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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES AND EXCHANGE ACT OF 1934
For the fiscal year ended 1-1910
December 31, 1993 Commission file number
------------------------
BALTIMORE GAS AND ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
MARYLAND 52-0280210
(State of incorporation) (I.R.S. Employer Identification No.)
GAS AND ELECTRIC BUILDING, CHARLES
CENTER, 21201
BALTIMORE, MARYLAND (Zip Code)
(Address of principal executive offices)
410-783-5920
(Registrant's telephone number, including area code)
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
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New York Stock Exchange, Inc.
Common Stock -- Without Par Value Chicago Stock Exchange, Inc.
Pacific Stock Exchange, Inc.
Preferred Stock, Series B 4 1/2%, Cumulative,
$100 Par Value New York Stock Exchange, Inc.
Preferred Stock, Cumulative, $100 Par Value:
Series C 4%
Series D 5.40%
Preference Stock, Cumulative, $100 Par Value: Philadelphia Stock Exchange, Inc.
7.78%, 1973 Series
7.50%, 1986 Series
6.75%, 1987 Series
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
Not Applicable
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months, and (2) has been subject to such filing
requirements for the past 90 days. Yes _x_ No __.
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K (Section 229.405 of this chapter) is not contained herein,
and will not be contained, to the best of registrant's knowledge, in definitive
proxy or information statements incorporated by reference in Part III of this
Form 10-K or any amendment to this Form 10-K. /X/
Aggregate market value of Common Stock, without par value, held by
non-affiliates as of February 28, 1994 was approximately $3,395,220,704 based
upon New York Stock Exchange composite transaction closing price.
COMMON STOCK, WITHOUT PAR VALUE -- 146,446,343 SHARES OUTSTANDING ON FEBRUARY
28, 1994.
DOCUMENTS INCORPORATED BY REFERENCE
PART OF FORM 10-K DOCUMENT INCORPORATED BY REFERENCE
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III Definitive Proxy Statement for the Annual Meeting of Shareholders of
Baltimore Gas and Electric Company to be held on April 20, 1994
(Proxy Statement).
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TABLE OF CONTENTS
PAGE
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PART I
Item 1 -- Business
General...................................... 1
Capital Requirements......................... 2
Rate Matters................................. 3
Nuclear Operations........................... 4
Load Management, Energy, and Capacity
Purchases.................................... 5
Fuel for Electric Generation................. 6
Gas Operations............................... 7
Environmental Matters........................ 8
Electric Operating Statistics................ 11
Gas Operating Statistics..................... 12
Franchises................................... 13
Diversified Businesses....................... 13
Employees.................................... 15
Item 2 -- Properties................................... 16
Item 3 -- Legal Proceedings............................ 16
Submission of Matters to a Vote of Security
Item 4 -- Holders...................................... 17
Executive Officers of the Registrant
(Instruction 3 to Item 401(b) of Regulation
Item 10 -- S-K)......................................... 18
PART II
Market for Registrant's Common Equity and
Item 5 -- Related Stockholder Matters.................. 19
Item 6 -- Selected Financial Data...................... 20
Management's Discussion and Analysis of
Financial Condition and Results of
Item 7 -- Operations................................... 21
Financial Statements and Supplementary
Item 8 -- Data......................................... 29
Changes in and Disagreements with Accountants
Item 9 -- on Accounting and Financial Disclosure....... 56
PART III
Directors and Executive Officers of the
Item 10 -- Registrant................................... 56
Item 11 -- Executive Compensation....................... 56
Security Ownership of Certain Beneficial
Item 12 -- Owners and Management........................ 56
Certain Relationships and Related
Item 13 -- Transactions................................. 56
PART IV
Exhibits, Financial Statement Schedules and
Item 14 -- Reports on Form 8-K.......................... 56
Signatures........................................................... 66
PART I
ITEM 1. BUSINESS
Baltimore Gas and Electric Company and Subsidiaries are herein collectively
referred to as the Company. The Company is engaged in utility operations and
related businesses through Baltimore Gas and Electric Company (BGE). The Company
is engaged in diversified businesses primarily through BGE's wholly owned
subsidiary, Constellation Holdings, Inc. and its subsidiaries (collectively, the
Constellation Companies).
BGE was incorporated under the laws of the State of Maryland on June 20,
1906, and is primarily engaged in the business of producing, purchasing, and
selling electricity, and purchasing, transporting, and selling natural gas
within the State of Maryland. BGE is qualified to do business in the District of
Columbia where its federal affairs office is located. BGE is qualified to do
business in the Commonwealth of Pennsylvania where it is participating in the
ownership and operation of two electric generating plants as described under
ITEM 2. PROPERTIES -- ELECTRIC. BGE also owns two-thirds of the outstanding
capital stock, including one-half of the voting securities, of Safe Harbor Water
Power Corporation (Safe Harbor), a hydroelectric producer on the Susquehanna
River at Safe Harbor, Pennsylvania. (SEE ITEM 2. PROPERTIES -- ELECTRIC.) BNG,
Inc. is a wholly owned subsidiary of BGE which invests in natural gas reserves.
Other business of BGE includes the sale and service of gas and electric
appliances; BGE intends to emphasize this business in the future and will form a
subsidiary during 1994 to direct this effort. For financial information by
segment of operation see NOTE 2 TO CONSOLIDATED FINANCIAL STATEMENTS.
BGE furnishes electric and gas retail services in the City of Baltimore and
in all or part of nine counties in Central Maryland. The electric service
territory includes an area of approximately 2,300 square miles with an estimated
population of 2,602,000. The gas service territory includes an area of
approximately 625 square miles with an estimated population of 1,963,000. There
are no municipal or cooperative bulk power markets within BGE's service
territory.
Electric utilities presently face competition in the construction of
generating units to meet future load growth and in the sale of electricity in
the bulk power markets. On March 25, 1993, the Public Service Commission of
Maryland (PSC) issued BGE a Certificate of Public Convenience and Necessity
authorizing BGE to construct a 140-megawatt combustion turbine at its Perryman
site. The PSC further required BGE to implement a competitive bidding program
for the selection of a third-party power supplier for the increment of electric
generating capacity needed after the Perryman combustion turbine. BGE announced
March 11, 1994 that PECO Energy won the competitive bidding with a proposal to
supply 140 megawatts for 25 years beginning June 1, 1997. Electric and gas
utilities also face the future prospect of competition for electric and gas
sales to retail customers. It is not possible to predict the ultimate effect
competition will have on BGE's earnings in future years.
As discussed throughout this report, the two units at BGE's Calvert Cliffs
Nuclear Power Plant are its principal generating facilities and have the lowest
fuel cost in BGE's system. An extended shutdown of either of these Units could
have a substantial adverse effect on the Company's business and financial
condition. Furthermore, BGE does not consider it possible to obtain insurance
adequate to cover all the costs that could result from a major incident or an
extended outage at either of the Calvert Cliffs Units. (SEE NUCLEAR OPERATIONS
AND NOTE 13 TO CONSOLIDATED FINANCIAL STATEMENTS for information regarding prior
outages at the Plant.)
The Constellation Companies' businesses are discussed under DIVERSIFIED
BUSINESSES on page 13 and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS (MD&A).
The percentages of Operating Revenues and Operating Income attributable to
electric, gas, and diversified operations are set forth below:
OPERATING REVENUES OPERATING INCOME*
------------------------- -------------------------
ELECTRIC GAS DIVERSIFIED ELECTRIC GAS DIVERSIFIED
------- -- ---------- ------- -- ----------
1993..................... 79% 16% 5% 83% 7 % 10%
1992..................... 79 16 5 81 9 10
1991..................... 81 15 4 87 8 5
1990..................... 79 17 4 77 10 13
1989..................... 76 20 4 78 11 11
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*net of income taxes
BGE currently derives approximately 23% of electric revenues and 42% of gas
revenues from customers located in the City of Baltimore and 77% and 58%,
respectively, from outside the City of Baltimore. No single customer's electric
revenues exceed 4% of total electric revenues and no single customer's gas
revenues exceed 4% of total gas revenues.
1
The disparity between the percentage of gas operating revenues in relation
to the percentage of gas operating income as compared to the same percentages
for electric operations is due to BGE's level of investment and its fuel costs
in each of these segments. BGE's operating revenue amounts represent recovery of
all fuel and operating expenses plus a return on its investment in the business.
BGE's net investment for ratemaking purposes in the electric business is $4.5
billion while the comparable investment in its gas business is less than $450
million. Thus, operating revenues include a much greater return component for
electric operations than gas operations. Also, as can be seen by referring to
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA, CONSOLIDATED STATEMENTS OF
INCOME on page 30, gas purchased for resale as a percentage of gas revenues
(56%) is greater than electric fuel and purchased energy as a percentage of
electric revenues (25%). It should be noted that both purchased gas costs and
electric fuel costs are passed through to the customer with no mark-up for
profit. The combined effects of these factors yield the observed relationship
between operating revenues and income for electric and gas operations.
CAPITAL REQUIREMENTS
The Company's actual capital requirements for 1991 through 1993, along with
estimated amounts for 1994 through 1996, are set forth below:
1991 1992 1993 1994 1995 1996
--------- --------- --------- --------- --------- ---------
(IN MILLIONS)
Utility Business
Construction expenditures (excluding AFC)
Electric..................................................... $ 328 $ 292 $ 360 $ 345 $ 319 $ 300
Gas.......................................................... 43 36 51 54 60 56
Common....................................................... 48 39 44 51 46 44
--------- --------- --------- --------- --------- ---------
Total construction expenditures.............................. 419 367 455 450 425 400
AFC (a)........................................................ 37 22 23 34 35 25
Deferred nuclear expenditures (b).............................. 23 16 14 12 -- --
Deferred energy conservation
expenditures (b).............................................. 3 20 33 48 45 40
Nuclear fuel (uranium purchases and processing charges)........ 2 40 47 42 46 51
Retirement of long-term debt and redemption of preference stock
(c)........................................................... 339 486 907 36 281 98
--------- --------- --------- --------- --------- ---------
Total utility business......................................... 823 951 1,479 622 832 614
--------- --------- --------- --------- --------- ---------
Diversified Businesses........................................... 276 198 300 72 141 97
--------- --------- --------- --------- --------- ---------
Total........................................................ $ 1,099 $ 1,149 $ 1,779 $ 694 $ 973 $ 711
--------- --------- --------- --------- --------- ---------
--------- --------- --------- --------- --------- ---------
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(a) Allowance for Funds Used During Construction (AFC) is accrued for all
construction projects with a construction period of more than one month
beginning January 1, 1992. (SEE NOTE 1 TO CONSOLIDATED FINANCIAL STATEMENTS
for a discussion of AFC.)
(b) See NOTE 5 TO CONSOLIDATED FINANCIAL STATEMENTS for a discussion of
deferred nuclear expenditures and deferred energy conservation
expenditures.
(c) The 1994 amount does not reflect the early redemption of the following
bonds: the 7 1/4% Series due April 15, 2001 First Refunding Mortgage Bonds
which were redeemed effective March 11, 1994, at 101.88% of principal, and
the 7% Series due 1998 First Refunding Mortgage Sinking Fund Bonds which
will be redeemed effective April 18, 1994, at 101.11% of principal.
BGE's actual capital requirements may vary from the estimates set forth
above because of a number of factors such as inflation, economic conditions,
regulation, legislation, load growth, environmental protection standards, and
the cost and availability of capital. The Constellation Companies' capital
requirements for diversified businesses may vary from the estimates set forth
above due to a number of factors including market and economic conditions and
are discussed in detail under MD&A -- DIVERSIFIED BUSINESSES CAPITAL
REQUIREMENTS on page 28.
BGE's estimated construction, nuclear fuel, deferred nuclear expenditures,
and deferred energy conservation expenditures are expected to amount to
approximately $2.1 billion, $250 million, $12 million, and $200 million,
respectively, for the five-year period 1994-1998. Electric construction
expenditures reflect the installation of two 5,000 kilowatt diesel generators at
Calvert Cliffs Nuclear Power Plant, scheduled to be placed in service in 1995;
the construction of a 140-megawatt combustion turbine at Perryman, scheduled to
be placed in service in
2
1995, which the PSC authorized in an order dated March 25, 1993; and
improvements in BGE's existing generating plants and its transmission and
distribution facilities. Future electric construction expenditures do not
include additional generating units in light of the competitive bidding process
established by the PSC as discussed on page 1. The Company estimates currently
that expenditures for compliance with the sulfur dioxide provisions of the Clean
Air Act of 1990 will total approximately $55 million through 1995.
During the period January 1, 1989 through December 31, 1993, BGE expended
$2,299 million for gross additions to utility plant or approximately 32% of its
total utility plant (exclusive of nuclear fuel) at December 31, 1993. During the
same period, a total of $272 million of utility plant was retired. Nuclear fuel
expenditures include uranium purchases and processing charges.
BGE presently estimates that approximately $750 million will be required for
retirements and redemptions of long-term debt (including sinking fund payments)
and BGE preference stock during the five-year period 1994-1998.
For further information with respect to capital requirements and for a
discussion of internal generation of cash, see ITEM 7. MD&A -- LIQUIDITY AND
CAPITAL RESOURCES.
RATE MATTERS
ELECTRIC AND GAS BASE RATE DECISION
On April 23, 1993, the PSC issued an Order (the 1993 Rate Order) authorizing
BGE annualized electric and gas base rate increases of $84.9 million and $1.6
million, respectively. The increases are equivalent to 4.5% and 0.4% of total
electric and gas revenues, respectively. In granting the increases, the PSC
provided a return on BGE's higher level of electric and gas rate base and
recognized increases in electric operating expenses associated primarily with
maintaining and improving system reliability. This was partially offset by a
reduction in the authorized rate of return to 9.40% from the 9.94% rate of
return previously authorized.
The 1993 Rate Order also provided for recovery of one-half of the annual
level of the increase in postretirement benefit costs under Statement of
Financial Accounting Standards No. 106. The PSC directed BGE to defer the
remainder of the annual increase in these costs for inclusion in BGE's next base
rate proceeding and provided that costs deferred during the intervening period
will be amortized over a fifteen-year period beginning in 1998.
ENERGY CONSERVATION SURCHARGE
The PSC approved a base rate surcharge effective July 1, 1992 which provides
for the recovery of deferred energy conservation expenditures, a return thereon,
lost revenues, and incentives for achievement of predetermined goals for certain
conservation programs subject to an earnings test. The compensation for foregone
sales due to conservation programs and the incentives for achieving conservation
goals must be refunded to customers if BGE is earning in excess of its
authorized rate of return, as determined by the PSC. (See discussion in ITEM 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS.) The surcharge is reset on July 1 of each
year.
ELECTRIC FUEL RATE PROCEEDINGS
By statute, electric fuel costs are recoverable if the PSC finds that BGE
demonstrates that, among other things, it has maintained the productive capacity
of its generating plants at a reasonable level. The PSC and Maryland's highest
appelate court have interpreted this as permitting a subjective evaluation of
each unplanned outage at BGE's generating plants to determine whether or not BGE
had implemented all reasonable and cost effective maintenance and operating
control procedures appropriate for preventing the outage. The PSC has
established a Generating Unit Performance Program (GUPP) to measure annual
utility compliance with maintaining the productive capacity of generating plants
at reasonable levels by establishing a system-wide generating performance target
and individual performance targets for each base load generating unit. As a
result, actual generating performance, after adjustment for planned outages, is
compared to the system-wide target and, if met, should signify compliance with
the requirements of Maryland law. Failure to meet the system-wide target will
result in review of each unit's adjusted actual generating performance versus
its performance target in determining compliance with the law, and the basis for
possibly imposing a penalty on BGE. Failure to meet these targets requires BGE
to demonstrate that the outages causing the failure are not the result of
mismanagement. Parties to fuel rate hearings may still question the prudence of
BGE's actions or inactions with respect to any given generating plant outage,
which could result in a disallowance of replacement energy costs. BGE is
involved in fuel rate proceedings annually where issues concerning individual
plant outages can be raised. Recovery of a portion of replacement energy costs
has been denied in past proceedings and BGE cannot estimate the amount that
could be denied in future fuel rate proceedings, but such amounts could be
material. (See NUCLEAR OPERATIONS.)
BGE is required to submit to the PSC the actual generating performance data
for each calendar year 45 days after year end. The PSC reviews BGE's performance
for each calendar year in the first fuel rate proceeding initiated following the
submission of the actual generating performance data for that year. BGE must
initiate fuel
3
rate proceedings in any month following a month during which the calculated fuel
rate decreased by more than 5% and may initiate fuel rate proceedings in any
month following a month during which the calculated fuel rate increased by more
than 5%.
NUCLEAR OPERATIONS
Discussed below are certain events relating to the operations of the Calvert
Cliffs Nuclear Power Plant (the Plant) during the period 1987 to the present
including issues involving the possible disallowance of replacement energy costs
incurred during unplanned outages at the Plant. All outstanding issues will be
resolved in fuel rate proceedings before the PSC which are conducted in
accordance with the procedures outlined above under RATE MATTERS -- ELECTRIC
FUEL RATE PROCEEDINGS.
OPERATIONS IN 1987
The Plant generated 10,069,576 megawatt hours (MWH) in 1987 which resulted
in a capacity factor of 70%. In October 1988, BGE filed a fuel rate application
for a change in its electric fuel rate under GUPP, which covered BGE's operating
performance in 1987. This was the first proceeding filed under this program and
BGE's filing demonstrated that it met the system-wide and individual plant
performance targets for 1987, including the performance target for the Plant.
BGE believes, therefore, it is entitled to recover all fuel costs incurred in
1987 without any disallowances. However, People's Counsel alleges that a number
of the outages at the Plant (including the 66-day outage described below) were
due to management imprudence and requests that the PSC disallow recovery of the
associated replacement energy costs which BGE estimates to be approximately $33
million. (See NOTE 13 TO CONSOLIDATED FINANCIAL STATEMENTS.) This matter is
awaiting a decision by a hearing examiner.
In late March, 1987, the Nuclear Regulatory Commission (NRC) conducted an
inspection of the Plant for the purpose of examining BGE's compliance with
environmental qualification requirements mandated by NRC regulations. These
regulations require the establishment of a qualification file for the purpose of
demonstrating proof of operability of designated electric equipment regarded as
important to safety. This written proof of operability is related to the ability
of the equipment to function under harsh environments, such as extreme
temperatures, humidity, and radiation. The NRC's inspections revealed cable
splices that were lacking required documentation demonstrating compliance with
NRC regulations. The inspection results from Unit 2, which was shut down for
maintenance and refueling at the time of inspection, indicated a sufficient
number of equipment qualification problems that BGE shut down Unit 1 on April 1,
1987, in order to inspect for similar nonqualified electrical connections.
Subsequently, BGE identified an additional problem regarding the certification
of piping system fasteners with mechanical safety requirements. The fasteners
must be certified as meeting specified American Society of Mechanical Engineers
requirements; however, BGE was unable to document that all of the fasteners in
question had been certified. BGE received a notice of violation from the NRC in
connection with the environmental qualifications problem and paid civil
penalties in the amount of $300,000. In addition, the Calvert Cliffs Units were
out of service for a total of 66 days in order to document compliance with these
environmental and mechanical qualification requirements.
OPERATIONS IN 1988
The Plant generated 11,733,900 MWH in 1988 which resulted in a capacity
factor of 81%. BGE filed a fuel rate application under GUPP in May, 1989 in
which it demonstrated that it met the system-wide and individual plant
performance targets for 1988. People's Counsel alleged that BGE imprudently
managed several outages at the Plant and requested that the PSC disallow
recovery of $2 million of replacement energy costs. On November 14, 1991, a
Hearing Examiner at the PSC issued a proposed Order, which became final on
December 17, 1991 and concluded that no disallowance was warranted. The Hearing
Examiner found that BGE maintained the productive capacity of the Plant at a
reasonable level, noting that it produced a near record amount of power and
exceeded the GUPP standard. Based on this record, the Order concluded there was
sufficient cause to excuse any avoidable failures to maintain productive
capacity at higher levels.
OPERATIONS IN 1989 TO 1991 -- EXTENDED OUTAGE
The Plant generated 2,719,197 MWH in 1989 and 1,251,416 MWH in 1990. In the
Spring of 1989, a leak was discovered around the Unit 2 pressurizer heater
sleeves during a refueling outage. BGE shut down Unit 1 as a precautionary
measure on May 6, 1989 to inspect for similar leaks and none were found at that
time. However, Unit 1 was out of service for the remainder of 1989 and 285 days
of 1990 to undergo maintenance and modification work to enhance the reliability
of various safety systems, to repair equipment, and to perform required periodic
surveillance tests. Unit 2 remained out of service until May 4, 1991 to complete
repair of the pressurizer, perform maintenance and modification work, and
complete the refueling. The replacement energy costs associated with these
extended outages for both Units at Calvert Cliffs, concluding with the return to
service of Unit 2, are estimated to be $458 million. This estimate is based on a
computer simulation comparing the actual operating conditions during the
extended outages with operating conditions assuming the Plant ran at its
targeted capacity factor.
4
The extended outages experienced at the Plant are being reviewed by the PSC
in the 1989-1991 fuel rate proceeding, and People's Counsel and others have
challenged recovery of some part of the associated replacement energy costs. In
the PSC's Rate Order issued in BGE's 1990 Base Rate Case, it found that $4
million of operations and maintenance expenses incurred by BGE during the
1989-1990 outages at the Plant should not be recoverable from customers. The PSC
concluded that the related work, which was performed at Unit 1 during the
1989-1990 outage, was avoidable and caused by Company actions which were
deficient. The work characterized as avoidable had a significant impact on the
duration of the Unit 1 outage. The PSC's Order stated that its conclusions in
this proceeding did not have a binding effect in the fuel rate proceeding on the
recoverability of Calvert Cliffs' replacement energy costs. However, BGE
believes that it is doubtful that the PSC will authorize recovery of the full
amount of replacement energy costs presently under investigation. Based on a
review of the circumstances surrounding the extended outages by BGE personnel as
well as independent consultants, in 1990 BGE recorded a provision of $35 million
against the possible disallowance of such costs. However, BGE cannot determine
whether replacement energy costs may be disallowed in the 1989-1991 fuel rate
proceeding in excess of the provision, but such amounts could be material.
On March 15, 1994, the PSC Staff and the Office of People's Counsel filed
testimony in the 1989-1991 fuel rate proceedings. The PSC Staff concluded that
approximately 46% of the outage time was unreasonably incurred and that
approximately $200 million of replacement energy costs should be disallowed.
People's Counsel concluded that approximately $400 million of the replacement
energy costs should be disallowed. BGE is tentatively scheduled to file rebuttal
testimony in mid-August of 1994 at which time it will vigorously contest the
findings of Staff and People's Counsel. Further hearings in this matter are not
scheduled until mid-year of 1995.
As previously reported, in December 1988, the NRC categorized the Plant as
one requiring close monitoring and increased NRC attention. The NRC did so
following certain events that the NRC indicated raised questions about the
effectiveness of past corrective action regarding engineering and technical
areas and the overall approach to safety at the Plant. Details of such events
were described in the Report on Form 10-K for the year ended December 31, 1990
in the section titled "Nuclear Operations" on pages 4 through 7. In February
1992, the NRC removed the Plant from its list of nuclear plants categorized as
requiring close monitoring as a result of improved performance in previously
identified problem areas and the demonstration of a sustained period of safe
operation.
OPERATIONS IN 1991 AFTER THE EXTENDED OUTAGE
The Plant generated 9,036,100 MWH in 1991, which resulted in a capacity
factor of 63%. BGE filed a fuel rate application under GUPP in June 1992,
however, the Hearing Examiner has determined that the 1991 case will not be
addressed until the case covering the extended outage has been resolved.
OPERATIONS IN 1992
The Plant generated 10,663,950 MWH in 1992, which resulted in a capacity
factor of 74%. BGE's fuel rate application under GUPP for 1992 demonstrated that
the Plant exceeded its individual plant performance targets and that system-wide
performance exceeded targeted levels. There are no contested performance issues
based on 1992 performance.
OPERATIONS IN 1993
The Plant generated 12,300,816 MWH in 1993, which resulted in a capacity
factor of 85%. BGE's fuel rate application under GUPP for 1993 demonstrated that
the Plant exceeded its individual plant performance targets and that system-wide
performance exceeded targeted levels.
LOAD MANAGEMENT, ENERGY, AND CAPACITY PURCHASES
BGE has implemented various active load management programs designed to be
used when system operating conditions require a reduction in load. These
programs include customer-owned generation and curtailable service for large
commercial and industrial customers, air conditioning control which is available
to residential and commercial customers, and residential water heater control.
The load reductions typically have been invoked on peak summer days; the summer
peak capacity impact for 1994 from active load management is expected to be
approximately 470 megawatts (MW). Cost recovery for these load management
programs is attained through the inclusion in rate base of capital investments
and the appropriate expenses (including credits on customer bills) for recovery
in base rate proceedings.
The generating and transmission facilities of BGE are interconnected with
those of neighboring utility systems to form the Pennsylvania-New
Jersey-Maryland Interconnection (PJM). Under the PJM agreement, the
interconnected facilities are used for substantial energy interchange and
capacity transactions as well as emergency assistance. In addition, BGE enters
into short-term capacity transactions at various times to meet PJM obligations.
5
BGE has an agreement with Pennsylvania Power & Light Company (PP&L) to
purchase a mix of energy and capacity from June 1, 1990 through May 31, 2001.
This agreement, which has been accepted by the Federal Energy Regulatory
Commission, is designed to help maintain adequate reserve margins through this
decade and provide flexibility in scheduling power plant additions for the
latter half of the 1990s. The PP&L agreement entitles BGE to 5.94% of the energy
output, and net capacity (currently 124 MW), of PP&L's nuclear Susquehanna Steam
Electric Station from October 1, 1991 to May 31, 2001 and also enables BGE to
treat a portion of PP&L's capacity as BGE's capacity for purposes of satisfying
BGE's installed capacity requirements as a member of the PJM. BGE is not
acquiring an ownership interest in any of PP&L's generating units. PP&L will
continue to control, manage, operate, and maintain that station and all other
PP&L-owned generating facilities. BGE's firm capacity purchases at December 31,
1993 represented 170 MW of rated capacity of Bethlehem Steel Corporation's
Sparrows Point complex, 57 MW of rated capacity of the Baltimore Refuse Energy
Systems Company, and 124 MW of base load capacity from PP&L.
Also, on March 11, 1994, BGE announced that PECO Energy won a competitive
bid for additional capacity with a proposal to supply 140 megawatts for 25 years
beginning June 1, 1997. BGE anticipates submitting a contract for approval to
the PSC in the Spring of 1994.
FUEL FOR ELECTRIC GENERATION
Information regarding BGE's electric generation by fuel type and the cost of
fuels in the five-year period 1989-1993 is set forth in the following tables:
AVERAGE COST OF FUEL CONSUMED
GENERATION BY FUEL TYPE ( CENTS PER MILLION BTU)
--------------------------------------------- ----------------------------------------------
1993 1992 1991 1990 1989 1993 1992 1991 1990 1989
----- ----- ----- ----- ----- ------ ------ ------ ------ ------
Nuclear (a)................... 43% 40% 33% 5% 10% 53.01 45.54 48.64 54.86 50.43
Coal.......................... 55 54 44 44 46 151.85 154.76 160.74 154.56 154.31
Oil........................... 3 1 5 7 10 253.36 254.19 284.87 319.44 281.54
Hydro & Gas................... 3 3 4 6 5 -- -- -- -- --
----- ----- ----- ----- -----
104 98 86 62 71
Interchange/Purchases (b)..... (4) 2 14 38 29
----- ----- ----- ----- -----
100% 100% 100% 100% 100%
----- ----- ----- ----- -----
----- ----- ----- ----- -----
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(a) Nuclear fuel costs provide for disposal costs associated with long-term
off-site spent fuel storage and shipping, currently set by law at one mill
per kilowatt-hour of nuclear generation (approximately 10 cents per
million Btu) and for contributions to a fund for decommissioning and
decontaminating the Department of Energy's uranium enrichment facility.
(SEE FUEL FOR ELECTRIC GENERATION -- NUCLEAR.)
(b) Net purchases from (sales to) others.
COAL: BGE obtains a large amount of its coal under supply contracts with
mining operators. The remainder of its coal requirements are obtained through
spot purchases. BGE believes that it will be able to renew such contracts as
they expire or enter into similar contractual arrangements with other coal
suppliers. BGE's Brandon Shores Units 1 and 2 have a total annual requirement of
approximately 3,200,000 tons of coal (combined) with a sulfur content of less
than approximately 0.8%. The average delivered costs per ton paid by BGE for
Brandon Shores coal for the years 1989 through 1993 were $40.17, $39.00, $39.80,
$39.98, and $39.49, respectively. BGE's Crane Units 1 and 2 have a total annual
requirement of about 700,000 tons of coal (combined) with a sulfur content of
less than approximately 2.4% and a low ash melting temperature. The average
delivered costs per ton paid by BGE for coal at Crane for the years 1989 through
1993 were $42.62, $40.45, $38.88, $38.37, and $37.25, respectively. BGE's Wagner
Units 2 and 3 have a total annual requirement of approximately 1,000,000 tons of
coal (combined) with a sulfur content of no more than 1%. The average delivered
costs per ton paid by BGE for coal at Wagner for the years 1989 through 1993
were $41.45, $41.28, $44.49, $43.19, and $40.62, respectively.
Coal deliveries to BGE's coal burning facilities are made by rail and barge.
The coal used by BGE is produced from mines located in central and northern
Appalachia.
BGE has a 20.99% undivided interest in the Keystone coal-fired generating
plant and a 10.56% undivided interest in the Conemaugh coal-fired generating
plant. The bulk of the annual coal requirements for the Keystone plant is under
contract from Rochester and Pittsburgh Coal Company. The Conemaugh plant
purchases coal from local suppliers on the open market. The average delivered
costs per ton for coal for these plants for the years 1989 through 1993 were
$33.62, $36.69, $33.07, $31.53, and $32.42, respectively.
OIL: Under normal burn practices, BGE's requirements for residual fuel oil
amount to approximately 1,000,000 barrels of low-sulfur oil per year. Deliveries
of residual fuel oil are made directly into BGE barges from
6
the suppliers' Baltimore Harbor marine terminal for distribution to the various
generating plant locations. The average delivered prices per barrel paid by BGE
for residual fuel oil for the years 1989 through 1993 were $17.65, $20.24,
$15.53, $17.25, and $15.69 respectively.
NUCLEAR: The supply of fuel for nuclear generating stations involves the
acquisition of uranium concentrates, its conversion to uranium hexafluoride,
enrichment of uranium hexafluoride, and the fabrication of nuclear fuel
assemblies. Information is set forth below with respect to fuel for Calvert
Cliffs Units 1 and 2:
Uranium Concentrates: BGE has, either in inventory or under contract, sufficient
quantities of uranium concentrates to meet approximately 80% of
its requirements through 1997 and approximately 50% of its
requirements for 1998.
Conversion: BGE has contractual commitments providing for the conversion of
uranium concentrates into uranium hexafluoride which will meet
100% of BGE's requirements through 1995 and approximately 40% of
its requirements from 1996 through 1998.
Enrichment: BGE has a contract with the Department of Energy for the enrichment
of 100% of BGE's enrichment requirements through 1995 and 70% of
its requirements from 1996 through 1998.
Fuel Assembly BGE has contracted for the fabrication of fuel assemblies for
Fabrication: reloads it requires through 1996.
Under the Nuclear Waste Policy Act of 1982 (the 1982 Act), spent fuel
discharged from nuclear power plants, including Calvert Cliffs, is required to
be placed into a federal repository. Such facilities do not currently exist,
and, consequently, must be developed and licensed. BGE cannot now predict when
such facilities will be available, although the 1982 Act obligates the federal
government to accept spent fuel starting in 1998. While BGE cannot now predict
what the ultimate cost will be, the 1982 Act assesses a one mill per
kilowatt-hour fee on nuclear electricity generated and sold. At anticipated
operating levels, it is expected that this fee will be approximately $11 million
for Calvert Cliffs each year.
The Energy Policy Act of 1992 (the 1992 Act) contains provisions requiring
domestic utilities to contribute to a fund for decommissioning and
decontaminating the Department of Energy's (DOE) uranium enrichment facilities.
These contributions are generally payable over a fifteen-year period with
escalation for inflation and are based upon the amount of uranium enriched by
DOE for each utility. The 1992 Act provides that these costs are recoverable
through utility service rates as a cost of fuel. Information about the cost of
decommissioning is discussed in NOTE 1 TO THE CONSOLIDATED FINANCIAL STATEMENTS
on page 39 under the heading "UTILITY PLANT, DEPRECIATION AND AMORTIZATION, AND
DECOMMISSIONING."
Maryland law makes it unlawful to establish within the State a facility for
the permanent storage of high-level nuclear waste, unless otherwise expressly
required by federal law. BGE has received a license from the NRC to operate its
new on-site independent spent fuel storage facility. BGE now has storage
capacity at Calvert Cliffs that will accommodate spent fuel from operations
through the year 2006. In addition, BGE can expand its temporary storage
capacity to meet future requirements until federal storage is available.
Expenditures for nuclear fuel are discussed in MD&A -- LIQUIDITY AND CAPITAL
RESOURCES on page 28. Capital requirements for nuclear fuel returned to normal
levels in 1992. The 1991 level was abnormally low due to the accumulation in
inventory of nuclear fuel purchased and processed over the period of extended
outages at Calvert Cliffs during 1989-1991. The 1991 level reflects the use of
nuclear fuel from such inventoried stocks rather than new purchases.
GAS: BGE has a firm natural gas transportation entitlement of 3,500
dekatherms a day to provide ignition and banking at certain power plants. Gas
for electric generation is purchased as needed in the spot market using
interruptible transportation arrangements. Certain gas fired units can use
residual fuel oil as an alternative.
GAS OPERATIONS
BGE distributes natural gas purchased directly from several producers and
marketers. Transportation to BGE's city gate for these purchases is provided by
Columbia Gas Transmission Corporation (Columbia), CNG Transmission Corporation
(CNG), and Transcontinental Gas Pipe Line Corporation under various
transportation agreements. BGE has upstream transportation capacity under
contract on Tennessee Gas Pipeline Company, Texas Eastern Transmission
Corporation, Columbia Gulf Transmission Company and ANR Pipeline Company (ANR).
BGE has storage service agreements with Columbia, CNG and ANR. The
transportation and storage agreements are on file with the Federal Energy
Regulatory Commission (FERC).
7
BGE's current pipeline firm transportation entitlements to serve its firm
loads are 473,597 dekatherms (DTH) per day during the winter period and 291,231
DTH per day during the summer period. BGE uses the firm transportation capacity
to move gas from the Gulf of Mexico, Louisiana, south central regions of Texas
and Canada to BGE's city gate. The gas is subject to a mix of long and
short-term contracts that are managed to provide economic, reliable and flexible
service. Additional short-term contracts or exchange agreements with other gas
companies can be arranged in the event of short term emergencies.
To supplement BGE's gas supply at times of heavy winter demands and to be
available in temporary emergencies affecting gas supply, BGE has propane air and
liquefied natural gas facilities. The liquefied natural gas facility consists of
a plant for the liquefaction and storage of natural gas with a storage capacity
of 1,000,000 DTH and an installed daily capacity of 281,760 DTH. The propane air
facility consists of a plant with a mined cavern and refrigerated storage
facilities having a total storage capacity equivalent to 1,000,000 DTH and a
daily capacity of 91,600 DTH. BGE has under contract sufficient volumes of
propane for the operation of the propane air facility and is capable of
liquefying sufficient volumes of natural gas during the summer months for
operation of its liquefied natural gas facility during winter periods.
BGE offers gas for sale to its residential, commercial and industrial
customers on a firm and interruptible basis. BGE also provides its large
commercial and industrial customers with a transportation service across its
distribution system so that these customers may make direct purchase and
transportation arrangements with suppliers and pipelines. A transportation fee
is charged by BGE that is equivalent to its operating margin on gas it sells to
similar customers for the service from the city gate to the customer's facility.
This program enables BGE to maintain throughput at a level which assures that
fixed costs are spread over the maximum number of DTH. BGE is authorized by the
PSC to provide a balancing service for its transportation customers.
Future purchased gas costs are expected to increase due to transition costs
incurred by BGE gas pipeline suppliers in implementing FERC Order No. 636. These
transition costs, if approved by the PSC and FERC, will be passed on to BGE
customers through the purchased gas adjustment clause.
ENVIRONMENTAL MATTERS
The Company is subject to regulation with regard to air and water quality,
waste disposal, and other environmental matters by various federal, state, and
local authorities. Certain of these regulations require substantial expenditures
for additions to utility plant and the use of more expensive low-sulfur fuels.
While the Company cannot now precisely estimate the total effect of existing and
future environmental regulations and standards upon its existing and proposed
facilities and operations, the necessity for compliance with existing standards
and regulations has caused BGE to increase capital expenditures by approximately
$223 million during the five-year period 1989-1993. It is estimated that the
capital expenditures necessary to comply with such standards and regulations
will be approximately $37 million, $15 million, and $21 million for 1994, 1995,
and 1996, respectively.
AIR: The Federal Clean Air Act (the Act) mandates health and welfare
standards for concentrations of air pollutants. The State of Maryland is charged
by the Act with the responsibility for setting limits on all major sources of
these pollutants in the State so that these standards are not exceeded. Except
for Crane Units 1 and 2, BGE's generating units are limited to burning fuel
(coal or oil) with sulfur content of 1% or below. All units are limited to
emitting particulate matter at or below 0.02 grains per standard cubic foot of
exhaust gas for oil fired units and 0.03 grains per standard cubic foot for coal
fired units. Brandon Shores, a newer plant, is subject to more stringent
standards for sulfur dioxide (1.2 pounds per million Btu), and nitrogen dioxide
(0.7 pounds per million Btu). The Crane Units must meet limits of 3.5 pounds per
million Btu for sulfur dioxide, which is equivalent to a coal sulfur content of
approximately 2.4%. BGE is in compliance with existing air quality regulations.
Under a consent order with the Maryland Department of the Environment (MDE)
relating to such regulations, BGE is operating two of four units at its
Riverside facility at reduced capacity until these units are retired during
1994. The fifth Riverside unit was retired in 1991.
The Clean Air Act amendments of 1990 require sulfur dioxide emission
reductions at Crane and the jointly owned Conemaugh plant by 1995 and additional
controls at other coal plants to be in place by 2000. BGE presently plans to
achieve emission reduction at Crane by conversion to low-sulfur coal. The
capital costs for equipment changes at the Crane plant are estimated to be
approximately $7 million. Scrubbers are being installed at both units of the
Conemaugh plant, in which BGE has a 10.56% undivided ownership interest. BGE
estimates that its share of the costs of the scrubbers will be approximately
$42.7 million. In addition, BGE anticipates incurring other Clean Air Act costs
of approximately $10 million for various equipment such as continuous emission
monitors and precipitator upgrades by 2000.
At this time, plans for complying with nitrogen oxide (NOx) control
requirements under the Act are less certain because all implementation
regulations have not yet been finalized by the government. It is expected that
8
by the year 2000 these regulations will require additional NOx controls for
ozone non-attainment at BGE's generating plants and other BGE facilities. The
controls will result in additional expenditures that are difficult to predict
prior to the issuance of such regulations. Based on existing and proposed ozone
non-attainment regulations, BGE currently estimates that the NOx controls at
BGE's generating plants will cost approximately $70 million. BGE is currently
unable to predict the cost of compliance with the additional requirements at
other BGE facilities.
WATER: The discharge of effluents into the navigable waters of the State of
Maryland is regulated by the MDE, in accordance with the National Pollutant
Discharge Elimination System (NPDES) permit program, established pursuant to the
Federal Clean Water Act. At the present time, all of BGE's steam electric
generating plants have the required NPDES permits.
MDE water quality regulations require, among other things, specifying
procedures for determining compliance with State water quality standards. These
procedures require extensive studies involving sampling and monitoring of the
waters around affected generating plants. Under current regulations, the State
of Maryland may require changes in plant operations. At this time BGE is
performing studies to determine whether any modifications will be required to
comply with these new regulations.
WASTE DISPOSAL: The United States Environmental Protection Agency (EPA) has
promulgated regulations implementing those portions of the Resource Conservation
and Recovery Act which deal with management of hazardous wastes. These
regulations, and the Hazardous and Solid Waste Amendments of 1984, designate
certain spent materials as hazardous wastes and establish standards and permit
requirements for those who generate, transport, store, or dispose of such
wastes. The State of Maryland has adopted similar regulations governing the
management of hazardous wastes, which closely parallel the federal regulations.
BGE has implemented procedures for compliance with all applicable federal and
state regulations governing the management of hazardous wastes. Certain high
volume utility wastes such as fly ash and bottom ash have been exempted from
these regulations. The Company currently utilizes almost all of its coal fly ash
and bottom ash as structural fill material in a manner approved by the State of
Maryland. The remainder of the coal ash is sold to the construction industry for
a number of approved applications.
The Federal Comprehensive Environmental Response, Compensation and Liability
Act (Superfund statute) establishes liability for the cleanup of hazardous
wastes found contaminating the soil, water, or air. Those who generated,
transported or deposited the waste at the contaminated site are each jointly and
severally liable for the cost of the cleanup, as are the current property owner
and their predecessors in title at the time of the contamination. In addition,
many states have enacted laws similar to the Superfund statute.
On October 16, 1989, the EPA filed a complaint in the U.S. District Court
for the District of Maryland under the Superfund statute against BGE and seven
other defendants to recover past and future expenditures associated with cleanup
of a site located at Kane and Lombard Streets in Baltimore. The State of
Maryland intervened by filing a similar complaint in the same case and court on
February 12, 1990. The complaints allege that BGE arranged for its fly ash to be
deposited on the site. The litigation is currently stayed pending settlement
discussions among all parties. Additional investigation was initiated on the
remainder of the site by the MDE for the EPA but was never completed. BGE and
three other defendants agreed to complete the remedial investigation and
feasibility study of groundwater contamination around the site in a July 1993
consent order. The remedial action, if any, for the remainder of the site will
not be selected until these investigations are concluded. Therefore, neither the
total site cleanup costs, nor BGE's share, can presently be estimated.
In the early 1970's, BGE shipped an unknown number of scrapped transformers
to Metal Bank of America, a metal reclaimer in Philadelphia. Metal Bank's scrap
and storage yard has been found to be contaminated with oil containing high
levels of PCBs (PCBs are hazardous chemicals frequently used as a fire-resistant
coolant in electrical equipment). On December 7, 1987, the EPA notified BGE and
other utilities that they are considered potentially responsible parties (PRPs)
with respect to the cleanup of the site. A remedial investigation and
feasibility study by BGE and the other PRPs is in progress. The investigation
costs are estimated to be about $6 million. BGE's share of the investigation
costs is estimated to be approximately 15.8%, or $1 million, based on an
allocation formula applied to the PRP group. The total cleanup costs are not yet
known so BGE's potential liability cannot be estimated, but such liability could
be material.
During the early 1970's, BGE disposed of a small amount of low-level nuclear
waste at a site in Morehead, Kentucky, known as Maxey Flats. This site was found
to have been operated improperly. As a result, low-level radioactive
contaminants have been found to be leaking from the site. On November 26, 1986,
the EPA notified BGE that it is one of approximately 800 PRPs. A remedial
investigation and feasibility study was completed by BGE and other PRPs. The EPA
has issued its Record of Decision, recommending a natural stabilization remedy.
The cost estimate for this remedy is currently estimated to be approximately $60
million for all PRPs. BGE's
9
volumetric share of the waste on-site is 0.0103 percent of the total, based upon
BGE's records of waste shipped to the site compared to the total recorded waste.
BGE's potential liability cannot be estimated, but such liability is not likely
to be substantial because its volumetric share of the waste on-site is so small.
From 1985 until 1989, BGE shipped waste oil and other materials to the
Industrial Solvents and Chemical Company in York County, Pennsylvania for
disposal. The Pennsylvania Department of Environmental Resources (Pennsylvania
Department) subsequently investigated this site and found it to be heavily
contaminated by hazardous wastes. The Pennsylvania Department notified BGE on
August 15, 1990, that it and approximately 1,000 other entities were PRPs with
respect to the cost of all remedial activities to be conducted at the site. No
remedial investigation or feasibility study has been undertaken, but the PRPs
agreed to perform waste characterization at the site in a July 1993 consent
order. Also, the PRPs agreed to remove and dispose of specified numbers of drums
and tanks of waste in a December 1993 consent order. BGE's share of the
liability at this site currently is estimated to be approximately 2.39%, but
this may change as additional information about the site is obtained. The actual
cost of remedial activities has not been determined. As a result of these
factors, BGE's potential liability cannot presently be estimated. However, such
liability could be material.
On March 9, 1993 BGE was served in litigation instituted by the EPA in the
United States District Court for the Eastern District of Pennsylvania involving
contamination of the Douglassville site in Berks County, Pennsylvania. BGE was
named as a third party defendant based upon allegations that BGE had contracted
with A&A Waste Oils, an original defendant, to dispose of oils and lubricants.
BGE was dismissed as a party to this litigation in August, 1993.
In the early part of the century, predecessor gas companies (which were
later merged into BGE) manufactured coal gas for residential and industrial use.
The residue from this manufacturing process was coal tar, previously thought to
be harmless but now found to contain a number of chemicals designated by the EPA
as hazardous substances. BGE is coordinating an investigation of these former
coal gas plant sites, including exploration of corrective action options to
remove coal tar, with the MDE. No formal legal proceedings have been instituted
with respect to these sites. The technology for cleaning up such sites is still
developing, and potential remedies for these sites have not been identified. As
explained in NOTE 13 TO THE CONSOLIDATED FINANCIAL STATEMENTS on page 52, a
liability of $25.4 million was accrued in 1993 regarding future estimated
expenditures at these sites. Any cleanup costs for these sites in excess of the
amount accrued, which could be significant in total, cannot presently be
estimated.
10
ELECTRIC OPERATING STATISTICS
YEAR ENDED DECEMBER 31,
-------------------------------------------------------------------------
1993 1992 1991 1990 1989
------------- ------------- ------------- ------------- -------------
Electric Output (In Thousands) -- MWH:
Generated....................................... 28,907 25,626 22,767 15,193 18,296
Purchased (A)................................... 2,627 4,323 5,522 11,859 8,959
------------- ------------- ------------- ------------- -------------
Subtotal.................................... 31,534 29,949 28,289 27,052 27,255
Less Interchange Sales.......................... 4,149 3,180 1,167 1,088 595
------------- ------------- ------------- ------------- -------------
Total Output................................ 27,385 26,769 27,122 25,964 26,660
------------- ------------- ------------- ------------- -------------
------------- ------------- ------------- ------------- -------------
Power Generated and Purchased at Times of Peak
Load (MW) (one hour):
Generated by Company............................ 5,245 3,679 4,948 3,032 2,954
Net Purchased (A)............................... 631 1,879 962 2,445 2,350
------------- ------------- ------------- ------------- -------------
Peak Load (B)................................... 5,876 5,558 5,910 5,477 5,304
------------- ------------- ------------- ------------- -------------
------------- ------------- ------------- ------------- -------------
Annual System Load Factor (%)..................... 55.2 54.8 52.4 54.1 57.4
Revenues (In Thousands)
Residential..................................... $ 931,643 $ 839,954 $ 882,591 $ 718,032 $ 648,883
Commercial...................................... 869,829 842,694 850,038 758,573 668,819
Industrial...................................... 199,042 201,950 212,864 194,951 191,796
------------- ------------- ------------- ------------- -------------
System Sales.................................... 2,000,514 1,884,598 1,945,493 1,671,556 1,509,498
Interchange Sales............................... 91,543 64,323 23,845 26,629 17,802
Other........................................... 23,098 19,002 25,187 14,268 19,867
------------- ------------- ------------- ------------- -------------
Total....................................... $ 2,115,155 $ 1,967,923 $ 1,994,525 $ 1,712,453 $ 1,547,167
------------- ------------- ------------- ------------- -------------
------------- ------------- ------------- ------------- -------------
Sales (In Thousands) -- MWH:
Residential..................................... 10,614 9,735 10,097 9,283 9,451
Commercial...................................... 12,395 11,909 11,707 11,352 11,079
Industrial...................................... 3,763 3,663 3,708 3,743 4,261
------------- ------------- ------------- ------------- -------------
System Sales.................................... 26,772 25,307 25,512 24,378 24,791
Interchange Sales............................... 4,149 3,180 1,166 1,088 595
------------- ------------- ------------- ------------- -------------
Total....................................... 30,921 28,487 26,678 25,466 25,386
------------- ------------- ------------- ------------- -------------
------------- ------------- ------------- ------------- -------------
Customers
Residential..................................... 968,212 956,570 939,734 930,880 913,910
Commercial...................................... 100,820 99,673 98,254 96,567 95,102
Industrial...................................... 3,800 3,761 3,584 3,526 3,132
------------- ------------- ------------- ------------- -------------
Total....................................... 1,072,832 1,060,004 1,041,572 1,030,973 1,012,144
------------- ------------- ------------- ------------- -------------
------------- ------------- ------------- ------------- -------------
Average Cost of Fuel Consumed ( CENTS per million
Btu)............................................. 112.77 110.20 127.89 177.00 167.34
------------- ------------- ------------- ------------- -------------
------------- ------------- ------------- ------------- -------------
BGE achieved an all-time peak load of 6,038 megawatts on January 19, 1994.
- --------------------------
(A) Includes purchases from Safe Harbor Water Power Corporation, a
hydroelectric company, of which the Company owns two-thirds of the capital
stock.
(B) See page 5 for a discussion of active load management programs which may
be activated at times of peak load.
In 1993, BGE changed its classification of commercial and industrial
customers to present this information on a basis which is more consistent with
predominant industry practices. Prior-year amounts have been reclassified to
conform to the current year's presentation.
11
GAS OPERATING STATISTICS
YEAR ENDED DECEMBER 31,
---------------------------------------------------------------
1993 1992 1991 1990 1989
----------- ----------- ----------- ----------- -----------
Gas Output (In Thousands) -- DTH:
Purchased.................................................. 71,204 70,208 63,159 59,470 70,063
LNG Withdrawn from Storage................................. 725 742 551 333 789
Produced................................................... 259 92 17 5 736
----------- ----------- ----------- ----------- -----------
Total Output........................................... 72,188 71,042 63,727 59,808 71,588
Delivery Service Gas
Delivered (A).............................................. 38,521 41,048 40,503 43,377 44,696
----------- ----------- ----------- ----------- -----------
Total.................................................. 110,709 112,090 104,230 103,185 116,284
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
Peak Day Sendout (DTH)....................................... 657,700 609,200 610,200 653,900 663,200
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
Capability on Peak Day (DTH)................................. 847,000 847,000 817,000 853,000 761,000
Revenues (In Thousands)
Residential................................................ $ 265,601 $ 242,737 $ 220,653 $ 218,967 $ 242,389
Commercial
Excluding Delivery Service............................... 121,832 112,147 96,189 89,573 112,630
Delivery Service......................................... 3,287 3,591 3,031 3,304 4,409
Industrial
Excluding Delivery Service............................... 22,250 21,123 14,855 32,439 18,363
Delivery Service......................................... 12,920 14,290 14,288 17,851 22,661
Other...................................................... 9,959 9,049 9,179 11,285 11,349
----------- ----------- ----------- ----------- -----------
Total.................................................. $ 435,849 $ 402,937 $ 358,195 $ 373,419 $ 411,801
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
Sales (In Thousands) -- DTH:
Residential................................................ 40,029 39,042 36,519 35,026 39,806
Commercial
Excluding Delivery Service............................... 23,830 23,478 20,687 18,164 21,964
Delivery Service......................................... 7,428 7,102 6,433 5,872 5,778
Industrial
Excluding Delivery Service............................... 5,298 5,314 3,605 7,305 3,697
Delivery Service......................................... 31,390 33,638 34,240 34,720 39,452
----------- ----------- ----------- ----------- -----------
Total.................................................. 107,975 108,574 101,484 101,087 110,697
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
Customers
Residential................................................ 491,165 486,863 482,085 482,680 482,538
Commercial................................................. 37,518 37,000 36,561 35,953 35,970
Industrial................................................. 1,353 1,412 1,385 1,401 1,398
----------- ----------- ----------- ----------- -----------
Total.................................................. 530,036 525,275 520,031 520,034 519,726
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
BGE achieved an all-time peak day sendout of 762,000 DTH on January 19, 1994.
- --------------------------
(A) Represents gas purchased by alternate fuel customers directly from
suppliers for which BGE receives a fee for transportation through its
system ("delivery service"). (SEE MD&A -- RESULTS OF OPERATIONS.)
In 1993, BGE changed its classification of commercial and industrial
customers to present this information on a basis which is more consistent with
predominant industry practices. Prior-year amounts have been reclassified to
conform to the current year's presentation.
12
FRANCHISES
BGE has nonexclusive electric and gas franchises to use streets and other
highways which are adequate and sufficient to permit BGE to engage in its
present business. All such franchises, other than the gas franchises in
Manchester, Hampstead, Perryville, Sykesville, Havre de Grace, and Montgomery
and Frederick Counties, are unlimited as to time. The gas franchises for these
jurisdictions expire at various times from 1994 to 2020, except for Havre de
Grace which has the right, exercisable at twenty-year intervals from 1907, to
purchase all of BGE's gas properties in that municipality. Conditions of the
franchises are satisfactory. BGE also has rights-of-way to maintain 26-inch
natural gas mains across certain Baltimore City owned property (principally
parks) which expire in 1999 and 2004, each subject to renewal during the last
year thereof for an additional period of 25 years on a fair revaluation of the
rights so granted. Conditions of the grants are satisfactory.
Franchise provisions relating to rates have been superseded by the Public
Service Commission Law of Maryland.
DIVERSIFIED BUSINESSES
GENERAL
Diversified businesses consist of the operations of the Constellation
Companies and BNG, Inc.
The Constellation Companies' businesses are concentrated in three major
areas -- power generation projects, financial investments, and real estate
projects (including senior living facilities). A significant portion of the
Constellation Companies' activities are conducted through joint ventures in
which they hold varying ownership interests.
The Constellation Companies hold up to a 50% ownership interest in 24 power
generating projects in operation or under construction accounting for $285
million of the Constellation Companies' assets. One of these power generation
construction projects is the Puna project, which is discussed on page 14. These
projects, all of which either are qualifying facilities under the Public Utility
Regulatory Policies Act of 1978 or are otherwise exempt from the Public Utility
Holding Company Act of 1935, are of the following types and aggregate generation
capacities: coal 160 MW, solar 170 MW, geothermal 121 MW, waste coal 182 MW,
wood burning 70 MW, and hydro 30 MW. In addition, another $6 million has been
spent on projects in development. The Constellation Companies also participate
in the operation and maintenance of 23 power generation projects existing or
under construction, 10 of which are projects in which the Constellation
Companies hold an ownership interest. Financial investments account for $213
million of the Constellation Companies' assets. These assets include $91 million
in internally and externally managed securities portfolios, $83 million in
monoline financial guaranty (credit enhancement) companies, and $39 million in
tax-oriented transactions. Real estate projects account for $489 million of the
Constellation Companies' assets. These projects include raw land, office
buildings, retail, and commercial projects, an entertainment, dining, and retail
complex in Orlando, Florida, a mixed-use planned unit development, and senior
living facilities. The majority of the real estate projects are in the
Baltimore-Washington area and have been adversely affected by the depressed real
estate and economic market.
The Constellation Companies' investment in wholesale power generating
projects includes $163 million representing ownership interests in 16 projects
which sell electricity in California under Interim Standard Offer No. 4 power
purchase agreements. Under these agreements, the properties supply electricity
to purchasing utilities at a fixed energy rate for the first ten years of the
agreements and at variable energy rates based on the utilities' avoided cost for
the remaining term of the agreements. Avoided cost generally represents a
utility's next lowest cost generation to service the demands on its system.
These power generation projects are scheduled to convert to supplying
electricity at avoided cost rates in various years beginning in late 1996
through the end of 2000. As a result of declines in purchasing utilities'
avoided costs after these agreements were signed, revenues at these projects
based on current avoided cost levels would be substantially lower than revenues
presently being realized under the fixed price terms of the agreements. If
current avoided cost levels were to continue into 1996 and beyond, the
Constellation Companies could experience reduced earnings or incur losses
associated with these projects, which could be significant. The Constellation
Companies are investigating alternatives for certain of these power generation
projects including, but not limited to, repowering the projects to reduce
operating costs, renegotiating the power purchase agreements, and selling their
ownership interests in the projects. The Company cannot predict the impact these
matters may have on the Constellation Companies or the Company, but the impact
could be material.
The Constellation Companies contributed approximately $12 million, or 4% to
the Company's 1993 after-tax earnings, a decrease from the contribution of
approximately $15 million in 1992. For additional information about the
Constellation Companies, see MD&A -- RESULTS OF OPERATIONS -- DIVERSIFIED
BUSINESSES EARNINGS (which includes the Constellation Companies' earnings
information broken down by line of business) and MD&A -- LIQUIDITY AND CAPITAL
RESOURCES -- DIVERSIFIED BUSINESSES CAPITAL REQUIREMENTS.
13
BNG, Inc. is a wholly owned subsidiary of BGE which invests in natural gas
reserves. BNG owns gas producing properties in West Virginia, the output of
which is sold to BGE for the life of the reserves under a contract on file with
the PSC.
PUNA PROJECT
As discussed in previous filings made by the Company under the Securities
Exchange Act of 1934, the Constellation Companies have a 49% ownership interest
in a joint venture, Puna Geothermal Venture (PGV). PGV developed and is
operating a 25-megawatt geothermal energy project on the island of Hawaii (the
Big Island) in the State of Hawaii (the Puna project). Construction of the Puna
project was scheduled to be completed during 1991; however, it began generating
electricity on April 22, 1993. PGV sells the electricity it generates to Hawaii
Electric Light Company, Inc. ("Hawaii Electric") under a power purchase
agreement that calls for the supply by PGV of at least 22 megawatts.
Through the date of this Report, the Constellation Companies' investment in
the Puna project was $81.7 million. In addition, the Constellation Companies
have loaned $5 million (including accrued interest) to the other partner in PGV
for use in funding venture costs. PGV has outstanding a $93.4 million
construction loan. In connection with the construction loan, Constellation
Investments, Inc. (CII) provided a guarantee to the lending institution that
requires the Constellation Companies to put up to $15 million of equity into the
Puna project in certain events. The lender has the right to call the guarantee
but has not done so. Negotiations are ongoing with the project lenders to
convert the construction loan to permanent financing.
The diversified businesses section of the capital requirements chart on page
15 includes $15 million for the year 1994 relating to the Puna project. Of this
amount, approximately $14 million is additional equity that the Constellation
Companies will be required to contribute to PGV under the CII guarantee, and
approximately $1 million is additional costs relating to the project. In
addition, the Constellation Companies may need to fund $3 million to $20 million
during 1994 that is not included in the capital requirements chart to deal with
the problem with the production wells described below.
The Company cannot predict the impact that the matters involving the Puna
project discussed below may have on the Constellation Companies or the Company,
but such impact could be material.
PGV currently has two production wells that provide steam to power the
project. Recently, one of the production wells changed from a steam dominated
resource to a brine dominated resource. The result is that the well produces
considerably more fluid to inject back into the ground. If the second production
well also changes from steam dominated to brine dominated, PGV will have
insufficient injection capacity to handle the resulting increase in fluid volume
and this may affect the project's ability to generate the megawatts required
under the power purchase agreement. Studies are underway to determine both the
likelihood of the second production well changing to brine dominated and the
need for additional injection or production wells. The studies have not reached
a point where a prediction about the outcome can be made.
On April 13, 1993, Hawaii Electric filed suit, HAWAII ELECTRIC LIGHT
COMPANY, INC. v. PUNA GEOTHERMAL VENTURE COMPANY, INC., Civil No. 93-234 (3rd
Circuit Ct., Hawaii), seeking to require PGV to pay contractual penalties of
$7.5 million (for delays in the scheduled delivery of power to Hawaii Electric)
and seeking to require PGV to pay consequential damages. PGV asserts that the
delay was caused by a "force majeure" event. A tentative settlement has been
agreed to which requires no additional capital contributions from the
Constellation Companies.
PGV intervened in WAO KELE O PUNA, ET AL. v. WAIHEE, ET AL., Civil No.
91-3553-10 (1st Circuit Court, Hawaii) on the grounds that plaintiffs improperly
are seeking to include the Puna project in an existing suit against the State of
Hawaii and the County regarding an unrelated project. If plaintiffs succeed, the
State and the County could be enjoined from any further permit review and
issuance and from monitoring activity for the Puna project, effectively shutting
down the Puna project. The Constellation Companies understand that the unrelated
project has been cancelled, but the effect, if any, on this lawsuit are
uncertain.
During 1993, EPA informed PGV that it was investigating the circumstances
regarding two air releases of hydrogen sulfide from the Puna project's well
drilling activities. EPA issued a final preliminary assessment report giving the
PGV site a low priority for further assessment action based on the fact there is
no residual hydrogen sulfide problem at the site to be remediated.
The Constellation Companies' partner in the Puna project continues to
experience financial difficulties. The partner has not been meeting its funding
obligation to PGV for over two years. Also, the partner is currently in default
under the $5 million loan it obtained from the Constellation Companies. On
February 22, 1994, the Constellation Companies reached tentative agreement with
the partner and certain of the partner's direct and
14
indirect shareholders which would result in recapitalization of the project, and
repayment of the $5 million loan to Constellation. This agreement is subject to
project lender approval and certain approvals by shareholders of the partner.
There are no assurances that these approvals will be obtained.
CAPITAL REQUIREMENTS
Capital requirements for diversified businesses for 1991 through 1993, along
with estimated amounts for 1994 through 1996, are set forth below:
1991 1992 1993 1994 1995 1996
---- ---- ---- ---- ---- ----
(IN MILLIONS)
Retirement of long-term
debt......................... $167 $118 $222 $ 9 $ 81 $ 77
Investment requirements....... 109 80 78 63 60 20
---- ---- ---- ---- ---- ----
Total diversified
businesses................. $276 $198 $300 $ 72 $141 $ 97
---- ---- ---- ---- ---- ----
---- ---- ---- ---- ---- ----
The investment requirements shown above include the Constellation Companies'
portion of equity funding to committed projects under development as well as net
loans made to project partnerships. The investment requirements for past periods
reflect actual funding of projects, whereas investment requirements for the
years 1994-1996 reflect the Constellation Companies' estimate of funding during
such periods for ongoing and anticipated projects. Also, guarantees of $36
million may be called which are not included above. For more information see
SCHEDULE VII -- GUARANTEES OF SECURITIES OF OTHER ISSUERS.
Estimates of the Constellation Companies' investment requirements are
subject to continuous review and modification. Actual investment requirements
may vary significantly from the amounts above due to the type and number of
projects selected for development, the impact of market conditions on those
projects, the ability to obtain financing, and the availability of internally
generated cash. The Constellation Companies' investment requirements have been
met in the past through the internal generation of cash and through borrowings
from institutional lenders.
See NOTES 3 AND 4 TO CONSOLIDATED FINANCIAL STATEMENTS AND MD&A -- LIQUIDITY
AND CAPITAL RESOURCES -- DIVERSIFIED BUSINESSES CAPITAL REQUIREMENTS for
additional information about diversified activities.
EMPLOYEES
As of December 31, 1993, BGE employed 9,028 people for its utility
operations. Additionally, 135 people were employed by the Constellation
Companies. The Constellation Companies' amount excludes the approximately 800
employees at an entertainment, dining, and retail complex in Orlando, Florida
and 55 employees of two wholly owned subsidiaries operating two power generation
facilities. The number of employees at BGE's utility operations is 7,941 as of
the date of this report as a result of the various employee reduction programs
initiated in 1993. See NOTE 7 TO CONSOLIDATED FINANCIAL STATEMENTS.
15
ITEM 2. PROPERTIES
ELECTRIC: The principal electric generating plants of BGE are as follows:
INSTALLED GENERATION (MWH)
CAPACITY ----------------------
PLANT LOCATION (MW) PRIMARY FUEL 1993 1992
- ------------------------ ------------------------ ------------ ------------ ---------- ----------
(AT DECEMBER 31, 1993)
Steam
Calvert Cliffs Calvert County, MD 1,660 Nuclear 12,300,816 10,663,950
Brandon Shores Anne Arundel County, MD 1,288 Coal 7,584,610 6,793,320
Herbert A. Wagner Anne Arundel County, MD 991 Coal/Oil/Gas 2,953,056 2,348,466
Charles P. Crane Baltimore County, MD 380 Coal 2,102,530 1,818,747
Gould Street Baltimore City, MD 104 Oil 162,160 63,612
Riverside Baltimore County, MD 277 Oil/Gas 81,710 102,215
Westport Baltimore City, MD 127 Oil 33,717 44,332
Jointly Owned -- Steam
Keystone Armstrong and Indiana 359(A) Coal 2,497,351 2,500,289
Counties, PA
Conemaugh Indiana County, PA 181(A) Coal 1,147,729 1,262,146
Combustion Turbine
Notch Cliff Baltimore County, MD 128 Gas 12,276 11,281
Perryman Harford County, MD 208 Oil 11,320 5,320
Westport Baltimore City, MD 121 Gas 9,863 7,905
Riverside Baltimore County, MD 173 Oil/Gas 6,632 2,510
Philadelphia Road Baltimore City, MD 64 Oil 2,537 1,174
Charles P. Crane Baltimore County, MD 14 Oil 386 253
Herbert A. Wagner Anne Arundel County, MD 14 Oil 172 178
------------ ---------- ----------
Totals 6,089 28,906,865 25,625,698
------------
------------ ---------- ----------
---------- ----------
- ----------------------------------
(A) BGE-owned proportionate interest and entitlement. These totals include
diesel capacity of 2 megawatts and 1 megawatt for Keystone and Conemaugh,
respectively.
BGE also owns two-thirds of the outstanding capital stock of Safe Harbor
Water Power Corporation, and is currently entitled to 277 megawatts of the rated
capacity of the Safe Harbor Hydroelectric Project. Safe Harbor is operated under
a FERC license which expires in the year 2030.
GAS: BGE has propane air and liquefied natural gas facilities as described
in Gas Operations on page 7.
GENERAL: All of the principal plants and other important units of BGE
located in Maryland are held in fee except that several properties (not
including any principal electric or gas generating plant or the principal
headquarters building owned by BGE in downtown Baltimore) in BGE's service area
are held under lease arrangements. The leased spaces are used for various
office, service and/or retail merchandising purposes. Electric transmission and
electric and gas distribution lines are constructed principally (a) in public
streets and highways pursuant to franchises or (b) on permanent fee simple or
easement rights-of-way secured for the most part by grants from record owners
and as to a relatively small part by condemnation.
BGE's undivided interests as a tenant in common in the properties acquired
for the Keystone and Conemaugh Plants located in Pennsylvania are held in fee by
BGE, subject to minor defects and encumbrances which do not materially interfere
with the use of the properties by BGE.
All of BGE's property referred to above is subject to the lien of the
Mortgage securing BGE's First Refunding Mortgage Bonds.
ITEM 3. LEGAL PROCEEDINGS
ASBESTOS
During 1993, BGE was served in several actions concerning asbestos. The
actions are collectively titled IN RE BALTIMORE CITY PERSONAL INJURIES ASBESTOS
CASES in the Circuit Court for Baltimore City, Maryland. The actions are based
upon the theory of "premises liability," alleging that BGE knew of and exposed
individuals to an asbestos hazard. The actions relate to two types of claims.
The first type, direct claims by individuals exposed to asbestos, were
described in a Report on Form 8-K filed August 20, 1993. BGE and approximately
70 other defendants are involved. The 260 non-employee plaintiffs each claim $6
million in damages ($2 million compensatory and $4 million punitive). BGE does
not know the specific facts necessary for BGE to assess its potential liability
for these type claims, such as the identity of the BGE facilities at which the
plaintiffs allegedly worked as contractors, the names of the plaintiffs'
employers, and the date on which the exposure allegedly occurred.
16
The second type are claims by two manufacturers -- Owens Corning Fiberglass
and Pittsburgh Corning Corp. -- against BGE and approximately eight others, as
third-party defendants. These relate to approximately 1,500 individual
plaintiffs who have settled with the manufacturers. BGE does not know the
specific facts necessary for BGE to assess its potential liability for these
type claims, such as the identity of BGE facilities containing asbestos
manufactured by the two manufacturers, the relationship (if any) of each of the
individual plaintiffs to BGE, the settlement amounts for any individual
plaintiffs who are shown to have had a relationship to BGE, and the dates on
which/places at which the exposure allegedly occurred.
Until the relevant facts for both type claims are determined, BGE is unable
to estimate what its liability, if any, might be. Although insurance and hold
harmless agreements from contractors who employed the plaintiffs may cover a
portion of any ultimate awards in the actions, BGE's potential liability could
be material.
See ITEM 1. BUSINESS -- RATE MATTERS, NUCLEAR OPERATIONS, ENVIRONMENTAL
MATTERS, DIVERSIFIED BUSINESSES -- PUNA PROJECT, and NOTE 13 TO CONSOLIDATED
FINANCIAL STATEMENTS.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not Applicable.
17
ITEM 10. EXECUTIVE OFFICERS OF THE REGISTRANT
Executive Officers of the Registrant are:
OTHER OFFICES OR POSITIONS
NAME AGE PRESENT OFFICE HELD DURING PAST FIVE YEARS
- ----------------------------- --- --------------------------------------------- ---------------------------------------------
Christian H. Poindexter 55 Chairman of the Board (A) Vice Chairman of the Board
(Since January 1, 1993) President, Constellation
Holdings, Inc.
Edward A. Crooke 55 President (B) President, Utility Operations
(Since September 1, 1992)
Bruce M. Ambler 54 President President, Constellation
Constellation Holdings, Inc. Development, Inc.
(Since August 1, 1989) Vice President, Constellation Holdings, Inc.
George C. Creel 60 Senior Vice President Senior Vice President
Generation Vice President, Nuclear Energy
(Since January 1, 1993) Vice President, Fossil Energy
Thomas F. Brady 44 Vice President Vice President
Customer Service and Customer Service and
Distribution Accounting
(Since July 1, 1993) Vice President, Accounting and
Economics
Herbert D. Coss, Jr. 59 Vice President Vice President
Marketing and Gas Electric Interconnection and
Operations Transmission
(Since January 1, 1994) Vice President, Interconnection
and Operations
Vice President, General Services
Robert E. Denton 50 Vice President Plant General Manager, Calvert Cliffs
Nuclear Energy Nuclear Power Plant
(Since September 1, 1992) Manager, Calvert Cliffs Nuclear Power Plant
Manager, Quality Assurance and Staff
Services
Carserlo Doyle 49 Vice President Manager, Telecommunications
Electric Interconnection Principal Engineer
and Transmission
(Since January 1, 1994)
Jon M. Files 58 Vice President Vice President, Management and Staff
Management Services Services
(Since September 1, 1989)
Ronald W. Lowman 49 Vice President Manager, Fossil Engineering
Fossil Energy Manager, Fossil Engineering
(Since January 1, 1993) Services
Manager, Generation
Maintenance
G. Dowell Schwartz, Jr. 57 Vice President Manager, Auditing
General Services
(since April 1, 1990)
Charles W. Shivery 48 Vice President Vice President
Finance and Accounting, Corporate Finance,
Chief Financial Officer Treasurer and Secretary
and Secretary Treasurer and Secretary and
(Since July 1, 1993) Manager, Finance
Joseph A. Tiernan 55 Vice President Vice President,
Corporate Affairs Corporate Administration
(Since February 1, 1993) Vice President, Nuclear Energy
- --------------------------
(A) Chief Executive Officer, Director, and member of the Executive Committee.
(B) Chief Operating Officer, Director, and member of the Executive Committee.
18
Officers of the Registrant are elected by, and hold office at the will of,
the Board of Directors and do not serve a "term of office" as such. There is no
arrangement or understanding between any officer and any other person pursuant
to which the officer was selected.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
STOCK TRADING
BGE's Common Stock, which is traded under the ticker symbol BGE, is listed
on the New York, Chicago, and Pacific stock exchanges, and has unlisted trading
privileges on the Boston, Cincinnati, and Philadelphia exchanges.
As of February 28, 1994, there were 82,321 common shareholders of record.
DIVIDEND POLICY
The Common Stock is entitled to dividends when and as declared by the Board
of Directors. There are no limitations in any indenture or other agreements on
payment of dividends; however, holders of Preferred Stock (first) and holders of
Preference Stock (next) are entitled to receive, when and as declared, from the
surplus or net profits, cumulative yearly dividends at the fixed preferential
rate specified for each series and no more, payable, quarterly, and to receive
when due the applicable Preference Stock redemption payments, before any
dividend on the Common Stock shall be paid or set apart.
Dividends have been paid on the Common Stock continuously since 1910. Future
dividends depend upon future earnings, the financial condition of the Company
and other factors. Quarterly dividends were declared on the Common Stock during
1993 and 1992 in the amounts set forth below.
COMMON STOCK DIVIDENDS AND PRICE RANGES
1993 1992
------------------------- -------------------------
PRICE* PRICE*
DIVIDEND ---------------- DIVIDEND ----------------
DECLARED HIGH LOW DECLARED HIGH LOW
-------- ------- ------- -------- ------- -------
First Quarter................. $ .36 $26 3/8 $22 3/8 $ .35 $23 1/8 $19 3/4
Second Quarter................ .37 26 5/8 23 7/8 .36 22 5/8 19 7/8
Third Quarter................. .37 27 1/2 25 1/8 .36 24 3/8 21 1/2
Fourth Quarter................ .37 26 7/8 23 1/2 .36 24 1/8 21 3/4
-------- --------
Total..................... $ 1.47 $ 1.43
-------- --------
-------- --------
- --------------------------
*Based on New York Stock Exchange Composite Transactions as reported in the
eastern edition of THE WALL STREET JOURNAL.
19
ITEM 6. SELECTED FINANCIAL DATA
1993 1992 1991 1990 1989
---------- ---------- ---------- ---------- ----------
(DOLLAR AMOUNTS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
Summary of Operations
Total Revenues................................................. $2,668,714 $2,491,343 $2,448,853 $2,178,112 $2,032,009
Expenses Other Than Interest and Income Taxes.................. 2,047,714 1,955,998 1,959,665 1,854,183 1,555,424
---------- ---------- ---------- ---------- ----------
Income From Operations......................................... 621,000 535,345 489,188 323,929 476,585
Other Income................................................... 15,702 22,096 26,628 36,674 30,928
---------- ---------- ---------- ---------- ----------
Income Before Interest and Income Taxes........................ 636,702 557,441 515,816 360,603 507,513
Interest Expense............................................... 188,764 189,747 196,588 165,205 149,593
---------- ---------- ---------- ---------- ----------
Income Before Income Taxes..................................... 447,938 367,694 319,228 195,398 357,920
Income Taxes................................................... 138,072 103,347 85,547 19,952 81,629
---------- ---------- ---------- ---------- ----------
Income Before Cumulative Effect of Changes in Accounting
Methods....................................................... 309,866 264,347 233,681 175,446 276,291
Cumulative Effect of Change in the Method of Accounting for
Income Taxes.................................................. -- -- 19,745 -- --
Cumulative Effect of Change in the Method of Accounting for
Unbilled Revenues, Net of Taxes............................... -- -- -- 37,754 --
---------- ---------- ---------- ---------- ----------
Net Income..................................................... 309,866 264,347 253,426 213,200 276,291
Preferred and Preference Stock Dividends....................... 41,839 42,247 42,746 40,261 32,381
---------- ---------- ---------- ---------- ----------
Earnings Applicable to Common Stock............................ $ 268,027 $ 222,100 $ 210,680 $ 172,939 $ 243,910
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
Earnings Per Share of Common Stock
Before Cumulative Effect of Changes in Accounting Methods.... $ 1.85 $ 1.63 $ 1.51 $ 1.09 $ 2.03
Cumulative Effect of Change in the Method of Accounting for
Income Taxes................................................ -- -- .16 -- --
Cumulative Effect of Change in the Method of Accounting for
Unbilled Revenues........................................... -- -- -- .31 --
---------- ---------- ---------- ---------- ----------
Total Earnings Per Share of Common Stock....................... $ 1.85 $ 1.63 $ 1.67 $ 1.40 $ 2.03
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
Dividends Declared Per Share of Common Stock................... $ 1.47 $ 1.43 $ 1.40 $ 1.40 $ 1.38
Ratio of Earnings to Fixed Charges............................. 3.00 2.65 2.27 1.78 3.02
Ratio of Earnings to Fixed Charges and Preferred and Preference
Stock Dividends Combined...................................... 2.34 2.08 1.82 1.47 2.44
Financial Statistics at Year End
Total Assets................................................... $7,987,039 $7,374,357 $7,137,989 $6,710,375 $5,985,679
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
Capitalization
Long-term debt............................................... $2,823,144 $2,376,950 $2,390,115 $2,193,844 $2,076,620
Preferred stock.............................................. 59,185 59,185 59,185 59,185 59,185
Redeemable preference stock.................................. 342,500 395,500 398,500 365,000 322,800
Preference stock not subject to mandatory redemption......... 150,000 110,000 110,000 110,000 110,000
Common shareholders equity................................... 2,620,511 2,534,639 2,153,306 2,073,158 2,001,188
---------- ---------- ---------- ---------- ----------
Total capitalization......................................... $5,995,340 $5,476,274 $5,111,106 $4,801,187 $4,569,793
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
Book Value Per Share of Common Stock........................... $ 17.94 $ 17.63 $ 17.00 $ 16.58 $ 16.60
Number of Common Shareholders.................................. 82,287 80,371 71,131 73,049 75,762
20
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
This annual report presents the financial condition and results of
operations of Baltimore Gas and Electric Company (BGE) and its subsidiaries
(collectively, the Company). Among other information, it provides Consolidated
Financial Statements, Notes to Consolidated Financial Statements (Notes),
Utility Operating Statistics, and Selected Financial Data. The following
discussion explains factors that significantly affect the Company's results of
operations, liquidity, and capital resources.
RESULTS OF OPERATIONS
EARNINGS PER SHARE OF COMMON STOCK
Consolidated earnings per share were $1.85 for 1993 and $1.63 for 1992, an
increase of $.22 and a decrease of $.04 from prior-year amounts. The changes in
earnings per share reflect a higher level of earnings applicable to common
stock, offset partially in 1993 and completely in 1992 by the larger number of
outstanding common shares. The summary below presents the earnings-per-share
amounts.
1993 1992 1991
--------- --------- ---------
Utility business........................................................................... $ 1.77 $ 1.52 $ 1.60
Diversified businesses
Current-year operations.................................................................. .08 .11 (.09)
Cumulative effect of change in the method of accounting for income taxes (see Note 1).... -- -- .16
--------- --------- ---------
Total diversified businesses............................................................. .08 .11 .07
--------- --------- ---------
Total...................................................................................... $ 1.85 $ 1.63 $ 1.67
--------- --------- ---------
--------- --------- ---------
EARNINGS APPLICABLE TO COMMON STOCK
Earnings applicable to common stock increased $45.9 million in 1993 and
$11.4 million in 1992. The 1993 increase reflects higher utility earnings,
slightly offset by lower earnings of diversified businesses. The 1992 increase
reflects increases in both utility and diversified businesses earnings.
Utility earnings increased in 1993 because BGE sold more electricity than in
the previous year and because of increased base rates. Three principal factors
produced the increase in sales of electricity: the summer of 1993 was hotter
than 1992; commercial customers used more electricity; and the number of
residential customers increased. The effect of weather on utility sales is
discussed below. The 1993 earnings increases were partially offset by higher
operations and maintenance expenses, depreciation expense, and property taxes,
and the effect of the Omnibus Budget Reconciliation Act of 1993 (1993 Tax Act),
which increased the federal corporate income tax rate to 35% from 34%. Utility
earnings increased in 1992 over 1991 because the colder winter in 1992 led to
higher electric and gas sales. Operations expenses and interest charges were
also lower in 1992, while other income was higher. However, the summer of 1992
was cooler than 1991, and as a result lower electric sales offset a substantial
portion of the increase in 1992 utility earnings.
The following factors influence BGE's utility operations earnings:
regulation by the Public Service Commission of Maryland (PSC), the effect of
weather and economic conditions on sales, and competition in the generation and
sale of electricity. The base rate increases authorized by the PSC in April 1993
will affect 1994 utility earnings favorably. Several electric fuel rate cases
now pending before the PSC discussed in Notes 1 and 13 could also affect future
years' earnings. During 1993 and 1992, unfavorable economic conditions
diminished electric and gas sales growth in BGE's service territory. Electric
utilities presently face competition in the construction of generating units to
meet future load growth and in the sale of electricity in the bulk power
markets. Electric utilities also face the future prospect of competition for
electric sales to retail customers. It is not possible