995 through
1997, are reflected below.
1992 1993 1994 1995 1996 1997
(IN MILLIONS)
Utility Business:
Construction expenditures (excluding AFC)
Electric $ 292 $ 360 $339 $233 $219 $206
Gas 36 51 68 61 71 84
Common 39 44 42 56 50 35
Total construction expenditures 367 455 449 350 340 325
AFC 22 23 34 35 18 13
Nuclear fuel (uranium purchases and processing charges) 40 47 42 48 50 52
Deferred energy conservation expenditures 20 33 41 44 43 29
Deferred nuclear expenditures 16 14 8 - - -
Retirement of long-term debt and redemption of
preference stock 486 907 203 268 98 164
Total utility business 951 1,479 777 745 549 583
Diversified Businesses:
Retirement of long-term debt 118 222 37 56 65 125
Investment requirements 80 78 51 66 70 40
Total diversified businesses 198 300 88 122 135 165
Total $1,149 $1,779 $865 $867 $684 $748
BGE UTILITY CAPITAL REQUIREMENTS
BGE's construction program is subject to continuous review and
modification, and actual expenditures may vary from the estimates above.
Electric construction expenditures include the installation of two 5,000
kilowatt diesel generators at Calvert Cliffs Nuclear Power Plant, one of
which is scheduled to be placed in service in 1995 and the second in
1996; 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 expenditures do not include additional generating units.
During 1994, 1993, and 1992, the internal generation of cash from
utility operations provided 72%, 71%, and 81% respectively, of the
funds required for BGE's capital requirements exclusive of retirements
and redemptions of debt and preference stock. In addition, in 1994, $70
million of cash was provided by the sale of certain BGE and HPS
receivables (see Note 13). During the three-year period 1995 through
1997, the Company expects to provide through utility operations 100% 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, 1994, BGE's issuances of
long-term debt, preference stock, and common stock were $1,557 million,
$130 million, and $448 million, respectively. During the same period,
retirements and redemptions of BGE's long-term debt and preference stock
28
totaled $1,425 million and $149 million, respectively, exclusive of any
redemption premiums or discounts. 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
enhance the capital structure of Constellation Holdings, Inc.
DIVERSIFIED BUSINESSES CAPITAL REQUIREMENTS
DEBT AND LIQUIDITY
The Constellation Companies intend to meet capital requirements by
refinancing debt as it comes due and through internally generated cash.
These internal sources include cash that may be generated from
operations, sale of assets, and cash 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 31). The ability of the Constellation Companies to sell or
liquidate assets described above will depend on market conditions, and
no assurances can be given that such sales or liquidations can be made.
Also, to provide additional liquidity to meet interim financial needs,
CHI has entered into a $50 million revolving credit agreement.
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 1995 through 1997 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 amounts on page 32 because of the type
and number of projects selected for development, the impact of market
conditions on those projects, the ability to obtain financing, and the
availability of internally generated cash. The Constellation Companies
have met their investment requirements in the past through the internal
generation of cash and through borrowings from institutional lenders.
RESPONSE TO REGULATORY CHANGE
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. In response to the
competitive forces and regulatory changes, as discussed in Part 1 of
this Report under the heading Regulatory Matters and Competition, BGE
from time to time will consider various strategies designed to enhance
its competitive position and to increase its ability to adapt to and
anticipate regulatory changes in its utility business. These strategies
may include internal restructurings involving the complete or partial
separation of its generation, transmission and distribution businesses,
acquisitions of related or unrelated businesses, business combinations,
and additions to or dispositions of portions of its franchised service
territories. BGE may from time to time be engaged in preliminary
discussions, either internally or with third parties, regarding one or
more of these potential strategies. No assurances can be given as to
whether any potential transaction of the type described above may
actually occur, or as to the ultimate effect thereof on the financial
condition or competitive position of BGE.
29
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, 1994 and 1993, 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, 1994. These financial statements are the responsibility of the
Company's Management. Our responsibility is to express an opinion on
these financial statements 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, 1994
and 1993, and the consolidated results of their operations and their
cash flows for each of the three years in the period ended December 31,
1994 in conformity with generally accepted accounting principles.
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 1989-1991 outages at the
Company's nuclear power plant, and the Company established in 1990 a
reserve of $35 million 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.
We have also previously audited, in accordance with generally accepted
standards, the consolidated balance sheets and statements of capitalization
at December 31, 1992, 1991, and 1990, and the related consolidated
statements of income, cash flows, common shareholders' equity, and income
taxes for each of the two years in the period ended December 31, 1991 (none
of which are presented herein); and we expressed unqualified opinions on
those consolidated financial statements. In our opinion, the information set
forth in the Summary of Operations included in the Selected Financial Data for
each of the five years in the period ended December 31, 1994, appearing on page
21 is fairly stated in all material respects in relation to the financial
statements from which it has been derived.
/s/ Coopers and Lybrand L.L.P.
COOPERS & LYBRAND L.L.P.
Baltimore, Maryland
January 20, 1995
30
Consolidated Statements of Income
YEAR ENDED DECEMBER 31, 1994 1993 1992
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
Revenues
Electric $2,126,581 $2,112,147 $1,965,532
Gas 421,249 433,163 400,399
Diversified businesses 235,155 196,075 193,605
Total revenues 2,782,985 2,741,385 2,559,536
Expenses Other Than Interest and Income Taxes
Electric fuel and purchased energy 542,314 534,628 556,184
Gas purchased for resale 224,590 242,685 214,103
Operations 545,413 574,073 537,593
Maintenance 164,892 181,208 172,248
Diversified businesses - selling, general, and
administrative 174,834 143,654 131,580
Depreciation and amortization 295,950 253,913 229,515
Taxes other than income taxes 199,733 194,832 183,004
Total expenses other than interest and income taxes 2,147,726 2,124,993 2,024,227
Income from Operations 635,259 616,392 535,309
Other Income
Allowance for equity funds used during construction 21,746 14,492 13,892
Equity in earnings of Safe Harbor Water Power
Corporation 4,349 4,243 4,267
Net other income and deductions 6,270 1,575 3,973
Total other income 32,365 20,310 22,132
Income Before Interest and Income Taxes 667,624 636,702 557,441
Interest Expense
Interest charges 214,347 212,971 211,712
Capitalized interest (12,427) (16,167) (13,800)
Allowance for borrowed funds used during
construction (11,766) (8,040) (8,165)
Net interest expense 190,154 188,764 189,747
Income Before Income Taxes 477,470 447,938 367,694
Income Taxes 153,853 138,072 103,347
Net Income 323,617 309,866 264,347
Preferred and Preference Stock Dividends 39,922 41,839 42,247
Earnings Applicable to Common Stock $ 283,695 $268,027 $ 222,100
Average Shares of Common Stock Outstanding 147,100 145,072 136,248
Earnings Per Share of Common Stock $ 1.93 $ 1.85 $ 1.63
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
CERTAIN PRIOR-YEAR AMOUNTS HAVE BEEN RECLASSIFIED TO CONFORM TO THE CURRENT
YEAR'S PRESENTATION.
31
Consolidated Balance Sheets
AT DECEMBER 31, 1994 1993
(IN THOUSANDS)
ASSETS
Current Assets
Cash and cash equivalents $ 38,590 $ 84,236
Accounts receivable (net of allowance for
uncollectibles) 314,842 401,853
Fuel stocks 70,627 70,233
Materials and supplies 149,614 145,130
Prepaid taxes other than income taxes 57,740 54,237
Other 47,022 38,971
Total current assets 678,435 794,660
Investments and Other Assets
Real estate projects 471,435 487,397
Power generation systems 311,960 298,514
Financial investments 224,340 213,315
Nuclear decommissioning trust fund 66,891 56,207
Safe Harbor Water Power Corporation 34,168 34,138
Senior living facilities 11,540 2,005
Other 58,824 65,355
Total investments and other assets 1,179,158 1,156,931
Utility Plant
Plant in service
Electric 5,929,996 5,713,259
Gas 616,823 557,942
Common 511,016 487,740
Total plant in service 7,057,835 6,758,941
Accumulated depreciation (2,305,372) (2,161,984)
Net plant in service 4,752,463 4,596,957
Construction work in progress 506,030 436,440
Nuclear fuel (net of amortization) 134,012 139,424
Plant held for future use 24,320 24,066
Net utility plant 5,416,825 5,196,887
Deferred Charges
Regulatory assets 773,034 768,125
Other 96,086 70,436
Total deferred charges 869,120 838,561
Total Assets $ 8,143,538 $7,987,039
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
32
Consolidated Balance Sheets
AT DECEMBER 31, 1994 1993
(IN THOUSANDS)
LIABILITIES AND CAPITALIZATION
Current Liabilities
Short-term borrowings $ 63,700 $ -
Current portions of long-term debt and
preference stock 323,675 44,516
Accounts payable 181,931 195,534
Customer deposits 24,891 22,345
Accrued taxes 19,585 20,623
Accrued interest 60,348 58,541
Dividends declared 66,012 63,966
Accrued vacation costs 30,917 35,546
Other 30,857 38,716
Total current liabilities 801,916 479,787
Deferred Credits and Other Liabilities
Deferred income taxes 1,156,429 1,067,611
Deferred investment tax credits 149,394 157,426
Pension and postemployment benefits 138,835 183,043
Decommissioning of federal uranium enrichment
facilities 45,836 46,858
Other 59,645 56,974
Total deferred credits and other liabilities 1,550,139 1,511,912
Capitalization
Long-term debt 2,584,932 2,823,144
Preferred stock 59,185 59,185
Redeemable preference stock 279,500 342,500
Preference stock not subject to mandatory
redemption 150,000 150,000
Common shareholders' equity 2,717,866 2,620,511
Total capitalization 5,791,483 5,995,340
Commitments, Guarantees, and Contingencies -
See Note 13
Total Liabilities and Capitalization $8,143,538 $7,987,039
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
33
Consolidated Statements of Cash Flows
YEAR ENDED DECEMBER 31, 1994 1993 1992
(IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 323,617 $309,866 $ 264,347
Adjustments to reconcile to net cash provided by
operating activities
Depreciation and amortization 351,064 314,027 273,549
Deferred income taxes 79,278 53,057 26,914
Investment tax credit adjustments (8,192) (8,444) (8,854)
Deferred fuel costs 11,461 51,445 105,430
Accrued pension and postemployment benefits (41,113) (25,276) -
Allowance for equity funds used during
construction (21,746) (14,492) (13,892)
Equity in earnings of affiliates and joint
ventures (net) (20,225) (4,655) (11,525)
Changes in current assets other than sale of
accounts receivable (10,536) (37,252) (26,206)
Changes in current liabilities, other than
short-term borrowings (24,447) 71,153 (9,614)
Other 7,153 (6,643) (31,005)
Net cash provided by operating activities 646,314 702,786 569,144
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of
Short-term borrowings (net) 63,700 (11,900) (139,600)
Long-term debt 207,169 1,206,350 603,400
Preference stock - 128,776 -
Common stock 33,869 57,379 355,759
Proceeds from sale of receivables 70,000 - -
Reacquisition of long-term debt (240,853) (1,012,514) (687,052)
Redemption of preference stock (4,406) (144,310) (2,924)
Common stock dividends paid (220,152) (211,137) (189,180)
Preferred and preference stock dividends paid (39,950) (42,425) (42,300)
Other (437) (7,094) (399)
Net cash used in financing activities (131,060) (36,875) (102,296)
CASH FLOWS FROM INVESTING ACTIVITIES
Utility construction expenditures (including AFC) (483,059) (477,878) (389,416)
Allowance for equity funds used during construction 21,746 14,492 13,892
Nuclear fuel expenditures (42,089) (47,329) (39,486)
Deferred nuclear expenditures (8,393) (13,791) (15,809)
Deferred energy conservation expenditures (40,440) (32,909) (19,918)
Contributions to nuclear decommissioning trust fund (9,780) (9,699) (8,900)
Purchases of marketable equity securities (52,099) (46,820) (49,003)
Sales of marketable equity securities 40,585 33,754 56,690
Other financial investments 2,469 19,589 44,929
Real estate projects 14,926 (30,330) (23,385)
Power generation systems (1,116) (26,841) (31,483)
Other (3,650) 8,965 4,746
Net cash used in investing activities (560,900) (608,797) (457,143)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (45,646) 57,114 9,705
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 84,236 27,122 17,417
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 38,590 $84,236 $ 27,122
OTHER CASH FLOW INFORMATION
Cash paid during the year for:
Interest (net of amounts capitalized) $ 184,441 $183,266 $ 183,209
Income taxes $ 112,923 $126,034 $ 87,693
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
CERTAIN PRIOR-YEAR AMOUNTS HAVE BEEN RECLASSIFIED TO CONFORM TO THE CURRENT
YEAR'S PRESENTATION.
34
Consolidated Statements of Common Shareholders' Equity
Unrealized
Loss on
Available Pension
YEARS ENDED DECEMBER 31, 1994, 1993, Common Stock Retained For Sale Liability Total
AND 1992 Shares Amount Earnings Securities Adjustment Amount
(IN THOUSANDS)
BALANCE AT DECEMBER 31, 1991 126,690 $ 979,211 $1,174,095 $ - $ - $2,153,306
Net income 264,347 264,347
Dividends declared
Preferred and preference stock (42,247) (42,247)
Common stock ($1.43 per share) (196,601) (196,601)
Common stock issued 17,098 356,230 356,230
Other (4) (439) 43 (396)
BALANCE AT DECEMBER 31, 1992 143,784 1,335,002 1,199,637 - - 2,534,639
Net income 309,866 309,866
Dividends declared
Preferred and preference stock (41,839) (41,839)
Common stock ($1.47 per share) (213,407) (213,407)
Common stock issued 2,250 57,379 57,379
Other (917) (3,117) (4,034)
Pension liability adjustment (33,990) (33,990)
Deferred taxes on pension liability adjustment 11,897 11,897
BALANCE AT DECEMBER 31, 1993 146,034 1,391,464 1,251,140 - (22,093) 2,620,511
Net income 323,617 323,617
Dividends declared
Preferred and preference stock (39,922) (39,922)
Common stock ($1.51 per share) (222,180) (222,180)
Common stock issued 1,493 33,869 33,869
Other 45 45
Net unrealized loss on securities (5,609) (5,609)
Deferred taxes on net unrealized loss on securities 1,963 1,963
Pension liability adjustment 8,573 8,573
Deferred taxes on pension liability adjustment (3,001) (3,001)
BALANCE AT DECEMBER 31, 1994 147,527 $1,425,378 $1,312,655 $(3,646) $(16,521) $2,717,866
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
35
Consolidated Statements of Capitalization
AT DECEMBER 31,
1994 1993
(IN THOUSANDS)
Long-Term Debt
First Refunding Mortgage Bonds of BGE
9 1/8% Series, due October l5, 1995 $ 188,014 $200,000
5 1/8% Series, due April 15, 1996 26,454 26,585
6 1/8% Series, due August 1, 1997 24,935 24,957
7% Series, due December 15, 1998 - 28,638
Floating rate series, due April 15, 1999 125,000 -
8.40% Series, due October 15, 1999 96,225 100,000
5 1/2% Series, due July 15, 2000 125,000 125,000
7 1/4% Series, due April 15, 2001 - 59,911
8 3/8% Series, due August 15, 2001 122,430 124,980
7 1/8% Series, due January 1, 2002 49,957 49,999
7 1/4% Series, due July 1, 2002 124,850 125,000
5 1/2% Installment Series, due July 15, 2002 11,650 12,080
6 1/2% Series, due February 15, 2003 124,947 125,000
6 1/8% Series, due July 1, 2003 124,925 125,000
5 1/2% Series, due April 15, 2004 125,000 125,000
6.80% Series, due September 15, 2004 - 20,000
7 1/2% Series, due January 15, 2007 125,000 125,000
6 5/8% Series, due March 15, 2008 125,000 125,000
6.90% Installment Series, due September 15, 2009 - 55,000
7 1/2% Series, due March 1, 2023 124,998 124,998
7 1/2% Series, due April 15, 2023 100,000 100,000
Total First Refunding Mortgage Bonds 1,744,385 1,802,148
Other long-term debt of BGE
Medium-term notes, Series A 10,500 23,500
Medium-term notes, Series B 100,000 100,000
Medium-term notes, Series C 173,050 173,050
Pollution control loan, due July 1, 2011 36,000 36,000
Port facilities loan, due June 1, 2013 48,000 48,000
Adjustable rate pollution control loan, due July 1, 2014 20,000 20,000
5.55% Pollution control revenue refunding loan,
due July 15, 2014 47,000 47,000
Economic development loan, due December 1, 2018 35,000 35,000
6.00% Pollution control revenue refunding loan,
due April 1, 2024 75,000 -
Total other long-term debt of BGE 544,550 482,550
Long-term debt of Constellation Companies
Mortgage and construction loans and other
collateralized notes
7.67%, due October 1, 1995 13,000 -
Variable rates, due through 2009 116,613 151,251
7.73%, due March 15, 2009 6,152 6,465
Unsecured notes 440,000 440,000
Total long-term debt of Constellation Companies 575,765 597,716
Unamortized discount and premium (17,593) (17,754)
Current portion of long-term debt (262,175) (41,516)
Total long-term debt 2,584,932 2,823,144
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
36
Consolidated Statements of Capitalization
AT DECEMBER 31,
1994 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 $22,292
Series C, 4%, 68,928 shares outstanding,
callable at $105 per share 6,893 6,893
Series D, 5.40%, 300,000 shares outstanding,
callable at $101 per share 30,000 30,000
Total preferred stock 59,185 59,185
PREFERENCE STOCK
Cumulative, $100 par value, 6,500,000 shares
authorized
Redeemable preference stock
7.50%, 1986 Series, 455,000 and 470,000 shares
outstanding. Callable
at $105 per share prior to October 1, 1996
and at lesser amounts thereafter 45,500 47,000
6.75%, 1987 Series, 455,000 and 485,000 shares
outstanding. Callable at
$104.50 per share prior to April 1, 1997
and at lesser amounts thereafter 45,500 48,500
6.95%, 1987 Series, 500,000 shares outstanding 50,000 50,000
7.80%, 1989 Series, 500,000 shares outstanding 50,000 50,000
8.25%, 1989 Series, 500,000 shares outstanding 50,000 50,000
8.625%, 1990 Series, 650,000 shares outstanding 65,000 65,000
7.85%, 1991 Series, 350,000 shares outstanding 35,000 35,000
Current portion of redeemable preference stock (61,500) (3,000)
Total redeemable preference stock 279,500 342,500
Preference stock not subject to mandatory redemption
7.78%, 1973 Series, 200,000 shares outstanding,
callable at $101 per share 20,000 20,000
7.125%, 1993 Series, 400,000 shares outstanding,
not callable prior to July 1, 2003 40,000 40,000
6.97%, 1993 Series, 500,000 shares outstanding,
not callable prior to October 1, 2003 50,000 50,000
6.70%, 1993 Series, 400,000 shares outstanding,
not callable prior to January 1, 2004 40,000 40,000
Total preference stock not subject to mandatory
redemption 150,000 150,000
COMMON SHAREHOLDERS' EQUITY
Common stock without par value, 175,000,000 shares
authorized; 147,527,114 and 146,034,014
shares issued and outstanding at December 31,
1994 and 1993, respectively . (At December 31,
1994, 166,893 shares were reserved for the
Employee Savings Plan and 3,277,655 shares
were reserved for the Dividend Reinvestment and
Stock Purchase Plan.) 1,425,378 1,391,464
Retained earnings 1,312,655 1,251,140
Unrealized loss on available for sale securities (3,646) -
Pension liability adjustment (16,521) (22,093)
Total common shareholders' equity 2,717,866 2,620,511
Total Capitalization $5,791,483 $5,995,340
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
37
Consolidated Statements of Income Taxes
YEAR ENDED DECEMBER 31,
1994 1993 1992
(DOLLAR AMOUNTS IN THOUSANDS)
INCOME TAXES
Current $ 82,767 $93,459 $ 85,287
Deferred
Change in tax effect of temporary differences 88,896 63,972 44,975
Change in income taxes recoverable through
future rates (8,580) (30,086) (18,061)
Deferred taxes credited (charged) to
shareholders' equity (1,038) 11,897 -
Deferred taxes charged to expense 79,278 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 (8,192) (8,444) (8,854)
Income taxes per Consolidated Statements of
Income $153,853 $138,072 $103,347
RECONCILIATION OF INCOME TAXES COMPUTED AT STATUTORY
FEDERAL RATE TO TOTAL INCOME TAXES
Income before income taxes $477,470 $447,938 $367,694
Statutory federal income tax rate 35% 35% 34%
Income taxes computed at statutory federal rate 167,115 156,778 125,016
Increases (decreases) in income taxes due to
Depreciation differences not normalized on
regulated activities 9,791 9,253 8,955
Allowance for equity funds used during
construction (7,611) (5,072) (4,723)
Amortization of deferred investment tax
credits (8,164) (8,444) (8,854)
Tax credits flowed through to income (1,754) (9,736) (804)
Change in federal corporate income tax
rate charged to expense - 7,274 -
Amortization of deferred tax rate
differential on regulated activities (1,885) (5,789) (7,365)
Other (3,639) (6,192) (8,878)
Total income taxes $153,853 $138,072 $103,347
Effective federal income tax rate 32.2% 30.8% 28.1%
AT DECEMBER 31, 1994 1993
(DOLLAR AMOUNTS IN THOUSANDS)
DEFERRED INCOME TAXES
Deferred tax liabilities
Accelerated depreciation $ 840,376 $ 789,165
Allowance for funds used during construction 208,726 202,490
Income taxes recoverable through future rates 93,952 90,950
Deferred termination and postemployment costs 53,749 55,890
Deferred fuel costs 41,507 45,518
Leveraged leases 31,948 32,613
Percentage repair allowance 36,630 35,431
Other 148,064 125,850
Total deferred tax liabilities 1,454,952 1,377,907
Deferred tax assets
Alternative minimum tax 71,074 73,203
Accrued pension and postemployment benefit costs 51,163 64,065
Deferred investment tax credits 52,288 55,099
Other 123,998 117,929
Total deferred tax assets 298,523 310,296
Deferred income taxes per Consolidated Balance Sheets $1,156,429 $1,067,611
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
38
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), BGE Home Products & Services, Inc. (HPS) and
BNG, Inc. are consolidated in the financial statements, and 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, respectively. 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 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 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.
Current tax expense consists solely of regular tax. In certain prior
years, tax expense included an alternative minimum tax (AMT) that 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,
1994, this carryforward totaled $71.1 million.
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 businesses other than leveraged
leases are flowed through to income.
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.
39
INVESTMENTS AND OTHER ASSETS
The Company adopted Statement of Financial Accounting Standards No. 115
(Statement No. 115), "Accounting for Certain Investments in Debt and
Equity Securities," effective January 1, 1994. Securities subject to the
requirements of Statement No. 115 are reported at fair value as of
December 31, 1994. Certain of Constellation Companies' marketable equity
securities totaling $24.3 million are classified as trading securities.
These securities are reported as other current assets, and unrealized
gains and losses are included in diversified businesses revenues. The
investments comprising the nuclear decommissioning trust fund and
certain marketable equity securities of CHI are classified as available
for sale. Unrealized gains and losses on these securities, as well as
CHI's portion of unrealized gains and losses on securities of
equity-method investees, are recorded in shareholders' equity. At
December 31, 1993 marketable equity securities are stated at the lower
of cost or market value.
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. Utility plant retired or otherwise disposed of is charged to
accumulated depreciation. 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 straight-line
rates applied to the average investment in classes of depreciable
property. Vehicles are depreciated based on their estimated useful
lives. Effective in 1995, BGE revised its utility plant depreciation
rates to reflect the results of a detailed depreciation study. The new
rates are expected to result in an increase in depreciation accruals of
approximately $21 million annually.
Depreciation expense for 1994 includes the write-off of certain
costs at BGE's Perryman site. Initially, BGE had planned to build two
combined cycle generating units at this site. However, due to
significant changes in the environment in which utilities operate, BGE
now has no plans to construct the second combined cycle generating unit.
Accordingly, during the third quarter of 1994, BGE wrote off $15.7
million of the costs associated with that second combined cycle unit.
This write-off reduced after-tax earnings during 1994 by $11.0 million
or 7 cents per share. Also in 1994, BGE reclassified the amortization of
deferred energy conservation expenditures and deferred nuclear
expenditures from operations expense to depreciation and amortization
expense. Prior-year amounts have been reclassified to conform with the
current year's presentation.
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 $143 million as of December 31, 1994. 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 sold. 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
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 $109.8
million and $93.4 million at December 31, 1994 and 1993, 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 have 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. The Company completed a
facility-specific study in 1995 which generated an estimate of $521
million in 1993 dollars to decommission the radioactive portion of the
plant. The Company plans to use the facility-specific cost estimate as a
basis for recording decommissioning expense in 1995, for 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.
Prior to 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.
The Constellation Companies capitalize interest on qualifying real
estate and power generation development projects. BGE capitalizes
interest on carrying charges accrued on certain deferred fuel costs as
discussed in Note 5.
40
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.
ACCOUNTING STANDARDS ISSUED
The Financial Accounting Standards Board has issued Statement of
Financial Accounting Standards Nos. 114 and 118, regarding accounting
for impairment of a loan, effective January 1, 1995. Adoption of these
statements is not expected to have a material impact on the Company's
financial statements.
NOTE 2. SEGMENT INFORMATION
1994 1993 1992
(IN THOUSANDS)
ELECTRIC
Nonaffiliated revenues $2,126,581 $2,112,147 $1,965,532
Affiliated revenues 840 - -
Total revenues 2,127,421 2,112,147 1,965,532
Income from operations 539,739 534,185 438,057
Depreciation and amortization 252,273 219,735 197,853
Construction expenditures (including AFC) 406,928 419,519 346,728
Identifiable assets at December 31 6,123,194 6,012,225 5,494,354
GAS
Total revenues (nonaffiliated) $ 421,249 $ 433,163 $ 400,399
Income from operations 35,205 34,738 40,598
Depreciation and amortization 32,478 23,875 21,513
Construction expenditures (including AFC) 76,131 58,359 42,688
Identifiable assets at December 31 733,624 690,783 575,513
DIVERSIFIED BUSINESSES
Nonaffiliated revenues $ 235,155 $ 196,075 $ 193,605
Affiliated revenues 15,649 6,825 6,468
Total revenues 250,804 202,900 200,073
Income from operations 60,315 47,469 56,654
Depreciation and amortization 11,199 10,303 10,149
Identifiable assets at December 31 1,158,162 1,166,997 1,090,667
TOTAL
Nonaffiliated revenues $2,782,985 $2,741,385 $2,559,536
Affiliated revenues 16,489 6,825 6,468
Intercompany eliminations (16,489) (6,825) (6,468)
Total revenues 2,782,985 2,741,385 2,559,536
Income from operations 635,259 616,392 535,309
Depreciation and amortization 295,950 253,913 229,515
Construction expenditures (including AFC) 483,059 477,878 389,416
Identifiable assets at December 31 8,014,980 7,870,005 7,160,534
Other assets at December 31 128,558 117,034 213,823
Total assets at December 31 8,143,538 7,987,039 7,374,357
CERTAIN PRIOR-YEAR AMOUNTS HAVE BEEN RECLASSIFIED TO CONFORM TO THE
CURRENT YEAR'S PRESENTATION.
41
NOTE 3. SUBSIDIARY INFORMATION
Diversified businesses consist of the operations of Constellation
Holdings, Inc. and its subsidiaries, BGE Home Products & Services, Inc.
(HPS), and BNG, Inc. Diversified businesses' operating expenses have
been reclassified as diversified businesses-selling, general, and
administrative expense in the consolidated statements of income.
Prior-year amounts have been reclassified to conform with the current
year s presentation.
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.
Effective July 1, 1994, BGE formed a wholly owned subsidiary, BGE
Home Products & Services, Inc., which engages in the businesses of
appliance and consumer electronics sales and service; heating,
ventilation, and air conditioning system sales, installation and
service; and home improvements and services.
BNG, Inc. is a wholly owned subsidiary which engages in natural gas
brokering.
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. The condensed financial information
does not reflect the elimination of inter-company balances or
transactions which are eliminated in the Company's consolidated
financial statements.
1994 1993 1992
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
Income Statements
Revenues
Real estate projects $ 106,915 $ 77,598 $ 76,582
Power generation systems 41,301 24,971 28,084
Financial investments 12,126 21,195 21,485
Total revenues 160,342 123,764 126,151
Expenses other than interest
and income taxes 107,267 80,707 77,154
Income from operations 53,075 43,057 48,997
Interest expense (45,782) (47,845) (43,903)
Capitalized interest 10,776 14,702 13,800`
Income tax benefit (expense) (4,305) 1,984 (3,637)
Net income $ 13,764 $ 11,898 $ 15,257
Contribution to the Company's
earnings per share of
common stock $ .09 $ .08 $ .11
Balance Sheets
Current assets $ 53,034 $ 54,039 $ 29,899
Noncurrent assets 1,055,056 1,036,507 990,273
Total assets $1,108,090 $1,090,546 $1,020,172
Current liabilities $ 70,670 $ 24,201 $ 113,404
Noncurrent liabilities 718,846 759,048 611,370
Shareholders' equity 318,574 307,297 295,398
Total liabilities and
shareholders' equity $1,108,090 $1,090,546 $1,020,172
42
NOTE 4. REAL ESTATE PROJECTS AND FINANCIAL INVESTMENTS
Real estate projects consist of the following investments held by the
Constellation Companies:
AT DECEMBER 31, 1994 1993
(IN THOUSANDS)
Properties under development $267,483 $249,473
Rental and operating properties
(net of accumulated
depreciation) 203,000 237,194
Other real estate ventures 952 730
Total $471,435 $487,397
Financial investments consist of the following investments held by
the Constellation Companies:
AT DECEMBER 31, 1994 1993
(IN THOUSANDS)
Insurance companies $ 87,700 $ 83,275
Marketable equity securities 51,175 42,681
Financial limited partnerships 48,014 44,903
Leveraged leases 37,451 38,669
Other securities - 3,787
Total $224,340 $213,315
The Constellation Companies' marketable equity securities and the
investments comprising the nuclear decommissioning trust fund are
classified as available for sale. The fair value and gross unrealized
gains and losses for available for sale securities, exclusive of $3.2
million of unrealized net losses on securities of equity-method
investees, are as follows:
Fair Unrealized Unrealized
AT DECEMBER 31, 1994 Value Gains Loss
(IN THOUSANDS)
Marketable equity securities $ 51,175 $1,276 $1,859
U.S. government agency 5,102 - 113
State municipal bonds 58,034 929 2,599
Total $114,311 $2,205 $4,571
Contractual maturities of debt securities:
(IN THOUSANDS)
Less than 1 year $ -
1-5 years 13,855
5-10 years 46,010
More than 10 years 4,765
Total $64,630
Gross realized gains and losses on available for sale securities
totaled $1.1 million and $3.1 million, respectively, in 1994. Net
realized gains from financial investments totaled $6.5 million in 1993
and $9.8 million in 1992.
NOTE 5. REGULATORY ASSETS
Certain utility expenses 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, 1994 1993
(IN THOUSANDS)
Income taxes recoverable
through future rates $268,436 $259,856
Deferred fuel costs 118,591 130,052
Deferred nuclear expenditures 90,937 86,726
Deferred termination
benefit costs 79,979 96,793
Deferred postemployment
benefit costs 73,591 62,892
Deferred cost of
decommissioning federal
uranium enrichment facilities 52,748 49,562
Deferred energy conservation
expenditures 45,534 38,655
Deferred environmental costs 35,015 32,966
Other 8,203 10,623
Total $773,034 $768,125
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.
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 reduced as they are collected from customers.
The underrecovered costs deferred under the fuel clauses were as
follows:
AT DECEMBER 31, 1994 1993
(IN THOUSANDS)
Electric
Costs deferred $152,815 $155,901
Reserve for possible
disallowance of replacement
energy costs (see Note 13) (35,000) (35,000)
Net electric 117,815 120,901
Gas 776 9,151
Total $118,591 $130,052
43
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 1994 associated
with nonrecurring phases of certain nuclear operations projects, and
expenditures incurred during 1990 for investigating leaks in the
pressurizer heater sleeves.
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 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 in
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 15-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
deferred fuel costs in excess of $72.8 million, net of related deferred
income taxes. 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 and
HPS. 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.
Prior service cost associated with retroactive plan amendments is
amortized on a straight-line basis over the average remaining service
period of active employees.
The Company's funding policy is to contribute at least the minimum
amount required under Internal Revenue Service regulations using the
projected unit credit cost method. Plan assets at December 31, 1994
consisted primarily of marketable fixed income and equity securities,
group annuity contracts, and short-term investments.
The tables on page 49 set forth the combined funded status of the
plans and the composition of total net pension cost. At December 31,
1994 and 1993, the accumulated pension obligation was greater than the
fair value of the Pension Plan's assets. As a result, the Company
recorded an additional pension liability, a portion of which was charged
to shareholders' equity.
Net pension cost shown below does not include the cost of
termination benefits described in Note 7.
44
AT DECEMBER 31, 1994 1993
(IN THOUSANDS)
Vested benefit obligation $ 622,445 $ 677,069
Nonvested benefit obligation 8,838 11,359
Accumulated benefit obligation 631,283 688,428
Projected benefits related to increase
in future compensation levels 82,815 109,161
Projected benefit obligation 714,098 797,589
Plan assets at fair value (614,284) (605,629)
Projected benefit obligation less
plan asset 99,814 191,960
Unrecognized prior service cost (23,863) (21,252)
Unrecognized net loss (112,546) (148,450)
Pension liability adjustment 52,177 58,553
Unamortized net asset from adoption of
FASB Statement No. 87 1,586 1,812
Accrued pension liability $ 17,168 $ 82,623
YEAR ENDED DECEMBER 31, 1994 1993 1992
(IN THOUSANDS)
Components of net pension cost
Service cost-benefits earned
during the period $ 15,015 $ 11,645 $ 11,771
Interest cost on projected
benefit obligation 58,723 51,183 47,355
Actual return on plan assets 7,932 (56,225) (33,685)
Net amortization and deferral (60,071) 6,591 (12,257)
Total net pension cost 21,599 13,194 13,184
Amount capitalized as
construction cost (2,578) (1,800) (1,839)
Amount charged to expense $ 19,021 $ 11,394 $ 11,345
The Company also sponsors a defined contribution savings plan covering
all eligible BGE employees and certain employees of the Constellation
Companies and HPS. Under this plan, the Company makes contributions on
behalf of participants. Company contributions to this plan totaled $8.7
million, $9.0 million, and $14.8 million in 1994, 1993, and 1992,
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 and HPS. 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.
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 20-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 in 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 postretirement
benefit costs as a regulatory asset. Accrual-basis PRB costs applicable
to nonregulated operations are charged to expense.
45
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, 1994 1993
Life Life
Health Care Insurance Health Care Insurance
(IN THOUSANDS)
Accumulated postretirement benefit obligation:
Retirees $ 161,134 $ 45,146 $ 182,638 $ 45,461
Fully eligible active employees 15,777 101 19,177 839
Other active employees 44,371 12,597 58,832 15,377
Total accumulated postretirement benefit obligation 221,282 57,844 260,647 61,677
Unrecognized transition obligation (158,725) (46,081) (179,764) (48,641)
Unrecognized net gain (loss) 1,238 (2,141) (36,675) (9,072)
Accrued postretirement benefit liability $ 63,795 $ 9,622 $ 44,208 $ 3,964
The following table sets forth the composition of net
post-retirement benefit cost. Net postretirement benefit cost shown
below does not include the cost of termination benefits described in
Note 7.
YEAR ENDED DECEMBER 31, 1994 1993
(IN THOUSANDS)
Net postretirement benefit cost:
Service cost-benefits earned during
the period $ 5,035 $ 4,373
Interest cost on accumulated postretirement
benefit obligation 23,037 20,451
Amortization of transition obligation 11,700 12,021
Net amortization and deferral 646 -
Total net postretirement benefit cost 40,418 36,845
Amount capitalized as construction cost (5,773) (5,898)
Amount deferred (10,213) (11,965)
Amount charged to expense $ 24,432 $ 18,982
Postretirement benefit costs recognized under the pay-as-you-go
method in 1992 totaled $11.7 million, of which $1.9 million was
capitalized and the remainder was charged to expense.
OTHER POSTEMPLOYMENT BENEFITS
The Company provides certain pay continuation payments and health and
life insurance benefits to employees of BGE and certain employees of the
Constellation Companies and HPS 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 $48 million and $52 million as of
December 31, 1994 and 1993, respectively. The portion of the
December 31, 1993 liability attributable to regulated activities was
deferred. The amounts deferred will be amortized over a 15-year period
beginning in 1998. The adoption of Statement No. 112 did not have a
material impact on net income.
ASSUMPTIONS
The pension and postemployment benefit liabilities were determined using
the following assumptions.
AT DECEMBER 31, 1994 1993
Assumptions:
Discount rate 8.5% 7.5%
Average increase in
future compensation levels 4.0% 4.5%
Expected long-term rate of
return on assets 9.0% 9.5%
The health care inflation rates for 1994 are assumed to be 9.0% for
Medicare-eligible retirees and 11.5% 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 $35 million as of December 31, 1994 and
would increase the aggregate of the service cost and interest cost
components of postretirement benefit cost by approximately $4 million
annually.
46
NOTE 7. TERMINATION BENEFITS
BGE 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 one-time 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.
BGE 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 one-time
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 is being 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 cost of
termination benefits was charged to expense in 1993.
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. Borrowings under the lines are at the banks' prime
rates, base interest rates, or at various money market rates.
1994 1993 1992
(DOLLAR AMOUNTS IN THOUSANDS)
BGE'S COMMERCIAL PAPER NOTES
Borrowings outstanding at December 31 $ 63,700 $ - $ 11,900
Weighted average interest rate of notes outstanding
at December 31 6.10% -% 3.62%
Unused lines of credit supporting commercial paper
notes at December 31 $ 148,000 $208,000 $ 203,000
Maximum borrowings during the year 187,500 96,900 393,650
Average daily borrowings during the year (a) 74,001 10,322 98,892
Weighted average interest rate for the year (b) 4.83% 3.28% 4.79%
CONSTELLATION COMPANIES' LINES OF CREDIT
Borrowings outstanding at December 31 $ - $ - $ -
Weighted average interest rate of borrowings
outstanding at December 31 -% -% -%
Unused lines of credit at December 31 $ - $ 20,000 $ -
Maximum borrowings during the year - - 60,670
Average daily borrowings during the year (a) - - 31,773
Weighted average interest rate for the year (b) -% -% 6.01%
<FN>
(A) THE SUM OF DOLLAR DAYS OF OUTSTANDING BORROWINGS DIVIDED BY THE
NUMBER OF DAYS IN THE PERIOD.
(B) TOTAL INTEREST ACCRUED DURING THE PERIOD DIVIDED BY AVERAGE DAILY
BORROWINGS.
47
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, HPS 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 5 1/2% Installment Series of 2002,
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 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 1996 and 1997. 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, 1994, BGE had no borrowings under these revolving credit
agreements and had available $125 million of unused capacity under these
agreements.
The Medium-term Notes Series A mature in February 1996. The weighted
average interest rate for notes outstanding at December 31, 1994 is
8.22%.
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, 1994 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, 1994 is 7.16%.
The principal amounts of the 5 1/2% Installment Series Mortgage Bonds
payable each year are as follows:
YEAR
(IN THOUSANDS)
1995 through 1997 $ 605
1998 and 1999 690
2000 and 2001 865
2002 6,725
LONG-TERM DEBT OF CONSTELLATION COMPANIES
The mortgage and construction loans and other collateralized notes have
varying terms. The $116.6 million of variable rate notes require
periodic payment of principal and interest with various maturities from
September 1995 through July 2009. The $13 million, 7.67% mortgage note
requires monthly interest payments and is due October 1, 1995. The $6.2
million, 7.73% mortgage note requires quarterly principal and interest
payments through March 15, 2009.
The unsecured notes outstanding as of December 31, 1994 mature in
accordance with the following schedule:
AMOUNT
(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
The Constellation Companies entered into an unsecured revolving
credit agreement on December 9, 1994 in the amount of $50 million. This
agreement matures December 9, 1997 and will be used to provide liquidity
for general corporate purposes. As of December 31, 1994, the
Constellation Companies had no borrowings under this agreement.
WEIGHTED AVERAGE INTEREST RATES FOR VARIABLE RATE DEBT
The weighted average interest rates for variable rate debt during 1994
and 1993 were as follows:
1994 1993
BGE
Floating rate series mortgage bonds 4.91% -%
Pollution control loan 2.80 2.39
Port facilities loan 3.02 2.53
Adjustable rate pollution control loan 3.13 3.00
Economic development loan 3.00 2.49
Constellation Companies
Mortgage and construction loans
and other collateralized notes 7.27 6.26
Loans under credit agreements - 5.94
48
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)
1995 $206,063 $ 56,112
1996 71,997 65,201
1997 80,653 125,389
1998 55,396 134,973
1999 251,467 116,425
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)
1995 $61,500
1996 26,000
1997 83,000
1998 33,000
1999 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, lease
payments for utility operations are charged to expense. Lease expense,
which is comprised primarily of operating leases, totaled $12.7 million,
$13.8 million, and $14.0 million for the years ended 1994, 1993, and
1992, respectively.
The future minimum lease payments at December 31, 1994 for long-term
noncancelable operating leases are as follows:
YEAR
(IN THOUSANDS)
1995 $ 4,185
1996 3,881
1997 3,447
1998 2,971
1999 1,409
Thereafter 5,347
Total minimum lease payments $21,240
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 22 years, with options to renew. The net book
value of property under operating leases was $148.8 million at December
31, 1994. The future minimum rentals to be received under operating
leases in effect at December 31, 1994 are as follows:
YEAR
(IN THOUSANDS)
1995 $ 13,143
1996 12,233
1997 11,062
1998 9,718
1999 9,082
Thereafter 73,693
Total minimum rentals $128,931
49
NOTE 12. TAXES OTHER THAN INCOME TAXES
Taxes other than income taxes were as follows:
YEAR ENDED DECEMBER 31, 1994 1993 1992
(IN THOUSANDS)
Real and personal property $112,492 $107,958 $100,419
Public service company franchise 48,143 48,693 45,654
Social security 35,269 35,724 34,911
Other 10,307 9,836 9,355
Total taxes other than income taxes 206,211 202,211 190,339
Amounts included above charged to accounts other than
taxes (6,478) (7,379) (7,335)
Taxes other than income taxes per Consolidated Statements
of Income $199,733 $194,832 $183,004
NOTE 13. COMMITMENTS, GUARANTEES, AND CONTINGENCIES
COMMITMENTS
BGE has made substantial commitments in connection with its construction
program for 1995 and subsequent years. In addition, BGE has entered into
two long-term contracts for the purchase of electric generating capacity
and energy. The contracts expire in 2001 and 2013. Total payments under
these contracts were $69.4, $68.7, and $60.6 million during 1994, 1993,
and 1992, respectively. At December 31, 1994, the estimated future
payments for capacity and energy that BGE is obligated to buy under
these contracts are as follows:
YEAR (IN THOUSANDS)
1995 $ 65,249
1996 62,880
1997 60,068
1998 60,699
1999 60,558
Thereafter 272,826
Total payments $582,280
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, 1994, the total amount of investment requirements committed
to by the Constellation Companies is $43.6 million.
In December, 1994, BGE and HPS entered into agreements with a
financial institution whereby BGE and HPS can sell on an ongoing basis
up to an aggregate of $40 million and $50 million, respectively, of an
undivided interest in a designated pool of customer receivables. Under
the terms of the agreements, BGE and HPS have limited recourse on the
receivables and have recorded a reserve for credit losses. At December
31, 1994, BGE and HPS had sold $30 million and $40 million of
receivables, respectively, under these agreements.
GUARANTEES
BGE has agreed to guarantee two-thirds of certain indebtedness incurred
by Safe Harbor Water Power Corporation. The amount of such indebtedness
totals $35 million, of which $23.3 million represents BGE' s share of
the guarantee. BGE assesses that the risk of material loss on the loans
guaranteed is minimal.
As of December 31, 1994, the total outstanding loans and letters of
credit of certain power generation and real estate projects guaranteed
by the Constellation Companies were $31.2 million. Also, the
Constellation Companies have agreed to guarantee certain other
borrowings of various power generation and real estate projects. The
Company has assessed 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 two titles designed to
reduce emissions of sulfur dioxide and nitrogen oxide (NOx) from
electric generating stations. Title IV contains provisions for
compliance in two separate phases. Phase I of Title IV became effective
January 1, 1995, and Phase II of Title IV must be implemented by 2000.
BGE met the requirements of Phase I by installing flue gas
desulfurization systems and fuel switching and through unit retirements.
BGE is currently examining what actions will be required in order to
comply with Phase II of the Act. However, BGE anticipates that
compliance will be attained by some combination of fuel switching, flue
gas desulfurization, unit retirements, or allowance trading.
At this time, plans for complying with NOx control requirements
under Title I of the Act are less certain because all implementation
regulations have not yet been finalized by the government. It is
expected that by the year 1999 these regulations will require additional
50
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 and
several state agencies that it is being considered a potentially
responsible party (PRP) with respect to the cleanup of certain
environmentally contaminated sites owned and operated by third parties.
In addition, a subsidiary of Constellation Holdings, Inc. has been named
as a defendant in a case concerning an alleged environmentally
contaminated site owned and operated by a third party. Cleanup costs for
these sites cannot be estimated, except that BGE's 15.79% share of the
possible cleanup costs at one of these sites, Metal Bank of America, a
metal reclaimer in Philadelphia, could exceed amounts recognized by up
to approximately $14 million based on the highest estimate of costs in
the range of reasonably possible alternatives. Although the cleanup
costs for certain of the remaining sites could be significant, BGE
believes that the resolution of these matters will not have a material
effect on its financial position or results of operations.
Also, BGE is coordinating investigation of several former gas
manufacturing plant sites, including exploration of corrective action
options to remove coal tar. However, no formal legal proceedings have
been instituted against BGE. BGE has recognized estimated environmental
costs at these sites totaling $37.9 million as of December 31, 1994.
These costs, net of accumulated amortization, have been deferred 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. BGE maintains various insurance
policies for these contingencies. The costs that could result from a
major accident or an extended outage at either of the Calvert Cliffs
units could exceed the coverage limits.
In addition, in the event of an incident at any commercial nuclear
power plant in the country, BGE could be assessed for a portion of any
third party claims associated with the incident. Under the provisions of
the Price Anderson Act, the limit for third party claims from a nuclear
incident is $8.92 billion. If third party claims relating to such an
incident exceed $200 million (the amount of primary insurance), BGE's
share of the total liability for third party claims could be up to $159
million per incident, that would be payable at a rate of $20 million per
year.
BGE and other operators of commercial nuclear power plants in the
United States are required to purchase insurance to cover claims of
certain nuclear workers. Other non-governmental commercial nuclear
facilities may also purchase such insurance. Coverage of up to $400
million is provided for claims against BGE or others insured by these
policies for radiation injuries. If certain claims were made under these
policies, BGE and all policyholders could be assessed, with BGE' s share
being up to $6.08 million in any one year.
For physical damage to Calvert Cliffs, BGE has $2.75 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 $14.3 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 $473.2 million
per unit of insurance, provided by the same industry mutual insurance
company for replacement power costs. This amount can be reduced by up to
$94.6 million per unit if an outage to both units at Calvert Cliffs is
caused by a singular insured physical damage loss. If 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 unit's adjusted actual generating
performance versus its performance target in determining compliance with
the law and the basis for possibly imposing a penalty on BGE. Parties to
fuel rate hearings may still question the prudence of BGE's actions or
inactions with respect to any given generating plant outage, which could
result in the disallowance of replacement energy costs by the PSC.
Since the two units at BGE's Calvert Cliffs Nuclear Power Plant
utilize BGE's lowest cost fuel, replacement energy costs associated
with outages at these units can be significant. BGE cannot estimate the
amount of replacement energy costs that could be challenged or
disallowed in future fuel rate proceedings, but such amounts could be
material.
51
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 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 its
Calvert Cliffs Nuclear Power Plant. In the Spring of 1989, a leak was
discovered around the Unit 2 pressurizer heater sleeves during a
refueling outage. BGE shut down Unit 1 as a precautionary measure on May
6, 1989 to inspect for similar leaks and none were found. However, Unit
1 was out of service for the remainder of 1989 and 285 days of 1990 to
undergo maintenance and modification work to enhance the reliability of
various safety systems, to repair equipment, and to perform required
periodic surveillance tests. Unit 2, which returned to service on May 4,
1991, remained out of service for the remainder of 1989, 1990, and the
first part of 1991 to repair the pressurizer, perform maintenance and
modification work, and complete the refueling. The replacement energy
costs associated with these extended outages for both units at Calvert
Cliffs, concluding with the return to service of Unit 2, is 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 value and fair value of
financial instruments included in the Consolidated Balance Sheets.
AT DECEMBER 31, 1994 1993
Carrying Fair Carrying Fair
Amount Value Amount Value
(IN THOUSANDS)
Current assets $ 382,776 $ 382,776 $ 496,919 $ 496,919
Investments and other assets 138,978 137,782 125,046 129,752
Current liabilities 768,932 768,932 443,968 443,968
Capitalization 2,864,432 2,699,103 3,165,644 3,303,616
52
Financial instruments included in current assets are cash and cash
equivalents, net accounts receivable, trading securities, and
miscellaneous loans receivable of the Constellation Companies. Financial
instruments included in current liabilities represent total current
liabilities from the balance sheet excluding accrued vacation costs. The
carrying amount of current assets and current liabilities approximates
fair value because of the short maturity of these instruments.
Investments and other assets include investments in common and
preferred securities, which are classified as financial investments in
the balance sheet, and the nuclear decommissioning trust fund. 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, 1994 and 1993 are excluded from the amounts
shown in investments and other assets because it was not practicable to
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
$23.3 million and $17.0 million, respectively, at December 31, 1994 and
$26.7 and $36.0 million, respectively, at December 31, 1993 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)
Revenues $767,686 $651,152 $753,878 $610,269 $2,782,985
Income from operations 162,559 136,778 232,472 103,450 635,259
Net income 82,145 66,708 126,616 48,148 323,617
Earnings applicable to common stock 72,114 56,687 116,714 38,180 283,695
Earnings per share of common stock 0.49 0.39 0.79 0.26 1.93
1993
Revenues $701,785 $583,812 $793,968 $661,820 $2,741,385
Income from operations 135,429 106,890 287,519 86,554 616,392
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
RESULTS FOR THE FIRST QUARTER OF 1994 REFLECT A $10.0 MILLION ONE-TIME
BONUS PAID TO EMPLOYEES IN LIEU OF A GENERAL INCREASE.
RESULTS FOR THE THIRD QUARTER OF 1994 REFLECT THE $15.7 MILLION ($11.0
MILLION AFTER-TAX) WRITE-OFF OF CERTAIN PERRYMAN COSTS (SEE NOTE 1).
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).
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.
CERTAIN PRIOR-YEAR AMOUNTS HAVE BEEN RECLASSIFIED TO CONFORM TO THE
CURRENT YEAR'S PRESENTATION.
53
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 13 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 20, 1995 of Coopers & Lybrand L.L.P.,
Independent Auditors
Consolidated Statements of Income for three years ended December 31,
1994
Consolidated Balance Sheets at December 31, 1994 and December 31,
1993
Consolidated Statements of Cash Flows for three years ended December
31, 1994
Consolidated Statements of Common Shareholders' Equity for three
years ended December 31, 1994
Consolidated Statements of Capitalization at December 31, 1994 and
December 31, 1993
Consolidated Statements of Income Taxes for three years ended
December 31, 1994
Notes to Consolidated Financial Statements
2. Financial Statement Schedules:
Schedule II -- Valuation and Qualifying Accounts
Schedules other than those listed above are omitted as not
applicable or not required.
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.
54
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
*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)
55
DESIGNATED IN
EXHIBIT
DATED FILE NO. NUMBER
*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 2
Form 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
*March 15, 1994 1-1910 (Form 10-K Annual Report for 1993) 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, as amended and restated.
*10(b) -- Executive Incentive Plan of the Baltimore Gas and Electric Company. (Designated as Exhibit No. 10(b)
to the Annual Report on Form 10-K for the year ended December 31, 1992, File No. 1-1910.)
10(c) -- Baltimore Gas and Electric Company 1995 Long-Term Incentive Plan.
*10(d) -- Baltimore Gas and Electric Company Non-qualified Deferred Compensation Plan for Executive Officers.
(Designated as Exhibit No. 10(d) to the Annual Report on Form 10-K for the year ended December 31,
1992, File No. 1-1910.)
*10(e) -- Baltimore and 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). (Designated as Exhibit No. 10(f) to the Annual Report on Form 10-K for the year ended
December 31, 1993, File No. 1-1910.)
10(f) -- Baltimore Gas and Electric Company Retirement Plan for Non-Employee Directors, as amended and
restated.
*10(g) -- Summary of Baltimore Gas and Electric Company Long Term Performance Program. (Designated as Exhibit
No. 10(h) to the Annual Report on Form 10-K for the year ended December 31, 1993, File No. 1-1910.)
10(h) -- Grantor Trust Agreement Dated as of July 31, 1994 between Baltimore Gas and Electric Company and
Citibank, N.A.
10(i) -- Constellation Holdings, Inc., Summary of Amended Executive Benefits Plan.
*10(j) -- Summary of Constellation Holdings, Inc. Annual Incentive Plan. (Designated as Exhibit No. 10(g) to
the Annual Report on Form 10-K for the year ended December 31, 1992, File No. 1-1910.)
*10(k) -- Amended Summary 1992 Long Term Incentive Plan of Constellation Holdings, Inc. (Designated as Exhibit
No. 10(k) to the Annual Report on Form 10-K for the year ended December 31, 1993, File No. 1-1910.)
10(l) -- Summary 1994-96 Long Term Incentive Plan of Constellation Holdings, Inc.
56
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 L.L.P., Independent Auditors (see page 62 in this Form 10-K).
27 -- Financial Data Schedule.
*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
57
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
COLUMN C
COLUMN B ADDITIONS
BALANCE CHARGED COLUMN E
AT TO BALANCE
BEGINNING COSTS CHARGED TO OTHER COLUMN D AT END
COLUMN A OF AND ACCOUNTS -- (DEDUCTIONS) -- 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
1994.................................... $13,957 $20,557 $ - $(19,554)(A) $14,960
1993.................................... 12,484 19,155 - (17,682)(A) 13,957
1992.................................... 11,911 18,910 - (18,337)(A) 12,484
Valuation Allowance --
Net unrealized loss on available for
sale securities
1994.................................... - - 5,609(B) - 5,609
1993.................................... - - - - -
1992.................................... - - - - -
Provision for possible disallowance of
replacement energy costs
1994.................................... 35,000 - - - 35,000
1993.................................... 35,000 - - - 35,000
1992.................................... 35,000 - - - 35,000
Loan loss reserve
1994.................................... 5,123 - - (5,123)(C) -
1993.................................... 4,382 741 - - 5,123
1992.................................... 3,856 526 - - 4,382
Energy project reserves
1994.................................... 1,778 28 - - 1,806
1993.................................... 492 1,286 - - 1,778
1992.................................... 494 - - (2)(D) 492
<FN>
(A) Represents principally net amounts charged off as uncollectible.
(B) Represents net unrealized loss charged to common shareholders' equity.
(C) Represents reversal of loan loss reserve due to reclassification of this
amount as part of the purchase price of certain real estate partnership
interests.
(D) Represents recovery of subsidiary's project development costs previously
reversed as uncollectible.
58
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)
By /s/ C. H. POINDEXTER
Date: March 17, 1995
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 and Director March 17, 1995
C. H. POINDEXTER
Principal financial and accounting officer:
By /s/ C. W. SHIVERY Vice President and Secretary March 17, 1995
C. W. SHIVERY
Directors:
/s/ B. B. BYRON Director March 17, 1995
B. B. BYRON
/s/ J. O. COLE Director March 17, 1995
J. O. COLE
/s/ D. A. COLUSSY Director March 17, 1995
D. A. COLUSSY
/s/ E. A. CROOKE Director March 17, 1995
E. A. CROOKE
/s/ J. R. CURTISS Director March 17, 1995
J. R. CURTISS
/s/ F. A. HRABOWSKI III Director March 17, 1995
F. A. HRABOWSKI
/s/ N. LAMPTON Director March 17, 1995
N. LAMPTON
/s/ G. V. MCGOWAN Director March 17, 1995
G. V. MCGOWAN
59
/s/ G. L. RUSSELL, JR. Director March 17, 1995
G. L. RUSSELL, JR.
/s/ M. D. SULLIVAN Director March 17, 1995
M. D. SULLIVAN
60
EXHIBIT INDEX
EXHIBIT PAGE
NUMBER 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
*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)
61
DESIGNATED IN
EXHIBIT PAGE EXHIBIT
NUMBER NUMBER DATED FILE NO. NUMBER
*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 2
by Form 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
*March 15, 1994 1-1910 (Form 10-K Annual Report for 1993) 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 as amended and restated.
*10(b) -- Executive Incentive Plan of the Baltimore Gas and Electric Company. (Designated as Exhibit
No. 10(b) to the Annual Report on Form 10-K for the year ended December 31, 1992, File No.
1-1910.)
10(c) -- Baltimore Gas and Electric Company 1995 Long-Term Incentive Plan.
*10(d) -- Baltimore Gas and Electric Company Non-qualified Deferred Compensation Plan for Executive
Officers. (Designated as Exhibit No. 10(d) to the Annual Report on Form 10-K for the year
ended December 31, 1992, File No. 1-1910.)
*10(e) -- Baltimore and 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). (Designated as Exhibit No. 10(f) to the Annual Report on
Form 10-K for the year ended December 31, 1993, File No. 1-1910.)
10(f) -- Baltimore Gas and Electric Company Retirement Plan for Non-Employee Directors, as amended
and restated.
*10(g) -- Summary of Baltimore Gas and Electric Company Long Term Performance Program. (Designated as
Exhibit No. 10(h) to the Annual Report on Form 10-K for the year ended December 31, 1993,
File No. 1-1910.)
10(h) -- Grantor Trust Agreement Dated as of July 31, 1994 between Baltimore Gas and Electric
Company and Citibank, N.A.
10(i) -- Constellation Holdings, Inc., Summary of Amended Executive Benefits Plan.
62
EXHIBIT PAGE
NUMBER NUMBER
*10(j) -- Summary of Constellation Holdings, Inc. Annual Incentive Plan. (Designated as Exhibit No.
10(g) to the Annual Report on Form 10-K for the year ended December 31, 1992, File No.
1-1910.)
*10(k) -- Amended Summary 1992 Long Term Incentive Plan of Constellation Holdings, Inc. (Designated
as Exhibit No. 10(k) to the Annual Report on Form 10-K for the year ended December 31,
1993, File No. 1-1910.)
10(l) -- Summary 1994-96 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 L.L.P., Independent Auditors (see page 62 in this Form 10-K).
27 -- Financial Data Schedule.
*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 10-K: None
63