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UNITED STATES
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 EXCHANGE ACT OF 1934
For the fiscal year ended 1-1910
DECEMBER 31, 1997 Commission file number
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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.)
39 W. LEXINGTON STREET,
BALTIMORE, MARYLAND 21201
(Address of principal executive offices) (Zip Code)
410-783-5920
(Registrant's telephone number, including area code)
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
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New York Stock Exchange, Inc.
Common Stock -- Without Par Value Chicago Stock Exchange, Inc.
Pacific Stock Exchange, Inc.
Preference Stock, Cumulative, $100 Par Value:
7.78%, 1973 Series
7.50%, 1986 Series Philadelphia Stock Exchange, Inc.
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 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. [ ]
Aggregate market value of Common Stock, without par value, held by
non-affiliates as of February 28, 1998 was approximately $4,645,485 based upon
New York Stock Exchange composite transaction closing price.
COMMON STOCK, WITHOUT PAR VALUE -- 147,867,114 SHARES OUTSTANDING ON
FEBRUARY 28, 1998.
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 24, 1998 (Proxy Statement).
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TABLE OF CONTENTS
PAGE
----
PART I
Item 1 -- Business
Overview of Consolidated
Business......................... 1
Consolidated Capital
Requirements..................... 3
Electric Business
Electric Regulatory Matters and
Competition.................... 4
Electric Rate Matters............ 5
Nuclear Operations............... 5
Electric Load Management, Energy,
and Capacity
Purchases...................... 6
Fuel for Electric Generation..... 7
Electric Operating Statistics.... 9
Gas Business
Gas Operating Statistics......... 10
Gas Regulatory Matters and
Competition.................... 11
Gas Operations................... 11
Gas Rate Matters................. 12
Franchises......................... 12
Diversified Businesses............. 12
Environmental Matters.............. 17
Employees.......................... 19
Item 2 -- Properties......................... 20
Item 3 -- Legal Proceedings.................. 21
Item 4 -- Submission of Matters to a Vote of
Security Holders................. 21
Item 10 -- Executive Officers of the
Registrant (Instruction 3 to Item
401(b) of Regulation S-K)........ 22
PART II
Item 5 -- Market for Registrant's Common
Equity and Related Stockholder
Matters.......................... 24
Item 6 -- Selected Financial Data............ 25
Item 7 -- Management's Discussion and
Analysis of Financial Condition
and Results of
Operations......................... 26
Item 7A -- Quantitative and Qualitative
Disclosures About Market Risk.... 36
Item 8 -- Financial Statements and
Supplementary Data............... 37
Item 9 -- Changes in and Disagreements with
Accountants on Accounting and
Financial
Disclosure......................... 63
PART III
Item 10 -- Directors and Executive Officers of
the Registrant..................... 63
Item 11 -- Executive Compensation............. 63
Item 12 -- Security Ownership of Certain
Beneficial Owners and
Management....................... 63
Item 13 -- Certain Relationships and Related
Transactions..................... 63
PART IV
Item 14 -- Exhibits, Financial Statement
Schedules and Reports on
Form 8-K......................... 64
Signatures....................................... 68
PART I
ITEM 1. BUSINESS
OVERVIEW OF CONSOLIDATED BUSINESS
Baltimore Gas and Electric Company (BGE) is the parent company and conducts
our primary business -- the electric and gas utility business. We also conduct
diversified businesses in subsidiary companies.
BGE was incorporated under the laws of the State of Maryland on June 20,
1906.
BGE owns two-thirds of the outstanding capital stock, including one-half of
the voting stock, of Safe Harbor Water Power Corporation. Safe Harbor is a
producer of hydroelectric power on the Susquehanna River at Safe Harbor,
Pennsylvania. We discuss this further in ITEM 2. PROPERTIES -- ELECTRIC.
OVERVIEW OF UTILITY BUSINESS
Our utility business includes our electric and gas businesses. Our electric
business generates, purchases, and sells electricity. Our gas business
purchases, transports, and sells natural gas. The focus of these activities is
serving customers in our service territory.
We furnish electric and gas retail services in the City of Baltimore and in
all or part of ten counties in Central Maryland. Our electric service territory
includes an area of approximately 2,300 square miles with an estimated
population of 2.6 million. Our gas service territory includes an area of more
than 600 square miles with an estimated population of 2.0 million. There are no
municipal or cooperative wholesale customers within our service territory.
As discussed throughout this report, the two units at our Calvert Cliffs
Nuclear Power Plant (Calvert Cliffs) are our principal generating facilities and
have the lowest fuel cost in our system. An extended shutdown of either of these
Units could have a substantial adverse effect on our business and financial
condition. We describe prior outages at our nuclear plant in the NUCLEAR
OPERATIONS section and in NOTE 12 TO CONSOLIDATED FINANCIAL STATEMENTS.
We describe our utility business further in five other sections of this
report -- ELECTRIC BUSINESS, ELECTRIC OPERATING STATISTICS, GAS OPERATING
STATISTICS, GAS BUSINESS, and FRANCHISES.
COMPETITION AND RESPONSE TO REGULATORY CHANGE
The utility industry is facing substantial regulatory change designed to
encourage competition in the sale of gas and electric services. To prepare for
this change, we regularly reevaluate our strategies.
We reevaluate our strategies with two goals in mind: to improve our
competitive position, and to anticipate and adapt to regulatory changes. We will
continue to develop strategies to keep us competitive. These strategies might
include one or more of the following:
o complete or partial separation of our generation, transmission and
distribution functions,
o purchase or sale of generation assets,
o mergers or acquisitions of utility or non-utility businesses,
o spin-off or sale of one or more businesses,
o growth of revenues from diversified businesses.
We cannot predict whether any transactions of the types described above may
actually occur, nor can we predict what their effect on our financial condition
or competitive position might be.
We discuss competition in our electric and gas businesses in more detail in
the ELECTRIC REGULATORY MATTERS AND COMPETITION and GAS REGULATORY MATTERS AND
COMPETITION sections.
OVERVIEW OF DIVERSIFIED BUSINESSES
Our diversified businesses are organized in three groups:
o Constellation(TM) Holdings, Inc. and Subsidiaries, together known as
the Constellation Holdings Companies -- our power generation,
financial investments, and real estate businesses,
o Constellation Energy Solutions(TM), Inc. and Subsidiaries -- our
energy marketing businesses, and
o BGE Home Products & Services, Inc. and Subsidiaries -- our home
products and commercial building systems businesses.
We describe our diversified businesses in more detail in the DIVERSIFIED
BUSINESSES section.
1
OPERATING REVENUES AND INCOME
The percentages of Operating Revenues and Operating Income attributable to
our electric, gas, and diversified businesses are shown in the tables below. We
present other information about these segments in NOTE 2 TO CONSOLIDATED
FINANCIAL STATEMENTS.
OPERATING REVENUES
------------------------------
ELECTRIC GAS DIVERSIFIED
-------- --- -----------
1997...................... 66% 16% 18%
1996...................... 70 16 14
1995...................... 76 14 10
1994...................... 76 15 9
1993...................... 77 16 7
OPERATING INCOME*
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ELECTRIC GAS DIVERSIFIED
-------- --- -----------
1997...................... 82% 9% 9%
1996...................... 75 10 15
1995...................... 83 7 10
1994...................... 85 4 11
1993...................... 87 6 7
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*Excluding the effect of income taxes.
The percentages for our gas and electric business differ due to two
factors:
o our level of investment in each business, and
o our fuel costs in each business.
Our electric and gas operating revenues reflect amounts collected for fuel
and other operating expenses plus a return on our investment. Our investment for
ratemaking purposes in the electric business is $4.8 billion, but our investment
for ratemaking purposes in the gas business is approximately $676 million. As a
result, our electric operating revenues include a much higher return component
than our gas operating revenues.
Also, as shown in our Consolidated Statements of Income in ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA, our electric fuel costs ("electric
fuel and purchased energy") were 24% of electric revenues in 1997, and our
purchased gas costs ("gas purchased for resale") were 56% of gas revenues in
1997. This means our cost of fuel in relation to our revenues is lower in the
electric business than in the gas business.
We charge the actual cost of the fuel we use to generate electricity to
customers with no profit to us. The price we charge for natural gas is based on
a market based rates incentive mechanism approved by the Maryland Public Service
Commission (Maryland PSC). We discuss market based rates further in the GAS
REGULATORY MATTERS AND COMPETITION section.
Our revenues come from many customers -- residential, commercial, and
industrial. Our largest electric customer provides 2.4% of our total electric
revenues. Our largest gas customer provides 1.3% of our total gas revenues.
As shown in the tables, the percentages for operating revenues and
operating income have historically been about the same for diversified
businesses. However, in 1997 the percentages differ because the Constellation
Holdings Companies wrote down their investments in two real estate projects.
These write-downs reduced diversified business operating income by about $71
million. We discuss these write-downs further in the DIVERSIFIED BUSINESSES
Section.
2
CONSOLIDATED CAPITAL REQUIREMENTS
Our business requires a great deal of capital. Our actual capital
requirements for the years 1995 through 1997, along with estimated amounts for
the years 1998 through 2000, are shown below:
1995 1996 1997 1998 1999 2000
---- ---- ------ ---- ------ ------
(IN MILLIONS)
Utility Business Capital Requirements
Construction expenditures (excluding AFC)
Electric................................................... $223 $219 $ 238 $236 $ 260 $ 273
Gas........................................................ 70 84 89 77 76 72
Common..................................................... 51 46 38 34 27 24
---- ---- ------ ---- ------ ------
Total construction expenditures......................... 344 349 365 347 363 369
AFC (a)...................................................... 22 10 8 8 11 14
Nuclear fuel (uranium purchases and
processing charges)........................................ 46 47 44 50 50 48
Deferred energy conservation expenditures (b)................ 46 31 27 12 10 10
Retirement of long-term debt and redemption of preference
stock...................................................... 279 184 243 117 344 264
---- ---- ------ ---- ------ ------
Total utility business capital requirements............. 737 621 687 534 778 705
---- ---- ------ ---- ------ ------
Diversified Business Capital Requirements.................... 173 170 344 333 271 403
---- ---- ------ ---- ------ ------
Total capital requirements.............................. $910 $791 $1,031 $867 $1,049 $1,108
==== ==== ====== ==== ====== ======
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(a) Allowance for Funds Used During Construction (AFC) is recorded for all
construction projects with a construction period of more than one month. We
discuss AFC further in NOTE 1 TO CONSOLIDATED FINANCIAL STATEMENTS.
(b) We discuss deferred energy conservation expenditures further in NOTE 5 TO
CONSOLIDATED FINANCIAL STATEMENTS.
CAPITAL REQUIREMENTS OF OUR UTILITY BUSINESS
We continuously review and change our construction program, so actual
expenditures may vary from the estimates for the years 1998 through 2000 in the
capital requirements chart. Our actual capital requirements may vary from the
estimates set forth in the table because of a number of factors such as:
o inflation and economic conditions,
o regulation and legislation,
o load growth,
o environmental protection standards, and
o the cost and availability of capital.
During the five-year period 1998 through 2002, we expect to spend about:
o $1.8 billion for construction projects,
o $240 million for nuclear fuel, and
o $50 million for deferred energy conservation programs.
Our projections of future electric construction expenditures do not include
costs to build more generating units. Electric construction expenditures include
improvements to our generating plants and transmission and distribution
facilities. They also include estimated costs for replacing the steam generators
and extending the operating licenses at Calvert Cliffs. The operating licenses
expire in 2014 for Unit 1 and in 2016 for Unit 2. We estimate these Calvert
Cliffs costs to be:
o $27 million in 1998,
o $38 million in 1999, and
o $44 million in 2000.
We estimate that during the three-year period 2001 through 2003, we will spend
an additional $175 million to complete the replacement of the steam generators
and extend the operating licenses at Calvert Cliffs.
If we do not replace the steam generators, we estimate that Calvert Cliffs
could not operate beyond the 2004-2006 time period. We expect the steam
generator replacements to occur during the 2002 refueling outage for Unit 1 and
during the 2003 outage for Unit 2.
During the period January 1, 1993 through December 31, 1997 we:
o spent about $2.0 billion for additions to our utility plant, which
is about 24% of our total utility plant (excluding nuclear fuel)
at December 31, 1997, and
o retired $414 million of our utility plant.
We estimate that we will need about $1.1 billion to retire long-term debt
(including sinking fund payments) and redeem preference stock during the
five-year period 1998-2002.
We discuss our capital requirements further in ITEM 7. MD&A -- LIQUIDITY
AND CAPITAL RESOURCES.
3
CAPITAL REQUIREMENTS OF OUR DIVERSIFIED
BUSINESSES
The capital requirements for our diversified businesses may vary from the
estimates set forth in the table due to a number of factors including market and
economic conditions. We discuss the capital requirements for these businesses
further in two sections of this report: DIVERSIFIED BUSINESS CAPITAL
REQUIREMENTS and ITEM 7. MD&A -- CAPITAL REQUIREMENTS OF OUR DIVERSIFIED
BUSINESSES.
ELECTRIC BUSINESS
We get most of our revenues and operating income from our electric utility
business. We describe this business in several paragraphs below. We discuss our
electric power marketing business separately under the heading DIVERSIFIED
BUSINESSES.
ELECTRIC REGULATORY MATTERS
AND COMPETITION
In recent years we have focused strategic attention on federal regulatory
changes that have increased competition in the wholesale market for bulk power
and expanded competition in the market for generation. Our board of directors
has a Long Range Strategy Committee to oversee the development of our long range
strategic goals, and to consider strategic initiatives presented by management.
Many of these changes were prompted by the Energy Policy Act of 1992 (the
1992 Act). The 1992 Act:
o granted the Federal Energy Regulatory Commission the authority to
order electric utilities to provide transmission service to other
utilities and to other buyers and sellers of electricity in the
wholesale market, and
o created a new class of power producers called exempt wholesale
generators, which are exempt from regulation under the Public
Utility Holding Company Act of 1935, as amended (the 1935 Act).
This exemption has increased the number of entrants into the
electric generation market.
Other changes resulted from policies at the Securities and Exchange
Commission, which has liberalized its interpretation and administration of the
1935 Act in ways that have made mergers between utility companies less
burdensome, thereby facilitating the creation of larger industry competitors.
In addition to the above changes, state legislators and regulators around
the United States are redefining regulatory plans for the electric utility
industry.
In Maryland, the State Legislature established a task force in 1997 to
examine the structure of the electric utility industry. The task force met
several times starting in September 1997 to explore whether all Maryland retail
customers should be allowed to choose any electricity supplier. Presently each
retail customer in Maryland is served by the single electric utility company
that holds the franchise in the area where the customer lives. Under customer
choice, the local electric utility would continue to transmit and deliver
electricity; however, the customer could contract to buy the electricity from
any willing supplier. From the perspective of the electric utility, this means
that transmission and distribution of electricity will remain regulated services
and the generation of electricity will become a competitive service.
There are many issues associated with moving from a regulated generation
market to a competitive generation market. These issues include, among others:
o the recovery of stranded costs(1) by electric utilities,
o adjusting the tax burden so as not to penalize electric utilities'
current generating assets in a competitive market,
o how to address the needs of low income customers, and
o the need to maintain reliable electric service.
The Maryland task force has determined that these issues are complex and
that comprehensive legislation cannot be enacted in the 1998 legislative
session. The Maryland legislature meets annually from mid-January to mid-April.
The task force may continue its work during 1998 and recommend legislation for
enactment in the 1999 legislative session. It appears the task force believes
that the issues can be fully evaluated so that implementation of customer choice
should begin not later than October 1, 2000.
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(1) What are stranded costs? They are costs a utility would recover under a
regulated pricing system, but not a competitive one. Traditionally, utilities
have been required to serve all customers in their franchised area while
regulators have set the rates customers pay for that service. To meet customers'
demand for electricity, utilities have had to build facilities, including
generating plants, and enter into contracts to buy power, among other things.
While regulators have approved these investments, they have tried to keep prices
low for consumers by setting rates that defer recovery of these costs over
longer than normal time periods.
Under customer choice, however, electric supply rates will be set by the
market, not by regulators. That means if the market price drops below the
current regulated price, the utility would not recover its investments in
facilities or costs under contracts to buy power and, therefore, the costs would
be "stranded'.
4
The Maryland Public Service Commission (Maryland PSC) has also addressed
the customer choice issues. In its order issued in December 1997, the Maryland
PSC required the phase-in of customer choice in three increments, with one third
of the customers being offered customer choice in each increment. The three
increments are phased in over two years from July 1, 2000 to July 1, 2002. The
Maryland PSC order contemplates a series of hearings and meetings to address the
issues surrounding customer choice. The Maryland PSC also recognizes the need
for legislation to deal with certain issues. BGE will be participating in the
hearings and meetings to be held by the Maryland PSC. We will quantify our
stranded costs and argue for recovery of these costs over a reasonable period of
time. Based on similar proceedings in other states, including neighboring
Pennsylvania, we can expect opposition to the recovery of stranded costs.
It is not possible to predict the ultimate effect competition will have on
our earnings in the future.
ELECTRIC RATE MATTERS
ENERGY CONSERVATION SURCHARGE
The Maryland PSC allows us to include in base rates a component to recover
money we have spent on conservation programs. This component is called an
"energy conservation surcharge" and was approved by the Maryland PSC effective
July 1, 1992. Under this surcharge the Maryland PSC limits what our electric
business profit can be. If, at the end of the year, we have exceeded our allowed
profit, we lower the amount of future surcharges to our customers to correct the
amount of overage, plus interest. The surcharge is reset on July 1 of each year.
We also discuss the surcharge in ITEM 7. MD&A -- RESULTS OF OPERATIONS.
POSTRETIREMENT AND POSTEMPLOYMENT BENEFIT
COSTS
Beginning in 1998, the Maryland PSC authorized us to make some changes in
the way we account for postretirement and other postemployment benefit costs.
The Maryland PSC authorized us to:
o expense all of the increase in annual postretirement benefit costs
related to our electric business, and
o amortize deferred postretirement and other postemployment benefit
costs related to our utility business over 15 years.
The Maryland PSC authorized us to reflect these changes in our current
electric base rates and will adjust our gas base rates to recover the higher
costs that will be recognized in 1998. We discuss this also in the GAS RATE
MATTERS section and in NOTE 6 TO CONSOLIDATED FINANCIAL STATEMENTS.
ELECTRIC FUEL RATE PROCEEDINGS
By law, we are allowed to recover our cost of electric fuel if the Maryland
PSC finds that, among other things, we have kept the productive capacity of our
generating plants at a reasonable level. To do this, the Maryland PSC will
perform an evaluation of each outage (other than regular maintenance outages) at
our generating plants. The evaluation will determine if we used all reasonable
and cost-effective maintenance and operating control procedures to try to
prevent the outage.
The Maryland PSC, under the Generating Unit Performance Program, measures
annually whether we have maintained the productive capacity of our generating
plants at reasonable levels. To do this, the program uses a system-wide
generating performance target and an individual performance target for each base
load generating unit. In fuel rate hearings, actual generating performance
adjusted for planned outages will be compared first to the system-wide target.
If that target is met, it should mean that the requirements of Maryland law have
been met. If the system-wide target is not met, each unit's adjusted actual
generating performance will be compared to its individual performance target to
determine if the requirements of Maryland law have been met and, if not, to
determine the basis for possibly imposing a penalty on BGE. Even if we meet
these targets, other parties to fuel rate hearings may still question whether we
used all reasonable and cost-effective procedures to try to prevent an outage.
If the Maryland PSC decides we were deficient in some way, the Maryland PSC may
not allow us to recover the cost of replacement energy.
BGE is required to submit to the Maryland PSC the actual generating
performance data for each calendar year 45 days after year end. The Maryland PSC
reviews the performance for each calendar year in the first fuel rate proceeding
that is initiated after the data is submitted. BGE must initiate fuel rate
proceedings in any month following a month during which the calculated fuel rate
decreased by more than 5% and may initiate fuel rate proceedings in any month
following a month during which the calculated fuel rate increased by more than
5%.
NUCLEAR OPERATIONS
The two units at Calvert Cliffs use the cheapest fuel. As a result, the
costs of replacement energy associated with outages at these units can be
significant.
5
Before the Generating Unit Performance Program became effective, we were
unable to recover a total of $9.6 million in replacement energy costs for
outages at Calvert Cliffs.
Since 1987 when the Generating Unit Performance Program became effective,
we have been able to recover all replacement energy costs for Calvert Cliffs
outages in 1988, 1992, 1993 and 1994. However, for a 66-day outage at Calvert
Cliffs during 1987 we were unable to recover approximately $4.5 million of our
replacement energy costs. Although we met the system-wide and Calvert Cliffs
performance targets, the Maryland PSC found that the presumption of
reasonableness was overcome by a showing that the outage was caused by
mismanagement.
As a result of the settlement of litigation surrounding an extended outage
at Calvert Cliffs during 1989 to 1991, we wrote off a total of $118 million of
replacement energy costs ($35 million in 1990 and $83 million in 1996), plus
$5.6 million of related financing charges (written off in 1996).
Our performance in 1995 and 1996 is currently being reviewed in a fuel rate
proceeding. We established that we exceeded the system-wide target for those
years as well as the performance target for Calvert Cliffs for 1995. Performance
for 1997 will be reviewed when we submit our next fuel rate application. We
cannot estimate the amount of replacement energy costs that could be challenged
or disallowed in future fuel rate proceedings, but such amounts could be
material.
The following is a summary of Calvert Cliffs' performance over the last 5
years:
GENERATION (MWH) CAPACITY FACTOR
---------------- ---------------
1993............. 12,300,816 85%
1994............. 11,225,977 77%
1995............. 12,940,496 88%
1996............. 12,069,937 82%
1997............. 13,133,441 90%
ELECTRIC LOAD MANAGEMENT, ENERGY,
AND CAPACITY PURCHASES
We have implemented various programs for use when system operating
conditions require a reduction in load. We refer to these programs as active
load management programs. These programs include:
o customer-owned generation and curtailable service for large
commercial and industrial customers,
o air conditioning control which is available to residential and
commercial customers, and
o residential water heater control.
We have generally activated these programs on peak summer days. The
potential reduction in the Summer 1998 peak load from active load management is
approximately 540 megawatts (MW). We recover the costs of these load management
programs from our customers.
Our generation and transmission facilities are connected to those of
neighboring utility systems to form the Pennsylvania-New Jersey-Maryland
Interconnection (PJM). Under the PJM agreement, we use the interconnected
facilities for substantial energy interchange and capacity transactions as well
as emergency assistance. In addition, sometimes we enter into short-term
capacity transactions to meet PJM obligations.
We have an agreement with Pennsylvania Power & Light Company (PP&L) to
purchase electricity and capacity (availability to supply electricity) 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 meeting capacity
obligations. The PP&L agreement:
o entitles us to 5.94% of the electricity output, and net capacity
(currently 130 MW), of PP&L's nuclear Susquehanna Steam Electric
Station from October 1, 1991 to May 31, 2001, and
o enables us to treat a portion of PP&L's capacity as our capacity
for purposes of satisfying our installed capacity requirements as
a member of the PJM.
We are 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.
Our firm capacity purchases at December 31, 1997 represented:
o 170 MW of rated capacity of Bethlehem Steel Corporation's Sparrows
Point complex,
o 57 MW of rated capacity of the Baltimore Refuse Energy Systems
Company, and
o 130 MW of Susquehanna capacity from PP&L.
In 1994 PECO Energy won a competitive bidding program to supply us 140 MW
of firm electric capacity and associated energy for 25 years beginning June 1,
1998. The Federal Energy Regulatory Commission and the Maryland PSC have both
accepted this contract.
6
FUEL FOR ELECTRIC GENERATION
Our electric generation by type of fuel and the cost of each fuel in the
five-year period 1993-1997 are shown below:
AVERAGE COST OF FUEL CONSUMED
GENERATION BY FUEL TYPE ((CENTS) PER MILLION BTU)
------------------------------------ ----------------------------------------------
1997 1996 1995 1994 1993 1997 1996 1995 1994 1993
---- ---- ---- ---- ---- ------ ------ ------ ------ ------
Nuclear (a)................... 44% 40% 43% 39% 43% 46.51 47.29 47.22 52.06 53.01
Coal.......................... 59 58 57 56 55 140.41 143.80 148.64 148.64 151.85
Oil........................... 1 1 1 3 3 283.61 313.33 267.59 245.28 253.36
Hydro & Gas................... 3 4 3 3 3 -- -- -- -- --
---- ---- ---- ---- ----
107 103 104 101 104
Net Interchange Purchases
(Sales)....................... (7) (3) (4) (1) (4)
---- ---- ---- ---- ----
100% 100% 100% 100% 100%
==== ==== ==== ==== ====
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(a) Nuclear fuel costs include disposal costs associated with long-term off-site
spent fuel storage and shipping, which is currently set by law at one mill
per kilowatt-hour of nuclear generation (approximately 10 cents per million
Btu), and contributions to a fund for decommissioning and decontaminating
the Department of Energy's uranium enrichment facility. We discuss this
further below.
NUCLEAR
The supply of fuel for nuclear generating stations includes the:
o purchase of uranium concentrates,
o conversion to uranium hexafluoride,
o enrichment of uranium hexafluoride, and
o fabrication of nuclear fuel assemblies.
Information is shown below about fuel requirements for Calvert Cliffs Units 1
and 2:
Uranium We have, either in inventory or under
Concentrates: contract, sufficient quantities of
uranium to meet 70 to 80% of our
requirements through 2004.
Conversion: We have contractual commitments
providing for the conversion of
uranium concentrates into uranium
hexafluoride which will meet
approximately 75% of our requirements
through 2004.
Enrichment: We have a contract with the U.S.
Enrichment Corporation for the
enrichment of 100% of our enrichment
requirements through 1998, declining
to approximately 50% by 2004.
Fuel Assembly We have contracted for the
Fabrication: fabrication of fuel assemblies for
reloads required through 2013.
The nuclear fuel market is very competitive and we do not anticipate any
problem in meeting our requirements beyond the periods noted above. We discuss
our expenditures for nuclear fuel in ITEM 7. MD&A -- LIQUIDITY AND CAPITAL
RESOURCES.
STORAGE OF SPENT NUCLEAR FUEL: Under the Nuclear Waste Policy Act of 1982
(the 1982 Act), we are required to place spent fuel discharged from Calvert
Cliffs into a federal repository. Such facilities do not currently exist, and,
consequently, must be developed and licensed. We cannot predict when such
facilities will be available. However, the 1982 Act requires the federal
government to accept spent fuel starting in 1998. We cannot predict what the
ultimate cost to dispose of the spent fuel will be. However, the 1982 Act
assesses a one mill per kilowatt-hour fee on nuclear electricity generated and
sold. We estimate this fee to be approximately $13 million for Calvert Cliffs
each year based on expected operating levels. Fees are deposited into the
Nuclear Waste Fund.
In December 1996, the United States Department of Energy (DOE) notified us
and other nuclear utilities that it is unable to meet the 1998 deadline for
accepting spent fuel. We are participating in litigation, along with 36 other
utilities, against the DOE. The litigation, titled NORTHERN STATES POWER, ET AL.
V. DOE, was filed January 31, 1997 in the United States Court of Appeals for the
D.C. Circuit. That court has original jurisdiction under the 1982 Act. The
utilities asked the court to allow them to pay fees, that formerly went directly
to DOE for deposit into the Nuclear Waste Fund, into escrow instead. Among other
remedies, the utilities also asked the court to force DOE to submit a program
with milestones illustrating how it would meet the deadline for accepting spent
nuclear fuel, and a monthly report to allow the utilities to monitor DOE's
progress.
7
On November 14, 1997 the court ordered DOE to comply with its unconditional
obligation under the 1982 Act to dispose of spent fuel. The court did not grant
the utilities the remedies sought, stating that adequate contractual and
statutory remedies already existed. The DOE and one utility have filed separate
motions for reconsideration with the court. In its motion for reconsideration,
DOE has advised the court that damage claims for breach of its spent fuel
disposal contracts would be paid from the Nuclear Waste Fund. Any shortfall in
funding would be replenished by increasing utility fees. This would render the
utilities' contract remedies meaningless. On February 19, 1998 the 36 utilities,
including BGE, filed a joint motion to enforce the court's order. Similar
motions were filed by six additional utilities. These 42 utilities represent
virtually the entire nuclear industry. The motions request:
o that the damages for breach not be paid by DOE from the Nuclear
Waste Fund,
o that DOE establish, in good faith, a program for immediate
disposal of spent fuel, specifying milestones,
o that the utilities be allowed to withhold future payment into the
Nuclear Waste Fund unless and until DOE complies with its obligations to
dispose of spent fuel, and
o that utilities not be penalized by DOE for withholding future
payments.
BGE is currently evaluating its contract options in light of the court's
decision. BGE cannot currently estimate the total amount of the costs it will
incur as a result of DOE's failure to meet the 1998 deadline.
Maryland law makes it unlawful to establish within the State a facility for
the permanent storage of high-level nuclear waste, unless required by federal
law. We received a license from the Nuclear Regulatory Commission to operate our
on-site independent spent fuel storage facility. We now have storage capacity at
Calvert Cliffs that will accommodate spent fuel from operations through the year
2006. In addition, we can expand our temporary storage capacity to meet future
requirements until federal storage is available.
COSTS FOR DECOMMISSIONING URANIUM ENRICHMENT FACILITIES: 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 through 1992. 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 CONSOLIDATED FINANCIAL STATEMENTS under the heading "UTILITY PLANT,
DEPRECIATION AND AMORTIZATION, AND DECOMMISSIONING."
COAL
We get most of our coal under supply contracts with mining operators, and
we get the rest through spot purchases. We believe that we will be able to renew
supply contracts as they expire or enter into similar contracts with other coal
suppliers. Our coal-burning facilities have the following requirements:
ANNUAL COAL
REQUIREMENT
(TONS)
------------------
Brandon Shores (a)
Units 1 and 2 (combined)........ 3,500,000
Crane (b)
Units 1 and 2 (combined)........ 700,000
Wagner (c)
Units 2 and 3 (combined)........ 900,000
- ---------------
Special Coal Restrictions:
(a) Sulfur content less than 0.8%
(b) Low ash melting temperature
(c) Sulfur content no more than 1%
Coal deliveries to our coal burning facilities are made by rail and barge.
The coal we use is produced from mines located in central and northern
Appalachia.
We have 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. Both of these plants are located in Pennsylvania. 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.
OIL
Under normal burn practices, BGE's requirements for residual fuel oil
amount to approximately 1,000,000 barrels of low-sulfur oil per year. Deliveries
of residual fuel oil are made directly into BGE barges from the suppliers'
Baltimore Harbor marine terminal for distribution to the various generating
plant locations.
GAS
We have a firm natural gas transportation entitlement of 3,500 dekatherms a
day to provide ignition and banking at certain power plants. We purchase gas for
electric generation as needed in the spot market using interruptible
transportation arrangements. Some of our gas fired units can use residual fuel
oil instead of gas.
8
ELECTRIC OPERATING STATISTICS
YEAR ENDED DECEMBER 31,
--------------------------------------------------------
1997 1996 1995 1994 1993
-------- -------- -------- -------- --------
Electric Output (In Thousands) -- MWH:
Generated............................................. 31,289 30,107 30,548 28,413 28,907
Purchased (A)......................................... 4,737 7,560 7,403 6,270 3,643
-------- -------- -------- -------- --------
Subtotal......................................... 36,026 37,667 37,951 34,683 32,550
Less Interchange and Other Sales...................... 6,224 7,580 8,149 5,684 4,149
-------- -------- -------- -------- --------
Total Output..................................... 29,802 30,087 29,802 28,999 28,401
======== ======== ======== ======== ========
Power Generated and Purchased at Times of Peak Load (MW)
(one hour):
Generated by Company.................................. 5,472 4,789 5,162 3,384 5,245
Net Purchased (A)..................................... 508 1,166 785 2,654 631
-------- -------- -------- -------- --------
Peak Load (B)......................................... 5,980 5,955 5,947 6,038 5,876
======== ======== ======== ======== ========
Annual System Load Factor (%)........................... 56.9 57.5 57.2 54.7 55.2
Revenues (In Millions)
Residential........................................... $ 932.5 $ 958.7 $ 955.2 $ 931.7 $ 931.7
Commercial............................................ 892.6 861.3 879.4 853.0 869.8
Industrial............................................ 211.9 207.6 208.5 205.6 199.0
-------- -------- -------- -------- --------
System Sales.......................................... 2,037.0 2,027.6 2,043.1 1,990.3 2,000.5
Interchange and Other Sales........................... 132.7 155.9 167.0 118.0 91.5
Other................................................. 22.3 25.5 21.0 19.1 20.1
-------- -------- -------- -------- --------
Total............................................ $2,192.0 $2,209.0 $2,231.1 $2,127.4 $2,112.1
======== ======== ======== ======== ========
Sales (In Thousands) -- MWH:
Residential........................................... 10,806 11,243 10,966 10,670 10,614
Commercial............................................ 12,718 12,591 12,635 12,351 12,395
Industrial............................................ 4,575 4,596 4,591 4,433 3,763
-------- -------- -------- -------- --------
System Sales.......................................... 28,099 28,430 28,192 27,454 26,772
Interchange and Other Sales........................... 6,224 7,580 8,149 5,684 4,149
-------- -------- -------- -------- --------
Total............................................ 34,323 36,010 36,341 33,138 30,921
======== ======== ======== ======== ========
Customers (In Thousands)
Residential........................................... 1,001.0 995.2 988.2 978.6 968.2
Commercial............................................ 105.9 104.5 103.4 101.9 100.8
Industrial............................................ 4.5 4.3 4.1 4.0 3.8
-------- -------- -------- -------- --------
Total............................................ 1,111.4 1,104.0 1,095.7 1,084.5 1,072.8
======== ======== ======== ======== ========
Average Cost of Fuel Consumed ((cents) per million
BTU).................................................. 105.76 108.05 104.78 112.44 112.77
======== ======== ======== ======== ========
We 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 we own two-thirds of the capital stock.
(B) We discuss active load management programs which may be activated at times
of peak load in ELECTRIC LOAD MANAGEMENT, ENERGY, AND CAPACITY PURCHASES.
9
GAS OPERATING STATISTICS
YEAR ENDED DECEMBER 31,
--------------------------------------------------------
1997 1996 1995 1994 1993
-------- -------- -------- -------- --------
Gas Output (In Thousands) -- DTH:
Purchased.......................................... 62,988 70,260 70,391 68,541 71,221
LNG Withdrawn from Storage......................... 484 904 815 698 725
Produced........................................... 541 784 528 828 259
-------- -------- -------- -------- --------
Total Output.................................. 64,013 71,948 71,734 70,067 72,205
Delivery service gas (A)........................... 52,629 45,964 43,854 41,897 38,521
Off-system sales (B)............................... 17,611 10,204 -- -- --
-------- -------- -------- -------- --------
Total......................................... 134,253 128,116 115,588 111,964 110,726
======== ======== ======== ======== ========
Peak Day Sendout (DTH)............................... 765,011 708,966 706,287 761,900 657,700
======== ======== ======== ======== ========
Capability on Peak Day (DTH)......................... 870,000 870,000 847,000 847,000 847,000
Revenues (In Millions)
Residential
Excluding Delivery Service...................... $ 321.7 $ 320.1 $ 248.3 $ 262.7 $ 265.6
Delivery Service (C)............................ 0.5 -- -- -- --
Commercial
Excluding Delivery Service...................... 113.5 125.1 109.9 121.0 121.8
Delivery Service................................ 12.9 7.2 3.7 2.3 3.3
Industrial
Excluding Delivery Service...................... 11.4 17.1 16.7 20.2 22.3
Delivery Service................................ 17.2 14.6 16.3 9.6 12.9
-------- -------- -------- -------- --------
System sales....................................... 477.2 484.1 394.9 415.8 425.9
Off-system sales................................... 37.5 26.6 -- -- --
-------- -------- -------- -------- --------
Other.............................................. 6.9 6.6 5.6 5.4 7.3
-------- -------- -------- -------- --------
Total......................................... $ 521.6 $ 517.3 $ 400.5 $ 421.2 $ 433.2
======== ======== ======== ======== ========
Sales (In Thousands) -- DTH:
Residential
Excluding Delivery Service...................... 39,958 43,784 40,211 40,279 40,029
Delivery Service................................ 205 -- -- -- --
Commercial
Excluding Delivery Service...................... 18,435 22,698 23,612 23,712 23,830
Delivery Service................................ 12,964 8,755 6,982 6,490 7,428
Industrial
Excluding Delivery Service...................... 2,016 2,887 4,102 4,410 5,298
Delivery Service................................ 38,791 36,201 35,925 33,837 31,390
-------- -------- -------- -------- --------
System sales....................................... 112,369 114,325 110,832 108,728 107,975
Off-system sales................................... 17,611 10,204 -- -- --
-------- -------- -------- -------- --------
Total......................................... 129,980 124,529 110,832 108,728 107,975
======== ======== ======== ======== ========
Customers (In Thousands)
Residential........................................ 524.5 516.5 506.8 498.2 491.2
Commercial......................................... 39.3 38.9 38.4 37.9 37.5
Industrial......................................... 1.3 1.3 1.3 1.3 1.3
-------- -------- -------- -------- --------
Total......................................... 565.1 556.7 546.5 537.4 530.0
======== ======== ======== ======== ========
We achieved an all-time peak day sendout of 765,011 DTH on January 18,
1997.
- ---------------
(A) Delivery service gas is gas purchased by customers directly from suppliers
for which we receive a fee for transportation through our system. We discuss
this further in ITEM 7. MD&A -- RESULTS OF OPERATIONS.
(B) Off-system sales are low-margin sales to wholesale suppliers of natural gas
outside our service territory (beginning first quarter 1996). We discuss
this further in ITEM 7. MD&A -- RESULTS OF OPERATIONS.
(C) Residential delivery service represents sales of gas through our Gas Options
pilot program that we began in late 1997. We discuss this program further in
the GAS REGULATORY MATTERS AND COMPETITION section.
10
GAS BUSINESS
We discuss our utility gas business on the previous page under GAS
OPERATING STATISTICS and in three other sections of this report: GAS REGULATORY
MATTERS AND COMPETITION; GAS OPERATIONS; AND GAS RATE MATTERS. We discuss our
gas marketing business separately under the heading DIVERSIFIED BUSINESSES.
GAS REGULATORY MATTERS AND
COMPETITION
To introduce competition, the natural gas industry is being deregulated,
and regulatory changes are well under way.
In 1992, the Federal Energy Regulatory Commission issued Order 636, which
increased gas users' ability to choose various gas purchasing, transportation,
brokering, and storage options. Consequently, we now buy all gas that we resell
directly from various suppliers (rather than pipeline companies) and arrange
separately for transportation and storage. We offer gas for sale to our
residential customers on a firm basis, and to our commercial and industrial
customers on a firm or interruptable basis. Alternatively, we can transport gas
for our customers. We also participate in the interstate markets, by releasing
pipeline capacity or bundling pipeline capacity with gas for off-system sales.
We provide our commercial and industrial customers who annually consume 250
DTH or more of gas with transportation service across our distribution system so
that they may make direct purchase and transportation arrangements with
suppliers and pipelines. Approximately 46% of the gas on our distribution system
is for these customers. We charge a fee for this transportation service. This
per unit charge assures that fixed costs are spread over the maximum number of
DTH. We also provide balancing and gas brokering services for these customers.
The Maryland PSC continues to encourage us and other utilities to offer
options for unbundling gas services and to allow smaller customers to arrange
for their own gas supplies. In response, we began a two-year Gas Options pilot
program for residential customers on November 1, 1997. Under the program:
o all of our residential natural gas customers are eligible, but
only up to 25,000 of them may participate (about 12,000 customers
currently participate).
o participants may shop for a natural gas supplier from a list of
companies, including one of our diversified businesses,
participating in the program.
o we continue to deliver the gas to customers' homes, and provide
customer services such as meter reading, billing, emergency
response, and regular maintenance.
Our Gas Options program is one of many natural gas pilot programs under way
across the country.
The Gas Options program and our delivery service should not significantly
impact our gas business earnings.
As part of our response to the increase in competition in the natural gas
business, we obtained approval from the Maryland PSC to utilize profit sharing
for earnings from off-system gas sales and capacity release revenues, and to
implement a market based rates incentive mechanism for gas sold by BGE on our
system. Off-system gas sales are direct sales to suppliers and end users of
natural gas outside our service territory. We make these sales as part of a
program to balance our supply of, and cost of, natural gas. Under market based
rates our actual cost of gas is compared to a market index (a measure of the
market price of gas in a given period). The difference between our actual cost
and the market index is shared equally between BGE (which benefits shareholders)
and customers.
GAS OPERATIONS
We distribute natural gas purchased directly from many producers and
marketers. We have transportation and storage agreements as shown below. These
agreements are on file with the Federal Energy Regulatory Commission. The gas is
transported to our city gate, under various transportation agreements, by:
o Columbia Gas Transmission Corporation,
o CNG Transmission Corporation, and
o Transcontinental Gas Pipe Line Corporation.
We have upstream transportation capacity under contract with:
o Tennessee Gas Pipeline Company,
o Texas Eastern Transmission Corporation,
o Columbia Gulf Transmission Company, and
o ANR Pipeline Company.
We have storage service agreements with:
o Columbia Gas Transmission Corporation,
o CNG Transmission Corporation, and
o ANR Pipeline Company.
Our current pipeline firm transportation entitlements to serve our firm
loads are 291,731
11
dekatherms (DTH) per day during the winter period and 266,731 DTH per day during
the summer period. We use the firm transportation capacity to move gas from the
Gulf of Mexico, Louisiana, south central regions of Texas and Canada to our 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. We can arrange
additional short-term contracts or exchange agreements with other gas companies
in the event of short-term emergencies.
We have three market area storage contracts to manage weather sensitive gas
demand during the winter period. Our current maximum storage entitlements are
224,435 DTH per day. To supplement our gas supply at times of heavy winter
demands and to be available in temporary emergencies affecting gas supply, we
have:
o a liquified natural gas facility for the liquefaction and storage
of natural gas with a storage capacity of 1,000,000 DTH and a
planned daily capacity of 287,988 DTH, and
o a propane air facility with a mined cavern and refrigerated
storage facilities having a total storage capacity equivalent to
1,000,000 DTH and a daily capacity of 85,000 DTH.
We have under contract sufficient volumes of propane for the operation of
the propane air facility and are capable of liquefying sufficient volumes of
natural gas during the summer months for operation of our liquefied natural gas
facility during winter periods.
GAS RATE MATTERS
POSTRETIREMENT AND POSTEMPLOYMENT BENEFIT
COSTS
Beginning in 1998, the Maryland PSC authorized us to make a change in the
way we account for postretirement and other postemployment benefit costs. The
Maryland PSC authorized us to amortize deferred postretirement and other
postemployment benefit costs related to our utility business over 15 years. The
Maryland PSC will adjust our gas base rates to recover the higher costs that
will be recognized in 1998. We discuss this also in the ELECTRIC RATE MATTERS
section and in NOTE 6 TO CONSOLIDATED FINANCIAL STATEMENTS.
1997 RATE CASE
During 1997, we applied for a $36.7 million increase in our gas base rates.
We applied for the increase to:
o provide a return on a higher level of gas rate base, due to
expansion of our gas distribution system and future capital
expenditures to meet customer growth,
o provide for an overall rate of return of 9.36% versus 9.04% (our
presently authorized rate), and
o to recover future increases in operating expenses that we have
committed to make.
In February 1998, we reached a settlement with the Maryland PSC for a $16
million increase in our gas base rates. The increase became effective March 1,
1998.
FRANCHISES
We have nonexclusive electric and gas franchises to use streets and other
highways which are adequate and sufficient to permit us to engage in our present
business. All such franchises, other than the gas franchises in Manchester,
Hampstead, Perryville, Sykesville, Havre de Grace, Mt. Airy, and Montgomery and
Frederick Counties, are unlimited as to time. The gas franchises for these
jurisdictions expire at various times from 2015 to 2087, except for Havre de
Grace which has the right, exercisable at twenty-year intervals from 1907, to
purchase all of our gas properties in that municipality. Conditions of the
franchises are satisfactory. We also have rights-of-way to maintain 26-inch
natural gas mains across certain Baltimore City owned property (principally
parks) which expire in 1998 and 2004, each subject to renewal during their last
year 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
Our diversified businesses are organized in three groups:
o Our power generation, financial investments, and real estate
businesses,
o Our energy marketing businesses, and
o Our home products and commercial building systems businesses.
12
OUR POWER GENERATION, FINANCIAL INVESTMENTS,
AND REAL ESTATE BUSINESSES
We refer to all of these together as the Constellation Holdings Companies.
Constellation Holdings, Inc. is a subsidiary of BGE and holds all of the stock
of the following three subsidiaries:
o Constellation Power, Inc. -- develops, owns, and operates power
generation projects,
o Constellation Investments, Inc. -- engages in financial
investments, and
o Constellation Real Estate Group, Inc. -- develops, owns, and
manages real estate and senior-living facilities.
The Constellation Holdings Companies' conduct a significant portion of
their activities through joint ventures in which they hold varying ownership
interests.
POWER GENERATION
Domestic
The Constellation Holdings Companies hold up to a 50% ownership interest in
23 power generating projects in operation accounting for $393 million of the
Constellation Holdings Companies' assets. These projects, all of which either
are qualifying facilities under the Public Utility Regulatory Policies Act of
1978 or are otherwise exempt from the Public Utility Holding Company Act of
1935, are of the following types and aggregate generation capacities:
o coal-166 MW o waste coal-185 MW
o solar-90 MW o wood burning-70 MW
o geothermal-126 MW o hydro-33 MW
In addition, the Constellation Holdings Companies:
o have spent another $17 million on projects in development,
o participate in the operation and maintenance of 13 power
generation projects existing or under construction, 12 of which
are projects in which the Constellation Holdings Companies hold an
ownership interest, and
o have invested $10.8 million in a coal processing facility that
they operate.
The Constellation Holdings Companies also invest in international power
projects. These are discussed later in this section.
CALIFORNIA POWER PURCHASE AGREEMENTS
The Constellation Holdings Companies have $261 million invested in 16
projects that sell electricity in California under power purchase agreements
called "Interim Standard Offer No. 4" agreements. Earnings from these projects
were $37.3 million, or $.25 per share, in 1997.
Under these agreements, the electricity rates are scheduled to change from
fixed rates to variable rates during 1996 through 2000. Some of the projects
have already had rate changes and have had lower revenues under variable rates
than they did under fixed rates. When the remaining projects transition to
variable rates, we expect the revenues from those projects to also be lower than
they are under fixed rates. However, the California projects that make the
highest revenues will not transition until 1999 and 2000. As a result, we do not
expect the Constellation Holdings Companies to have significantly lower earnings
due to the transition to variable rates before 2000. We cannot predict the
financial effects of the transition from fixed to variable rates on the
Constellation Holdings Companies or on BGE, but the effects could be material.
We describe these projects and the transition process in detail in NOTE 12
TO CONSOLIDATED FINANCIAL STATEMENTS.
International
The Constellation Holdings Companies' power generation business in Latin
America:
o develops, acquires, owns, and operates power generation projects, and
o acquires and owns distribution systems.
At December 31, 1997, the Constellation Holdings Companies had invested
about $23.1 million and committed another $4.3 million in power projects in
Latin America.
In the future, the Constellation Holdings Companies' power generation
business may be expanding further in both domestic and international projects.
FIRST QUARTER 1998 EVENT INCLUDES CONSTELLATION HOLDINGS COMPANIES' GUARANTEE
OF $73 MILLION
In the first quarter of 1998, affiliates of the Constellation Holdings
Companies entered into a $92.5 million credit facility to finance the
acquisition of
13
existing generating facilities and the development and construction of new
generating facilities in Guatemala. At the date of this report, the
Constellation Holdings Companies' obligation under the facility is $73 million.
FINANCIAL INVESTMENTS
Financial investments account for $197 million of the Constellation
Holdings Companies' assets. These assets include:
o $77 million in internally and externally managed securities portfolios,
o $89 million in a financial guaranty insurance company, and
o $31 million in tax-oriented transactions.
REAL ESTATE
Real estate and senior-living projects account for $509 million of the
Constellation Holdings Companies' assets. These projects include:
o land under development,
o office buildings,
o retail projects,
o distribution facility projects,
o an entertainment, dining, and retail complex in Orlando, Florida,
o a mixed-use planned-unit development,
o and senior-living facilities.
In 1997, the Constellation Holdings Companies recorded:
o a $14.1 million after-tax write-down of the investment in Church
Street Station -- an entertainment, dining, and retail complex in
Orlando, Florida -- because the Constellation Holdings Companies
have now decided to sell rather than keep the project, and
o a $31.9 million after-tax write-down of the investment in Piney
Orchard -- a mixed-use, planned-unit development -- because the
expected cash flow from the project was less than the
Constellation Holdings Companies' investment in the project.
We consider market demand, interest rates, the availability of financing,
and the strength of the economy in general when making decisions about our real
estate investments. If we were to sell our real estate projects in the current
market, we would have losses, although the amount of the losses is hard to
predict. Depending on market conditions in the future, we could also have losses
on any future sales.
We describe the Constellation Holdings Companies' real estate business
further in NOTE 12 TO CONSOLIDATED FINANCIAL STATEMENTS.
OUR ENERGY MARKETING BUSINESSES
Constellation Energy Solutions, Inc. is a subsidiary of BGE and serves as
the holding company for our three energy marketing businesses:
o Constellation Power Source(TM), Inc. -- our power marketing business,
o Constellation Energy Source(TM), Inc. -- our natural gas brokering
business, and
o Constellation Energy Projects and Services(TM), Inc. and Subsidiaries --
our energy services businesses.
POWER MARKETING
We formed CONSTELLATION POWER SOURCE, INC. in February 1997 to enter the
power marketing business. This new business provides power marketing and risk
management services to wholesale customers in North America by purchasing and
selling electric power, other energy commodities, and related derivatives.
Goldman Sachs Power, LLC, an affiliate of Goldman, Sachs & Co., the
investment banking firm, is the exclusive advisor to Constellation Power Source
for these services.
Constellation Power Source's business activities include trading:
o electricity,
o other energy commodities, and
o related derivative contracts.
Constellation Power Source uses the mark-to-market method of accounting for
these activities. Under the mark-to-market method of accounting, Constellation
Power Source:
o records assets and liabilities equal to the fair value of
commodities and derivatives it holds or sells,
o records these assets and liabilities at the time that it executes
contracts for these transactions, and
o records net gains and losses from both realized transactions and
changes in fair value of open commodity and derivative positions
as revenues in its income statement.
As a result of using the mark-to-market method of accounting, Constellation
Power
14
Source's revenue and earnings will fluctuate. The primary factors that cause
these fluctuations are:
o the number and size of new transactions,
o the magnitude and volatility of changes in commodity prices and
interest rates, and
o the number and size of open commodity and derivative positions
Constellation Power Source holds or sells.
Constellation Power Source management uses its best estimates to determine
the fair value of the commodities and derivatives positions it holds and
sells. These estimates consider various factors including closing exchange and
over-the-counter price quotations, time value, and volatility factors. However,
it is possible that future market prices could vary from those used in recording
assets and liabilities from trading activities, and such variations could be
material.
FIRST QUARTER 1998 EVENT INCLUDES BGE COMMITMENT OF
$115 MILLION
In March 1998, Constellation Power Source, Inc. and Goldman, Sachs Capital
Partners II L.P., an affiliate of Goldman, Sachs & Co., formed Orion Power
Holdings, Inc. to acquire electric generating plants in the United States and
Canada. Constellation Power Source owns a minority interest in Orion, and BGE
has committed to contribute up to $115 million in equity to Constellation Power
Source to fund its investment in Orion. Orion has entered into strategic
relationships with Constellation Power Source and Constellation Operating
Services, Inc. Constellation Power Source will be the exclusive provider of
power marketing and risk management services to Orion. Constellation Operating
Services will provide exclusive operating and maintenance services to Orion's
plants.
NATURAL GAS BROKERING
CONSTELLATION ENERGY SOURCE, INC. provides natural gas brokering and
related services for wholesale and retail customers.
ENERGY SERVICES
CONSTELLATION ENERGY PROJECTS & SERVICES, INC. AND ITS SUBSIDIARIES provide
a broad range of customized energy services, including:
o private electric and gas distribution systems,
o energy consulting,
o power quality services and equipment,
o campus and multi-building energy systems, and
o energy services contract work.
COMFORTLINK(REGISTER MARK) (a general partnership in which BGE is a
partner) provides district energy systems.
OUR HOME PRODUCTS AND COMMERCIAL BUILDING
SYSTEMS BUSINESSES
BGE HOME PRODUCTS & SERVICES, INC. provides comprehensive maintenance,
repair and replacement services for heating, air conditioning, plumbing,
electrical, indoor air quality systems, and major home appliances and
electronics. It also operates appliance and electronics retail stores and has a
home improvement business including kitchen and bathroom remodeling, replacement
doors and windows, siding, and roofing. Its subsidiary, BGE COMMERCIAL BUILDING
SYSTEMS, INC. (formerly named Maryland Environmental Systems, Inc.) specializes
in providing total building solutions for the commercial market. These services
include comprehensive maintenance, repair, replacement and new equipment
installation services for heating, ventilation, air conditioning, plumbing,
electrical, and building automation systems in small and large commercial
facilities. In 1997, BGE Home Products & Services, Inc. formed HP&S RECEIVABLES,
INC. -- solely to acquire and finance merchandise and service loans made by BGE
Home Products & Services, Inc.
15
DIVERSIFIED BUSINESS CAPITAL REQUIREMENTS
Capital requirements for our diversified businesses for 1995 through 1997,
along with estimated amounts for 1998 through 2000, are set forth below:
1995 1996 1997 1998 1999 2000
---- ---- ---- ---- ---- ----
(IN MILLIONS)
Diversified Business Capital Requirements
Investment requirements........................................... $118 $118 $156 $169 $134 $157
Retirement of long-term debt...................................... 55 52 188 164 137 246
---- ---- ---- ---- ---- ----
Total diversified business capital requirements................... $173 $170 $344 $333 $271 $403
==== ==== ==== ==== ==== ====
In the past, capital requirements of our diversified businesses only
included the Constellation Holdings Companies because they had the only
significant capital requirements. From time to time, however, our other
diversified businesses may develop significant capital requirements. As that
occurs, we will include the capital requirements of those businesses in the
capital requirements table. As discussed below under "DIVERSIFIED BUSINESS
INVESTMENT REQUIREMENTS," capital requirements for Constellation Power Source
and ComfortLink are also included this year.
Our diversified businesses expect to expand their businesses. This may
include expansion in the energy marketing, power generation, financial
investments, real estate, and senior-living facility businesses. Such expansion
could mean more investments in and acquisition of new projects. Our diversified
businesses have met their capital requirements in the past through borrowing,
cash from their operations, and from time to time, loans or equity contributions
from BGE. Our diversified businesses plan to raise the cash needed to meet
capital requirements in the future through these same methods.
DIVERSIFIED BUSINESS INVESTMENT REQUIREMENTS
The investment requirements of our diversified businesses include:
o the Constellation Holdings Companies' investments in financial
limited partnerships and funding for the development and
acquisition of projects, as well as loans made to project
entities,
o funding for growing Constellation Power Source's power marketing
business, and
o ComfortLink's funding for construction of district energy
projects.
Investment requirements for the years 1998 through 2000 include estimates
of funding for existing and anticipated projects. We continuously review and
modify those estimates. Actual investment requirements could vary a great deal
from the estimates in the table because they would be subject to several
variables, including:
o the type and number of projects selected for development,
o the effect of market conditions on those projects,
o the ability to obtain financing, and
o the availability of cash from operations.
The investment requirements exclude BGE's commitment to contribute up to
$115 million in equity to Constellation Power Source Inc. to fund its investment
in Orion Power Holdings, Inc.
DIVERSIFIED BUSINESS DEBT AND LIQUIDITY
Our diversified businesses plan to meet capital requirements by refinancing
debt as it comes due, by borrowing additional funds, and using cash generated by
the businesses. This includes cash from operations, sale of assets, and earned
tax benefits. BGE Home Products & Services, Inc. may also meet capital
requirements through sales of receivables.
If the Constellation Holdings Companies can get a reasonable value for real
estate, additional cash may be obtained by selling real estate projects. The
Constellation Holdings Companies' ability to sell or liquidate assets will
depend on market conditions, and we cannot give assurances that these sales or
liquidations could be made. For more information, see the discussion of the real
estate business and market in the REAL ESTATE section.
16
In 1997, the Constellation Holdings Companies issued $289 million of three
and four-year notes. In addition, our diversified businesses have the following
revolving credit agreements to provide additional cash for short-term financial
needs:
AMOUNT OF
REVOLVING CREDIT AGREEMENT
--------------------------
Constellation Holdings
Companies................ $75 million
ComfortLink................ $50 million
Constellation Energy
Solutions, Inc. and
Subsidiaries............. $10 million
See NOTES 3 and 4 TO CONSOLIDATED FINANCIAL STATEMENTS AND ITEM 7.
MD&A -- LIQUIDITY AND CAPITAL RESOURCES -- CAPITAL REQUIREMENTS OF OUR
DIVERSIFIED BUSINESSES for additional information about diversified businesses.
ENVIRONMENTAL MATTERS
We are subject to regulation by various federal, state, and local
authorities with regard to:
o air quality,
o water quality,
o waste disposal, and
o other environmental matters.
Some of the regulations require substantial expenditures for additions to
our utility plant and the use of more expensive low-sulfur fuels. We cannot
precisely estimate the total effect on our facilities and operations of current
and future environmental regulations and standards. However, we have increased
capital expenditures by approximately $117 million during the five-year period
1993-1997 to comply with existing standards and regulations, and we estimate
that the future capital expenditures necessary to comply with the standards and
regulations will be approximately:
o $14 million in 1998,
o $17 million in 1999, and
o $36 million in 2000.
CLEAN AIR
The Federal Clean Air Act (the Act) regulates health and welfare standards
for concentrations of air pollutants. Under the Act, the State of Maryland must
set limits on all major sources of these pollutants in the State so that the
standards are not exceeded. We have certain limits on our generating units that
put us in compliance with existing air quality regulations, as follows:
o All of our generating units, except Crane Units 1 and 2, are
limited to burning fuel (coal or oil) with a sulfur content of 1%
or below.
o The Crane Units 1 and 2 are limited to 3.5 pounds per million Btu
for sulfur dioxide, which is equivalent to a coal sulfur content
of approximately 2.4%.
o All units are limited to releasing 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.
o 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 Clean Air Act of 1990 contains two titles designed to reduce emissions
of sulfur dioxide and nitrogen oxide (NOx) from electric generating
stations -- Title IV and Title I.
Title IV addresses emissions of sulfur dioxide. Compliance is required in
two separate phases:
o Phase I became effective January 1, 1995. We met the requirements
of this phase by installing flue gas desulfurization systems
(scrubbers), switching fuels, and retiring some units.
o Phase II must be implemented by 2000. We are currently examining
what actions we should take to comply with this phase. We expect
to meet the compliance requirements through some combination of
installing flue gas desulfurization systems (scrubbers), switching
fuels, retiring some units, or allowance trading.
Title I addresses emissions of NOx, but the regulations of this title have
not been finalized by the government. As a result, our plans for complying with
this title are less certain. By 1999 the regulations require more NOx controls
for ozone attainment at our generating plants. The additional controls will
result in more expenditures, but it is difficult to estimate the level of those
expenditures since the regulations have not been finalized. However, based on
existing and proposed regulations, we currently estimate that the additional
controls at our generating plants will cost approximately $90 million.
In July 1997, the federal government published new National Ambient Air
Quality Standards for very fine particulates and revised standards for ozone
attainment. These standards may require increased controls at our fossil
generating plants in the future. We cannot estimate the cost of these increased
controls at this time because the states,
17
including Maryland, still need to determine what reductions in pollutants will
be necessary to meet the new federal standards.
WATER
The Maryland Department of the Environment regulates the discharge of waste
materials into the waters of the State of Maryland under the National Pollutant
Discharge Elimination System permit program. This program was established as
part of the Federal Clean Water Act. At the present time, we have the required
permits under the program for all of our steam electric generating plants.
The Maryland Department of the Environment water quality regulations
require us to, among other things, define procedures to determine compliance
with State water quality standards. These procedures require extensive studies
involving sampling and monitoring of the waters around affected generating
plants. The State of Maryland may require changes in plant operations. We
continually perform studies to determine whether any modifications will be
necessary to comply with these regulations.
WASTE DISPOSAL
The United States Environmental Protection Agency (EPA) has regulations for
implementing the portions of the Resource Conservation and Recovery Act that
deal with the management of hazardous wastes. These regulations, and the
Hazardous and Solid Waste Amendments of 1984, identify 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 regulations governing the management of hazardous wastes that are
similar to the federal regulations. We have procedures in place to comply with
all applicable federal and state regulations governing the management of
hazardous wastes. Some high volume utility wastes, such as fly ash and bottom
ash, are exempt from these regulations. We currently use almost all of our coal
fly ash and bottom ash as structural fill material in a manner approved by the
State of Maryland. We sell the remainder of the coal ash to the construction
industry for a number of approved uses.
The Federal Comprehensive Environmental Response, Compensation and
Liability Act (Superfund statute) establishes liability for the cleanup of
hazardous wastes that contaminate 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 the owner when the contamination occurred. Many states have implemented 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 us and seven
other defendants to recover past and future expenditures associated with the
cleanup of a site located at Kane and Lombard Streets in Baltimore. The State of
Maryland filed a similar complaint in the same case and court on February 12,
1990. The complaints alleged that we arranged for our fly ash to be deposited on
the site. The Court dismissed these complaints in November 1995. The Maryland
Department of the Environment began additional investigation on the remainder of
the site for the EPA, but never completed the investigation. We, along with
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, we cannot
estimate the total amount or our share of the site cleanup costs.
In the early 1970s, we 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 (hazardous chemicals frequently used as a fire-resistant coolant
in electrical equipment). On December 7, 1987, the EPA notified us and nine
other utilities that we are considered potentially responsible parties (PRPs)
with respect to the cleanup of the site. We, along with the other PRPs,
submitted a remedial investigation and feasibility study (RI/FS) to the EPA on
October 14, 1994. The estimated costs for the possible remedies range greatly
(from $15 million to $45 million). Until a specific remedy is chosen, we are not
able to predict the actual cleanup costs. Our share of the cleanup costs,
estimated to be approximately 15.79%, could be material.
From 1985 until 1989, we 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 us on
August 15, 1990, that we and approximately 1,000 other entities are PRPs with
respect to the cost of all remedial activities to be conducted at the site. The
PRPs have performed waste characterization, removed and disposed of all tanks
and drums of waste, and
18
completed a RI/FS at the site. Our share of the waste sent to this site is
estimated to be approximately 2.7%, but this may change as additional
information about the site is obtained. We have not determined the actual cost
of remedial activities. As a result of these factors, our potential liability
cannot be estimated. However, we do not expect such liability to be material.
On August 30, 1994, we were named as a defendant in UNITED STATES V.
KEYSTONE SANITATION COMPANY, ET AL. The litigation was instituted by the EPA and
involved contamination of the Keystone Sanitation Company landfill Superfund
site located in Adams County, Pennsylvania. In 1997, BGE and other defendants
entered into a settlement with the EPA for an immaterial amount but the court
has not yet approved the settlement.
In December 1995, we were notified by the EPA that we are one of
approximately 650 parties that may have incurred liability under the Superfund
statute for shipments of hazardous wastes to a site in Denver, Colorado known as
the RAMP Industries site. We, through our disposal vendor, shipped a small
amount of low level radioactive waste to the site between 1989 and 1992. The
site, which was found to have been operated improperly, was closed in 1994. That
same year, the EPA began a clean up of the site which will consist of removal of
drums of radioactive and hazardous mixed wastes. After the EPA completes its
drum removal phase of the clean up it will investigate potential soil and
groundwater contamination. Although our potential liability cannot be estimated,
we do not expect such liability to be material based on the limited amount of
waste we shipped to the site.
In September 1996, we received an information request from the EPA about
the Drumco Drum Dump Site, located in the Curtis Bay area of Maryland. This site
was the subject of an emergency drum removal action in 1991, due to a concern
about hazardous substances leaking from drums and posing a threat to human
health and the environment. According to EPA documents, approximately $2 million
dollars was spent on the drum removal action. To our knowledge, no long-term
remediation is planned for this site. In addition, we understand that the EPA
has sent information requests to approximately 17 other parties. Our records
indicate that we sold empty drums to Drumco, Inc. from approximately 1983-1990.
Although our potential liability cannot be estimated, we do not expect such
liability to be material based on our records showing that we sold only empty
storage drums to Drumco, Inc.
In April 1997, we received an information request from the EPA concerning
the 68th Street Dump Site, also known as the Robb Tyler Dump, located in
Baltimore, Maryland. This site is not currently listed as a federal Superfund
site. We understand that the EPA has sent information requests to over 70 other
parties. Our response to the EPA is that our records do not show that we sent
waste to the site. This response is based on reviewing all relevant documents
and interviewing employees involved in waste disposal for the Company from 1950
to 1975, which is the period covered by the EPA's inquiry. Although our
potential liability cannot be estimated, we do not expect such liability to be
material based on our records showing that we did not send waste to the site.
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. We are coordinating an investigation of these former
manufacturing sites, which includes reviewing possible actions to remove coal
tar. In late December 1996, we signed a consent order with the Maryland
Department of the Environment that requires us to implement remedial action
plans for contamination at and around the Spring Gardens site. We have submitted
the required remedial action plans and the Maryland Department of the
Environment is in the process of reviewing them. Based on several remedial
action options, the costs we consider to be probable to remedy the contamination
are estimated to total $50 million in nominal dollars (including inflation). We
have recorded these costs as a liability on our Consolidated Balance Sheet and
have deferred these costs, net of accumulated amortization and amounts we
recovered from insurance companies, as a regulatory asset (we discuss this
further in NOTE 5 TO CONSOLIDATED FINANCIAL STATEMENTS). We are also required by
accounting rules to disclose additional costs we consider to be less likely than
probable costs, but still "reasonably possible" of being incurred at these
sites. Because of the results of studies at these sites, it is reasonably
possible that these additional costs could exceed the amount we recognized by
approximately $48 million in nominal dollars ($11 million in current dollars,
plus the impact of inflation at 3.1% over a period of up to 60 years).
EMPLOYEES
As of December 31, 1997, we employed about 9,000 people.
19
ITEM 2. PROPERTIES
We describe our electric and gas business properties separately below.
ELECTRIC
Our principal electric generating plants are shown below:
GENERATION (MWH)
INSTALLED PRIMARY -------------------------
PLANT LOCATION CAPACITY (MW) FUEL 1997 1996
- ------------------------- ------------------------ ------------- ------------- ---------- ----------
(AT DECEMBER 31, 1997)
Steam
Calvert Cliffs Calvert County, MD 1,675 Nuclear 13,133,441 12,069,937
Brandon Shores Anne Arundel County, MD 1,296 Coal 8,483,339 8,849,357
Herbert A. Wagner Anne Arundel County, MD 1,006 Coal/Oil/Gas 3,399,601 3,149,334
Charles P. Crane Baltimore County, MD 385 Coal 1,942,621 2,000,992
Gould Street Baltimore City, MD 104 Oil 89,115 49,583
Riverside Baltimore County, MD 78 Oil/Gas 14,480 15,356
Jointly Owned -- Steam
Keystone Armstrong and 359(A) Coal 2,788,081 2,650,786
Indiana Counties, PA
Conemaugh Indiana County, PA 181(A) Coal 1,294,234 1,202,914
Combustion Turbine
Notch Cliff Baltimore County, MD 128 Gas 14,024 12,470
Perryman Harford County, MD 350 Oil/Gas 106,748 91,197
Westport Baltimore City, MD 121 Gas 10,236 6,420
Riverside Baltimore County, MD 173 Oil/Gas 8,197 5,450
Philadelphia Road Baltimore City, MD 64 Oil 3,391 1,829
Charles P. Crane Baltimore County, MD 14 Oil 960 707
Herbert A. Wagner Anne Arundel County, MD 14 Oil 754 513
----- ---------- ----------
Totals 5,948 31,289,222 30,106,845
===== ========== ==========
- ---------------
(A) These totals reflect BGE's proportionate interest and entitlement to
capacity from Keystone and Conemaugh, which are 2 megawatts of diesel
capacity for Keystone and 1 megawatt of diesel capacity for Conemaugh.
We also own two-thirds of the outstanding capital stock of Safe Harbor Water
Power Corporation, and are currently entitled to 277 megawatts of the rated
capacity of the Safe Harbor Hydroelectric Project. Safe Harbor is operated under
a Federal Energy Regulatory Commission license which expires in the year 2030.
GAS
We own the following propane air and liquefied natural gas facilities:
o a liquefied natural gas facility for the liquefication and storage
of natural gas with a total storage capacity of 1,000,000 DTH and
a planned daily capacity of 287,988 DTH, and
o a propane air facility with a mined cavern and refrigerated
storage facilities with a total storage capacity of 1,000,000 DTH
and a planned daily capacity of 85,000 DTH.
GENERAL INFORMATION
We own our principal plants and other important units that are located in
Maryland including our principal headquarters building in downtown Baltimore. We
also lease several properties in our service area which are used for various
offices and services. We have electric transmission and electric and gas
distribution lines located:
o in public streets and highways pursuant to franchises, and
o on permanent rights-of-way secured for the most part by grants
from owners of the property and for a relatively small part by
condemnation.
We share the ownership of the properties for the Keystone and Conemaugh
Plants in Pennsylvania. There are minor liens and easements on the Keystone and
Conemaugh properties, but these encumbrances do not materially interfere with
our use of the properties.
All of our property referred to above is subject to the lien of our
mortgage securing our mortgage bonds.
20
ITEM 3. LEGAL PROCEEDINGS
ASBESTOS
Since 1993, we have been involved in several actions concerning asbestos.
All of the actions together are 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 we knew of and
exposed individuals to an asbestos hazard. The actions relate to two types of
claims.
The first type are direct claims by individuals exposed to asbestos. We
described these claims in a Report on Form 8-K filed August 20, 1993. We are
involved in these claims with approximately 70 other defendants. Approximately
520 individuals that were never employees of the Company each claim $6 million
in damages ($2 million compensatory and $4 million punitive). We do not know the
specific facts necessary to estimate our potential liability for these claims.
The specific facts we do not know include:
o the identity of our facilities at which the plaintiffs allegedly
worked as contractors,
o the names of the plaintiffs' employers, and
o the date on which the exposure allegedly occurred.
In 1997, six of these cases were settled before trial for amounts that were
immaterial. Four more trials are currently scheduled -- two in 1998 and two in
1999.
The second type are claims by one manufacturer -- Pittsburgh Corning
Corp. -- against us and approximately eight others, as third party defendants.
These claims relate to approximately 1,500 individual plaintiffs. We do not know
the specific facts necessary to estimate our potential liability for these
claims. The specific facts we do not know include:
o the identity of our facilities containing asbestos manufactured by
the manufacturer,
o the relationship (if any) of each of the individual plaintiffs to us,
o the settlement amounts for any individual plaintiffs who are shown
to have had a relationship to us, and
o the dates on which/places at which the exposure allegedly occurred.
Until the relevant facts for both type claims are determined, we are unable
to estimate what our liability, if any, might be. Although insurance and hold
harmless agreements from contractors who employed the plaintiffs may cover a
portion of any awards in the actions, our potential liability could be material.
See ITEM 1. BUSINESS -- ELECTRIC RATE MATTERS, NUCLEAR OPERATIONS,
ENVIRONMENTAL MATTERS, and NOTE 12 TO CONSOLIDATED FINANCIAL STATEMENTS for
other information about our legal or regulatory proceedings.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF
SECURITY HOLDERS
Reference is made to the information set forth under Item 4. Submission of
Matters to a Vote of Security Holders on page 35 of our Quarterly Report on Form
10-Q for the quarter ended September 30, 1997.
21
ITEM 10. EXECUTIVE OFFICERS OF THE REGISTRANT
Executive Officers of BGE at the date of this report are:
OTHER OFFICES OR POSITIONS
NAME AGE PRESENT OFFICE HELD DURING PAST FIVE YEARS
- ------------------------ --- --------------------------------- -------------------------------------
Christian H. Poindexter 59 Chairman of the Board and Chairman of the Board and Chief
President (A) Executive Officer
(Since March 1, 1998) Vice Chairman of the Board
Edward A. Crooke 59 Vice Chairman of the Board and President, Chief Operating Officer,
Chairman of the Board - and Chairman of the Board - Subsidiaries
Subsidiaries (B) President, Utility Operations
(Since March 1, 1998)
Bruce M. Ambler 58 President and Chief Executive
Officer
Constellation Holdings, Inc.
(Since August 1, 1989)
Charles W. Shivery 52 President Vice President
Constellation Energy Solutions, Finance and Accounting,
Inc. and President Chief Financial Officer and
and Chief Executive Secretary
Officer Constellation Power Vice President and Treasurer,
Source, Inc. Corporate Finance Group
(Since February 25, 1997)
Robert E. Denton 55 Executive Vice President Senior Vice President, Generation
Generation Vice President, Nuclear Energy
(Since March 1, 1998) Plant General Manager, Calvert
Cliffs Nuclear Power Plant
Frank O. Heintz 53 Executive Vice President Vice President, Gas
Utility Operations and Vice Executive Director, LDC Caucus --
President Gas American Gas Association
(Since March 1, 1998) Chairman, Maryland Public Service
Commission
Thomas F. Brady 48 Vice President Vice President, Customer Service
Customer Service and and Accounting
Distribution Vice President, Accounting and
(Since July 1, 1993) Economics
David A. Brune 57 Vice President General Counsel
Finance and Accounting,
Chief Financial Officer and
Secretary
(Since February 25, 1997)
Charles H. Cruse 53 Vice President Plant General Manager, Calvert
Nuclear Energy Cliffs Nuclear Power Plant
(Since January 1, 1996) Manager, Nuclear Engineering
Carserlo Doyle 55 Vice President Manager, Telecommunications
Electric Interconnection Principal Engineer -- Electric
and Transmission Interconnection
(Since January 1, 1994)
Sharon S. Hostetter 53 Vice President Manager, Marketing
Marketing and Sales Division Manager, Resource
(Since November 1, 1995) Application and Customer
Development Group, Rochester
Gas and Electric Corporation
Ronald W. Lowman 53 Vice President Manager, Fossil Engineering
Fossil Energy Manager, Fossil Engineering
(Since January 1, 1993) Services
Gregory C. Martin 49 Vice President Manager, Customer Service
General Services Manager, Customer Accounts
(Since November 1, 1997)
22
OTHER OFFICES OR POSITIONS
NAME AGE PRESENT OFFICE HELD DURING PAST FIVE YEARS
- ------------------------ --- --------------------------------- --------------------------------------
Linda D. Miller 47 Vice President Manager, Employee Services
Management Services
(Since November 1, 1997)
Stephen F. Wood 45 President Vice President, Marketing and Sales
Constellation Energy Projects Manager, Major Customer Projects
& Services, Inc. Manager, System Engineering
(Since November 1, 1995) and Construction
Vice President Manager, Distribution Engineering
(Since February 16, 1996)
- ---------------
(A) Chief Executive Officer, Director, and member of the Executive Committee.
(B) Director and member of the Executive Committee.
Officers of BGE 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 director or officer and any other
person pursuant to which the director or officer was selected.
23
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
STOCK TRADING
Our common stock is traded under the ticker symbol BGE. It is listed on the
New York, Chicago, and Pacific stock exchanges. It has unlisted trading
privileges on the Boston, Cincinnati, and Philadelphia exchanges.
As of February 28, 1998, there were 72,972 common shareholders of record.
DIVIDEND POLICY
We pay dividends on our common stock when our Board of Directors declares
them. There is no limitation on our paying common stock dividends, other than we
must first pay all dividends (and any redemption payments) due on our preference
stock.
Dividends have been paid on the common stock continuously since 1910.
Future dividends depend upon future earnings, our financial condition and other
factors. Quarterly dividends were declared on the common stock during 1997 and
1996 in the amounts set forth below.
COMMON STOCK DIVIDENDS AND PRICE RANGES
1997 1996
----------------------------------------- ------------------------------------
PRICE* PRICE*
DIVIDEND ---------------------------- DIVIDEND --------------------------
DECLARED HIGH LOW DECLARED HIGH LOW
-------- ------------ ----------- -------- ---------- -----------
First Quarter................ $ .40 $28 $26 1/4 $ .39 $29 1/2 $26 1/8
Second Quarter............... .41 27 24 3/4 .40 28 5/8 25 1/2
Third Quarter................ .41 28 1/16 26 .40 28 5/8 25
Fourth Quarter............... .41 34 5/16 25 13/16 .40 28 3/4 25 3/4
----- -----
Total...................... $1.63 $1.59
===== =====
- ---------------
*Based on New York Stock Exchange Composite Transactions as reported in THE WALL
STREET JOURNAL.
24
Item 6. Selected Financial Data
Compound
1997 1996 1995 1994 1993 Growth
- -----------------------------------------------------------------------------------------------------------------------------------
(DOLLAR AMOUNTS IN MILLIONS, EXCEPT PER SHARE AMOUNTS) 5-Year 10-Year
SUMMARY OF OPERATIONS
Total Revenues $3,307.6 $3,153.2 $2,934.8 $2,783.0 $2,741.4 5.26% 5.47%
Expenses Other Than Interest and Income Taxes 2,584.0 2,483.7 2,239.1 2,147.7 2,125.0 5.00 6.22
---------------------------------------------------------------
Income From Operations 723.6 669.5 695.7 635.3 616.4 6.21 3.21
Other Income (Expense) (52.8) 6.1 8.8 32.3 20.3 -- --
---------------------------------------------------------------
Income Before Interest and Income Taxes 670.8 675.6 704.5 667.6 636.7 3.77 2.07
Net Interest Expense 230.0 198.5 197.0 190.1 188.8 3.93 7.10
---------------------------------------------------------------
Income Before Income Taxes 440.8 477.1 507.5 477.5 447.9 3.69 0.24
Income Taxes 158.0 166.3 169.5 153.9 138.1 8.87 1.94
---------------------------------------------------------------
Net Income 282.8 310.8 338.0 323.6 309.8 1.36 (0.59)
Preferred and Preference Stock Dividends 28.7 38.5 40.6 39.9 41.8 (7.42) 0.84
---------------------------------------------------------------
Earnings Applicable to Common Stock $ 254.1 $ 272.3 $ 297.4 $ 283.7 $ 268.0 2.73 (0.74)
- ---------------------------------------------------===============================================================
Earnings Per Share of Common Stock $1.72 $1.85 $2.02 $1.93 $1.85 1.08 (2.91)
Dividends Declared Per Share of Common Stock $1.63 $1.59 $1.55 $1.51 $1.47 2.65 2.69
Ratio of Earnings to Fixed Charges 2.78 3.10 3.21 3.14 3.00 0.96 (3.97)
Ratio of Earnings to Fixed Charges and Preferred
and Preference Stock Dividends Combined 2.35 2.44 2.52 2.47 2.34 2.47 (3.22)
FINANCIAL STATISTICS AT YEAR END
Total Assets $8,773.4 $8,544.3 $8,277.6 $7,995.9 $7,829.6 4.01 6.26
- ---------------------------------------------------===============================================================
Capitalization
Long-term debt $2,988.9 $2,758.8 $2,598.2 $2,584.9 $2,823.1 4.69 5.76
Preferred stock -- -- 59.2 59.2 59.2 -- --
Redeemable preference stock 90.0 134.5 242.0 279.5 342.5 (25.63) (7.02)
Preference stock not subject to mandatory
redemption 210.0 210.0 210.0 150.0 150.0 13.81 6.68
Common shareholders' equity 2,870.4 2,854.7 2,811.2 2,719.0 2,620.5 2.52 5.04
---------------------------------------------------------------
Total Capitalization $6,159.3 $5,958.0 $5,920.6 $5,792.6 $5,995.3 2.38 4.90
- ---------------------------------------------------===============================================================
Book Value Per Share of Common Stock $19.44 $19.33 $19.06 $18.43 $17.94 1.97 2.74
Number of Common Shareholders (IN THOUSANDS) 73.7 77.6 79.8 81.5 82.3 (1.73) (1.10)
CERTAIN PRIOR-YEAR AMOUNTS HAVE BEEN RECLASSIFIED TO CONFORM WITH THE CURRENT
YEAR'S PRESENTATION.
Baltimore Gas and Electric Company and Subsidiaries 25
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations
Introduction
In Management's Discussion and Analysis we explain the general financial
condition and the results of operations for BGE and its diversified business
subsidiaries including:
o what factors affect our businesses,
o what our earnings and costs were in 1997 and 1996,
o why earnings and costs changed from the year before,
o where our earnings came from,
o how all of this affects our overall financial condition,
o what our expenditures for capital projects were in 1995
through 1997 and what we expect them to be in 1998
through 2000, and
o where we will get cash for future capital expenditures.
As you read Management's Discussion and Analysis, it may be helpful to refer to
our Consolidated Statements of Income on page 38, which present the results of
our operations for 1997, 1996, and 1995. In Management's Discussion and
Analysis, we analyze and explain the annual changes in the specific line items
in the Consolidated Statements of Income. Our analysis may be important to you
in making decisions about your investments in BGE.
The electric utility industry is undergoing rapid and substantial change.
Competition in the generation part of our business is increasing. The regulatory
environment (federal and state) is shifting toward customer choice. These
matters are discussed briefly in the "Competition and Response to Regulatory
Change" section beginning on page 27. They are discussed in detail in this
Annual Report on Form 10-K.
We continuously evaluate changes in the utility industry. Based on the
evaluations, we refine short and long term business plans. We may also enter new
businesses, which may be opportunities to:
o provide our core energy business customers more services, or
o attract new customers for our core energy business, or
o expand our diversified stream of revenues.
________________________________________________________________________________
Results of Operations
In this section, we discuss our 1997 and 1996 earnings and the factors affecting
them. We begin with a general overview, then separately discuss earnings for the
utility business and for diversified businesses.
Overview
Total Earnings per Share of Common Stock
1997 1996 1995
- -------------------------------------------------------------------
Earnings per share from
current-year operations:
Utility business $1.94 $1.96 $1.84
Diversified businesses (subsidiaries) .34 .31 .18
----------------------
Total earnings per share from
current-year operations 2.28 2.27 2.02
Write-off of merger costs (see Note 12) (.25) -- --
Write-downs of real estate
investments (see Note 12) (.31) -- --
Disallowed replacement
energy costs (see Note 12) -- (.42) --
----------------------
Total earnings per share $1.72 $1.85 $2.02
- ---------------------------------------------======================
1997
Our 1997 total earnings decreased $18.2 million, or $.13 per share, from 1996.
Our total earnings decreased because:
o we wrote off costs associated with the proposed merger
with Potomac Electric Power Company, and
o Constellation Holdings, Inc. and Subsidiaries (together
known as the Constellation Holdings Companies) wrote down
their investments in two real estate projects.
We discuss the write-off of merger costs in the "Write-Off of Merger Costs"
section on page 31, and the real estate write-downs in the "Real Estate
Development and Senior-Living Facilities" section on page 33.
In 1997, utility earnings from current-year operations were lower mostly because
we sold less electricity and gas due to milder weather (people use less
electricity and gas to heat or cool their homes in milder weather). We discuss
our utility earnings in more detail in the "Utility Business" section beginning
on page 27.
In 1997, diversified business earnings from current-year operations were higher
mostly because the Constellation Holdings Companies had higher earnings from
power generation projects and financial investments. We discuss our diversified
business earnings in more detail in the "Diversified Businesses" section
beginning on page 32.
1996
Our 1996 total earnings decreased $25.1 million, or $.17 per share, from 1995.
Our total earnings decreased because we wrote off disallowed replacement energy
costs. We discuss this in detail in the "Disallowed Replacement Energy Costs"
section on page 29.
In 1996, utility earnings from operations were higher due to three factors: we
sold more electricity and gas due to colder winter weather, there was an
increase in the number of customers, and we had lower operations and maintenance
expenses. We would have had even higher utility earnings from operations except
we sold less electricity in the third quarter due to milder summer weather.
In 1996, diversified business earnings were higher mostly because the
Constellation Holdings Companies had higher earnings from power generation
projects and financial investments.
26 Baltimore Gas and Electric Company and Subsidiaries
Utility Business
Before we go into the details of our electric and gas operations, we believe it
is important to discuss four factors that have a strong influence on our utility
business performance: regulation, the weather, other factors including the
condition of the economy in our service territory, and competition.
Regulation by the Maryland Public Service Commission
(Maryland PSC)
The Maryland PSC determines the rates we can charge our customers. Our rates
consist of a "base rate" and a "fuel rate." The base rate is the rate the
Maryland PSC allows us to charge our customers for the cost of providing them
service, plus a profit. We have both an electric base rate and a gas base rate.
Higher electric base rates apply during the summer when the demand for
electricity is the highest. Gas base rates are not affected by seasonal changes.
The Maryland PSC allows us to include in base rates a
component to recover money spent on conservation programs. This component is
called an "energy conservation surcharge." However, under this surcharge the
Maryland PSC limits what our profit can be. If, at the end of the year, we have
exceeded our allowed profit, we lower the amount of future surcharges to our
customers to correct the amount of overage, plus interest.
In addition, we charge our electric customers separately for the fuel we use to
generate electricity (nuclear fuel, coal, gas, or oil) and for the net cost of
purchases and sales of electricity (primarily with other utilities). We charge
the actual cost of these items to the customer with no profit to us. We discuss
this in more detail in the "Electric Fuel Rate Clause" section on page 29 and in
Note 1.
We also charge our gas customers separately for the natural gas they consume.
The price we charge for the natural gas is based on a market based rates
incentive mechanism approved by the Maryland PSC. We discuss market based rates
in more detail in the "Gas Cost Adjustments" section on page 30 and in Note 1.
From time to time, when necessary to cover increased costs, we ask the Maryland
PSC for base rate increases. The Maryland PSC holds hearings to determine
whether to grant us all or a portion of the amount requested. The Maryland PSC
has historically allowed us to increase base rates to recover costs for
replacing utility plant assets, plus a profit, beginning at the time of
replacement. Generally, rate increases improve our utility earnings because they
allow us to collect more revenue. However, rate increases are normally granted
based on historical data and those increases may not always keep pace with
increasing costs.
Weather
Weather affects the demand for electricity and gas, especially among our
residential customers. Very hot summers and very cold winters increase demand.
Mild weather reduces demand.
We measure the weather's effect using "degree days." A degree day is the
difference between the average daily actual temperature and a baseline
temperature of 65 degrees. Cooling degree days result when the daily actual
temperature exceeds the 65 degree baseline. Heating degree days result when the
daily actual temperature is less than the baseline.
During the cooling season, hotter weather is measured by more cooling degree
days and results in greater demand for electricity to operate cooling systems.
During the heating season, colder weather is measured by more heating degree
days and results in greater demand for electricity and gas to operate heating
systems.
We show the number of cooling and heating degree days in 1997 and 1996, the
percentage changes in the number of degree days from prior years, and the number
of degree days in a "normal" year as represented by the 30-year average in the
following table.
30-Year
1997 1996 Average
- ------------------------------------------------------------------
Cooling degree days 746 786 804
Percentage change from prior year (5.1)% (25.6)%
Heating degree days 4,822 5,138 4,901
Percentage change from prior year (6.2)% 11.7%
Other Factors
Other factors, aside from weather, impact the demand for electricity and gas.
These factors include the "number of customers" and "usage per customer" during
a given period. We use these terms later in our discussions of electric and gas
operations. In those sections, we discuss how these and other factors affected
electric and gas sales during 1997 and 1996.
The number of customers in a given period is affected by new home and apartment
construction and by the number of businesses in our service territory.
Usage per customer refers to all other items impacting customer sales which
cannot be separately measured. These factors include the strength of the economy
in our service territory. When the economy is healthy and expanding, customers
tend to consume more electricity and gas. Conversely, during an economic
downtrend, our customers tend to consume less electricity and gas.
Competition and Response to Regulatory Change Our electric and gas businesses
are also affected by competition. We discuss competition in each business below.
Electric Business
Electric utilities are facing competition on various fronts, including:
o in the construction of generating units to meet increased
demand for electricity,
o in the sale of their electricity in the bulk power markets,
o in competing with alternative energy suppliers, and
o in the future, for electric sales to retail customers which
utilities now serve exclusively.
We regularly reevaluate our strategies with two goals in mind: to improve our
competitive position, and to anticipate and adapt to regulatory changes. We
cannot predict the ultimate effect competition or regulatory change will have on
our earnings.
We discuss competition in our electric business in more detail in this Annual
Report on Form 10-K under the heading "Electric Regulatory Matters and
Competition."
Baltimore Gas and Electric Company and Subsidiaries 27
Gas Business
Regulatory change in the natural gas industry is well under way. We discuss
competition in our gas business in more detail in this Annual Report on Form
10-K under the heading "Gas Regulatory Matters and Competition."
Strategies
We will continue to develop strategies to keep us competitive. These strategies
might include one or more of the following:
o the complete or partial separation of our generation,
transmission, and distribution functions,
o purchase or sale of generation assets,
o mergers or acquisitions of utility or non-utility businesses,
o spin-off or sale of one or more businesses,
o growth of revenues from diversified businesses.
We cannot predict whether any transactions of the types described above may
actually occur, nor can we predict what their effect on our financial condition
or competitive position might be.
Utility Business Earnings per Share of Common Stock
1997 1996 1995
- --------------------------------------------------------------------
Utility earnings per share from
current-year operations:
Electric business $1.77 $1.75 $1.70
Gas business .17 .21 .14
----------------------------
Total utility earnings per share
from current-year operations 1.94 1.96 1.84
Write-off of merger costs (see
Note 12) (.25) -- --
Disallowed replacement
energy costs (see Note 12) -- (.42) --
----------------------------
Total utility earnings per share $1.69 $1.54 $1.84
- ----------------------------------------============================
Our 1997 total utility earnings increased $24.0 million, or $.15 per share, from
1996. Our 1996 total utility earnings decreased $44.5 million, or $.30 per
share, from 1995. We discuss the factors affecting utility earnings below.
Electric Operations
Electric Revenues
The changes in electric revenues in 1997 and 1996 compared to the respective
prior year were caused by:
1997 1996
- ------------------------------------------------------------------
(IN MILLIONS)
Electric system sales volumes $(15.5) $ 0.3
Base rates 29.2 (2.5)
Fuel rates (4.3) (12.3)
----------------------
Total change in electric revenues
from electric system sales 9.4 (14.5)
Interchange and other sales (23.2) (11.1)
Other (3.2) 4.5
----------------------
Total change in electric revenues $(17.0) $(21.1)
- --------------------------------------------======================
Electric System Sales Volumes
"Electric system sales" are sales to customers in our service territory at rates
set by the Maryland PSC. These sales do not include interchange sales and sales
to others.
The percentage changes in our electric system sales volumes, by type of
customer, in 1997 and 1996 compared to the respective prior year were:
1997 1996
- ------------------------------------------------------------------
Residential (3.9)% 2.5%
Commercial 1.0 (0.3)
Industrial (0.4) 0.1
In 1997, we sold less electricity to residential customers mostly for two
reasons: lower electricity usage per customer and milder weather. We sold more
electricity to commercial customers mostly because usage per customer increased.
We would have sold even more electricity to commercial customers except for
milder weather during the year. We sold about the same amount of electricity to
industrial customers as we did in 1996.
In 1996, we sold more electricity to residential customers for three reasons:
colder weather in the first quarter, greater electricity usage per customer, and
an increase in the number of customers. We would have sold even more electricity
to residential customers except for milder summer weather. We sold about the
same amount of electricity to commercial and industrial customers as we did in
1995.
Weather impacts residential, more than commercial and industrial, sales. In 1997
and 1996, other items offset the impact of weather on commercial and industrial
sales. Other items included the demand for power to fuel manufacturing equipment
and office machinery, which vary with changes in the customers' businesses.
Base Rates
In 1997, base rate revenues were higher than they were in 1996 because of higher
energy conservation surcharge revenues. During 1996, we exceeded our profit
limit under the energy conservation surcharge. As a result, we excluded $28.5
million of our 1996 surcharge billings from revenue. To correct the overage, we
lowered the surcharge on our customers' bills beginning in July 1997 and will
continue to bill the lower surcharge through June 1998.
In 1996, base rate revenues were about the same as they were in 1995. Although
we sold more electricity in 1996, our revenues did not increase because the
higher sales occurred during the winter when our base rates are lower.
28 Baltimore Gas and Electric Company and Subsidiaries
Fuel Rates
The fuel rate is the rate the Maryland PSC allows us to charge our customers,
with no profit to us, for:
o our actual cost of fuel used to generate electricity, and
o the net cost of purchases and sales of electricity (primarily
with other utilities).
If these costs go up, the Maryland PSC permits us to increase the fuel rate. If
these costs go down, our customers benefit from a reduction in the fuel rate.
The fuel rate is impacted most by the amount of electricity generated at our
Calvert Cliffs Nuclear Power Plant (Calvert Cliffs) because the cost of nuclear
fuel is cheaper than coal, gas, or oil. We discuss the calculation of the fuel
rate in Note 1.
Changes in the fuel rate normally do not affect earnings. However, if the
Maryland PSC disallows recovery of any part of the fuel costs, our earnings are
reduced. We discuss this more thoroughly in the "Disallowed Replacement Energy
Costs" section below and in Note 12.
In 1997, fuel rate revenues decreased mostly because we sold less electricity.
In 1996, fuel rate revenues decreased due to a lower fuel rate because we were
able to operate plants with the lowest fuel costs. Fuel rate revenues would have
been even lower except we sold more electricity.
Interchange and Other Sales
"Interchange and other sales" are sales in the Pennsylvania-New Jersey-Maryland
Interconnection (PJM) energy market and to others. PJM is a regional power pool
with members that include many wholesale market participants, as well as BGE and
seven other utility companies. We sell energy to PJM members and to others after
we have satisfied the demand for electricity in our own system.
In 1997, we had lower interchange and other sales compared to 1996 mostly
because of lower sales volumes due to reduced demand.
In 1996, we had lower interchange and other sales compared to 1995 because we
generated less electricity at Calvert Cliffs. This meant that we had less
electricity to sell outside of our service territory. We generated less
electricity at that plant mostly because the 1996 outage for regular refueling
and maintenance took longer than in 1995.
Electric Fuel and Purchased Energy Expenses
1997 1996 1995
- ------------------------------------------------------------------
(IN MILLIONS)
Actual costs $504.5 $539.2 $554.5
Net recovery of costs
under electric fuel
rate clause (see Note 1) 15.2 8.2 24.3
Disallowed replacement energy
costs (including carrying
charges) (see Note 12) -- 95.4 --
-------------------------------
Total electric fuel and
purchased energy expenses $519.7 $642.8 $578.8
- -----------------------------------===============================
Actual Costs
In 1997, our actual costs of fuel to generate electricity (nuclear fuel, coal,
gas, or oil) and electricity we bought from others were lower than in 1996
mostly for two reasons: we bought less electricity from other utilities because
we were able to meet demand using the electricity we generated, and we were able
to use a less-costly mix of generating plants mostly because of shorter
refueling and maintenance downtime at Calvert Cliffs.
In 1996, our actual costs were lower than in 1995 because the price of
electricity and capacity we bought from other utilities was lower and we sold
less electricity. The price we pay for electricity and capacity we buy from
other utilities changes based on market conditions, complex pricing formulas for
PJM transactions, and contract terms.
Electric Fuel Rate Clause
Under the electric fuel rate clause, we defer (include as an asset or liability
in our Consolidated Balance Sheets and exclude from our Consolidated Statements
of Income) the difference between our actual costs of fuel and energy and what
we collect from customers under the fuel rate in a given period. We either bill
or refund our customers that difference in the future. We discuss the
calculation of the fuel rate in Note 1.
In 1997 and 1996, our actual costs of fuel and energy were lower than the fuel
rate revenues we collected from our customers.
Disallowed Replacement Energy Costs
In December 1996, we settled fuel rate proceedings about extended outages that
occurred at Calvert Cliffs in 1989 through 1991. We agreed not to bill our
customers for $118 million of electric replacement energy costs associated with
these outages. We wrote off a portion of these costs in 1990 and wrote off the
remainder in 1996. We discuss this further in Note 12.
Baltimore Gas and Electric Company and Subsidiaries 29
Gas Operations
Gas Revenues
The changes in gas revenues in 1997 and 1996 compared to the respective prior
year were caused by:
1997 1996
- ------------------------------------------------------------------
(IN MILLIONS)
Gas system sales volumes $(7.3) $ 8.2
Base rates 0.6 18.9
Gas cost adjustments (0.2) 62.1
----------------------
Total change in gas revenues
from gas system sales (6.9) 89.2
Off-system sales 10.9 26.6
Other 0.3 1.0
----------------------
Total change in gas revenues $ 4.3 $116.8
- --------------------------------------------======================
Gas System Sales Volumes
The percentage changes in our gas system sales volumes, by type of customer, in
1997 and 1996 compared to the respective prior year were:
1997 1996
- ---------------------------------------------------------------
Residential (8.3)% 8.9%
Commercial (0.2) 2.8
Industrial 4.4 (2.3)
In 1997, we sold less gas to residential customers mostly for two reasons: lower
usage per customer and milder weather. We sold about the same amount of gas to
commercial customers as we did in 1996. We sold more gas to industrial customers
mostly because the milder weather caused fewer service interruptions and
Bethlehem Steel (our largest customer) used more gas. We would have sold even
more gas to industrial customers except gas usage by industrial customers other
than Bethlehem Steel decreased.
In 1996, we sold more gas to residential and commercial customers due to colder
winter and early spring weather and an increase in the number of customers. We
would have sold even more gas to those customers except that gas usage per
customer decreased. We sold less gas to industrial customers because Bethlehem
Steel used less gas. We would have sold even less gas to industrial customers
except for increased gas usage by other industrial customers, an increase in the
number of customers, and colder winter weather.
Base Rates
In 1997, base rate revenues were higher than they were in 1996. Although we sold
less gas in 1997, our base rate revenues increased because of a higher energy
conservation surcharge in the last six months of the year.
In 1996, base rate revenues were higher than in 1995 because in November 1995,
the Maryland PSC allowed us to increase our gas base rates. This increased our
annual base rate revenues for 1996 by $19.3 million. That amount included $2.4
million to recover higher depreciation expense (an accounting procedure which
spreads the cost of utility plant in service over the years in which it is
used).
During 1997, we applied for a $36.7 million increase in our gas base rates. The
Maryland PSC is currently reviewing our application, and is expected to issue an
order by June 1998. Our earnings will be impacted during 1998 and 1999 by the
outcome of this case.
Gas Cost Adjustments
We charge our gas customers for the natural gas they consume using gas cost
adjustment clauses set by the Maryland PSC. These clauses operate similar to the
electric fuel rate clause described in the "Electric Fuel Rate Clause" section
on page 29.
However, effective October 1996, the Maryland PSC approved a modification of
these clauses to provide a market based rates incentive mechanism. Under market
based rates, our actual cost of gas is compared to a market index (a measure of
the market price of gas in a given period). The difference between our actual
cost and the market index is shared equally between BGE (which benefits
shareholders) and customers. We also discuss this in Note 1.
Delivery service customers, including Bethlehem Steel, are not subject to the
gas cost adjustment clauses because we are not selling them gas (we are selling
them the service of delivering their gas).
In 1997, gas cost revenues decreased mostly because we sold less gas. In 1996,
gas cost revenues increased because we had to pay more for gas and we sold more
gas.
Off-System Sales
Off-system gas sales, which are low-margin direct sales to wholesale suppliers
of natural gas outside our service territory, are not subject to gas cost
adjustments. We began sales of off-system gas during the first quarter of 1996.
The Maryland PSC approved an arrangement for part of the earnings from
off-system sales to benefit customers (through reduced costs) and the remainder
to be retained by BGE (which benefits shareholders).
In 1997 and 1996, off-system gas sales increased mostly because we first began
off-system sales of gas in February of 1996. These increases in off-system sales
did not significantly impact earnings.
Gas Purchased For Resale Expenses
1997 1996 1995
- -----------------------------------------------------------------
(IN MILLIONS)
Actual costs $291.6 $295.4 $205.9
Net recovery (deferral) of
costs under gas adjustment
clauses (see Note 1) 0.5 (11.0) (7.8)
-------------------------------
Total gas purchased for
resale expenses $292.1 $284.4 $198.1
- ----------------------------------===============================
Actual Costs
Actual costs include the cost of gas purchased for resale to our customers and
for sale off-system. Actual costs do not include the cost of gas purchased by
delivery service customers, including Bethlehem Steel.
In 1997, actual gas costs decreased from 1996 mostly because we sold less gas.
In 1996, actual gas costs increased from 1995 due to three factors: higher
market prices of gas, higher sales volumes, and the purchase of gas to resell
off-system (beginning in the first quarter of 1996).
30 Baltimore Gas and Electric Company and Subsidiaries
Gas Adjustment Clauses
We charge customers for the cost of gas sold through gas adjustment clauses
(determined by the Maryland PSC), as discussed under "Gas Cost Adjustments"
earlier in this section.
In 1997, the portion of our actual gas costs subject to these clauses was lower
than the revenues we collected from our customers. In 1996, the portion of our
actual gas costs subject to these clauses was higher than the revenues we
collected from our customers.
Other Operating Expenses
Operations and Maintenance Expenses
In 1997, our operations and maintenance expenses were slightly lower than they
were in 1996.
In 1996, our operations and maintenance expenses decreased $18.5 million due to
our continued efforts to control costs. This decrease would have been even
greater except we had higher costs to maintain our nuclear plant.
Depreciation and Amortization Expenses
We describe depreciation and amortization expenses in Note 1.
In 1997, our depreciation and amortization expense increased $12.7 million from
1996 mostly because we had more plant in service (as our level of plant that is
in service changes, the amount of our depreciation and amortization expense
changes).
In 1996, our depreciation and amortization expense increased $12.8 million from
1995 because we had more utility plant in service, and we had more energy
conservation program costs to be amortized.
The increase in 1996 expenses would have been even greater except that in 1995
depreciation and amortization expense included $14.2 million for the write-off
of costs associated with planned future generation facilities at our Perryman
site that will not be built. We discuss this write-off also in Note 1. In 1996,
depreciation and amortization expense did not include any such write-off.
Taxes Other Than Income Taxes
In 1997, taxes other than income taxes were about the same as they were in 1996.
In 1996, taxes other than income taxes were $9.6 million higher than in 1995
mostly due to three factors: plant additions made in 1995 increased our property
taxes about $7 million, higher 1996 revenues increased our gross receipts taxes
about $2 million, and higher labor costs increased our payroll taxes about $1
million.
Other Income and Expenses
Write-Off of Merger Costs
In September 1995 we signed an agreement with Potomac Electric Power Company to
merge together into a new company, Constellation Energy(TM) Corporation, after
all necessary regulatory approvals were received. In December 1997, both
companies mutually terminated the merger agreement. Accordingly, in 1997, we
wrote off $57.9 million of costs related to the merger. This write-off reduced
after-tax earnings by $37.5 million, or $.25 per share. We also discuss the
write-off of these costs in Note 12.
Allowance for Funds Used During Construction (AFC)
We finance construction projects with borrowed funds and equity funds. We are
allowed by the Maryland PSC to record the cost of these funds as part of the
cost of construction projects in our Consolidated Balance Sheets. We do this
through the AFC, which we calculate using a rate authorized by the Maryland PSC.
We bill our customers for the AFC plus a return after the utility plant is
placed in service. We also describe AFC in Note 1.
In 1997, AFC was about the same as it was in 1996. In 1996, we had lower AFC
compared to 1995 because we completed several projects and started less new
construction. We also had lower AFC because the Maryland PSC decreased the gas
AFC rate in November 1995 from 9.40% to 9.04%.
Net Other Income and Deductions
Net other income and deductions represent miscellaneous income and expenses
which are not directly related to operations.
In 1997, net other income and deductions were about the same as they were in
1996. In 1996, net other income and deductions increased $4.9 million compared
to 1995 mostly because the Constellation Holdings Companies had lower deductions
not directly related to operations and BGE had about $2 million more of other
interest and finance charge income.
Interest Charges
Interest charges represent the interest we paid on outstanding debt.
In 1997, we had $23.6 million higher interest charges compared to 1996 because
we had more debt outstanding and interest rates were higher.
In 1996, we had $2.1 million lower interest charges compared to 1995 largely
because of lower interest rates. We would have had even lower interest charges
except we had more debt outstanding.
Income Taxes
In 1997 our income taxes decreased because we had lower taxable income from both
our utility operations and our diversified businesses.
In 1996 our income taxes decreased because we had lower taxable income from
utility operations. Our income taxes would have been even lower except that we
had higher taxable income from our diversified businesses.
Baltimore Gas and Electric Company and Subsidiaries 31
Diversified Businesses
In the 1980s, we began to diversify our business in response to limited growth
in gas and electric sales. Today, we continue to diversify our business in
response to regulatory changes in the utility industry. Some of our diversified
businesses are related to our core utility business and others are not. Our
diversified businesses are organized in three groups:
o the Constellation Holdings Companies--our power generation,
financial investments, and real estate businesses,
o Constellation Energy Solutions, Inc. and Subsidiaries--our
energy marketing businesses, and
o BGE Home Products & Services, Inc. and Subsidiaries--our
home products and commercial building systems businesses.
Diversified Business Earnings Per Share of Common Stock
1997 1996 1995
- -------------------------------------------------------------------
Constellation Holdings Companies $ .39 $ .29 $ .18
Constellation Energy Solutions (.08) .00 .00
BGE Home Products & Services .03 .02 .00
-------------------------
Total diversified business earnings per
share from current-year operations .34 .31 .18
Write-downs of real estate investments
by the Constellation Holdings
Companies (see Note 12) (.31) -- --
-------------------------
Total diversified business
earnings per share $ .03 $ .31 $ .18
- ------------------------------------------=========================
Our 1997 diversified business earnings decreased $42.2 million, or $.28 per
share, from 1996. Our 1996 diversified business earnings increased $19.3
million, or $.13 per share, from 1995. These changes came mostly from the
Constellation Holdings Companies. We discuss factors affecting the earnings of
our diversified businesses below.
The Constellation Holdings Companies--Our Power Generation, Financial
Investments, and Real Estate Businesses
The Constellation Holdings Companies:
o develop, own, and operate power generation projects,
o engage in financial investments, and
o develop, own, and manage real estate and senior-living facilities.
Earnings per share from the Constellation Holdings Companies were:
1997 1996 1995
- --------------------------------------------------------------------
Power generation $ .25 $ .18 $ .13
Financial investments .18 .14 .08
Real estate development and
senior-living facilities (.01) (.02) (.02)
Other (.03) (.01) (.01)
--------------------------
Total Constellation Holdings Companies'
earnings per share from
current-year operations .39 .29 .18
Write-downs of real estate
investments (see Note 12) (.31) -- --
--------------------------
Total Constellation Holdings Companies'
earnings per share $ .08 $ .29 $ .18
- ------------------------------------------==========================
Power Generation
The Constellation Holdings Companies' power generation business develops, owns,
and operates domestic and international power generation projects. We discuss
international projects later in this section.
In 1997, earnings increased from 1996 mostly because of improved performance of
various energy projects.
In 1996, earnings increased from 1995 mostly due to our share of higher earnings
from energy projects and a $14.6 million after-tax gain on the sale by a
Constellation partnership of a power purchase agreement with Jersey Central
Power & Light Company back to that utility. Energy projects had higher earnings
for a variety of reasons--some ongoing (like improved efficiency due to
equipment or procedure changes) and some onetime (for example, losses incurred
in 1995--to shut-down certain operations at a plant--did not occur again in
1996). These increases were offset by $16.2 million of write-offs of investments
in certain power projects. We describe these write-offs further in Note 3.
California Power Purchase Agreements
The Constellation Holdings Companies have $261 million invested in 16 projects
that sell electricity in California under power purchase agreements called
"Interim Standard Offer No. 4" agreements. Earnings from these projects were
$37.3 million, or $.25 per share, in 1997.
Under these agreements, the electricity rates change from fixed rates to
variable rates during 1996 through 2000. The projects which already have had
rate changes have lower revenues under variable rates than they did under fixed
rates. When the remaining projects transition to variable rates, we expect their
revenues also to be lower than they are under fixed rates. However, the
California projects that make the highest revenues will transition in 1999 and
2000. As a result, we do not expect the Constellation Holdings Companies to have
significantly lower earnings before 2000 due to the transition to variable
rates. We cannot predict the financial effects of the transition from fixed to
variable rates on the Constellation Holdings Companies or on BGE, but the
effects could be material.
We describe these projects and the transition process in detail in Note 12.
International
The Constellation Holdings Companies' power generation business in Latin
America:
o develops, acquires, owns, and operates power generation projects, and
o acquires and owns distribution systems.
At December 31, 1997, the Constellation Holdings Companies had invested about
$23.1 million and committed another $4.3 million in power projects in Latin
America. In the future, the Constellation Holdings Companies' power generation
business may be expanding further in both domestic and international projects.
32 Baltimore Gas and Electric Company and Subsidiaries
Financial Investments
Earnings from the Constellation Holdings Companies' portfolio of financial
investments include income from:
o marketable securities,
o financial limited partnerships, and
o financial guaranty insurance companies.
In 1997, earnings were higher than in 1996 due to better earnings from trading
securities, and increased gains from marketable securities.
In 1996, earnings were higher than in 1995 because of better earnings from
marketable securities and increased gains from financial limited partnerships.
Real Estate Development and Senior-Living Facilities
The Constellation Holdings Companies' real estate development business includes:
o land under development,
o office buildings,
o retail projects,
o distribution facility projects,
o an entertainment, dining, and retail complex in Orlando, Florida,
o a mixed-use planned-unit development, and n senior-living facilities.
In 1997, earnings from real estate development and senior-living facilities were
lower than in 1996 mostly due to:
o a $14.1 million after-tax write-down of the investment in Church Street
Station--an entertainment, dining, and retail complex in Orlando, Florida--
which occurred because the Constellation Holdings Companies have now
decided to sell rather than keep the project, and
o a $31.9 million after-tax write-down of the investment in Piney Orchard--a
mixed-use, planned-unit development-- which occurred because the expected
cash flow from the project was less than the Constellation Holdings
Companies' investment in the project.
In 1996, earnings from real estate development and senior-living facilities were
about the same as they were in 1995.
We consider market demand, interest rates, the availability of financing, and
the strength of the economy in general when making decisions about our real
estate investments. If we were to sell our real estate projects in the current
market, we would have losses, although the amount of the losses is hard to
predict. Depending on market conditions in the future, we could also have losses
on any future sales.
We describe the Constellation Holdings Companies' real estate business further
in Note 12.
Constellation Energy Solutions, Inc. and Subsidiaries--
Our Energy Marketing Businesses
Our energy marketing businesses:
o provide power marketing and risk management services to wholesale customers
in North America by purchasing and selling electric power, other energy
commodities, and related derivatives,
o provide natural gas brokering and related services for
wholesale and retail customers, and
o provide a broad range of customized energy services, including private
electric and gas distribution systems, energy consulting, power quality
services, and campus and multi-building energy systems.
In 1997, earnings from our energy marketing businesses were lower than in 1996
mostly because of lower gas brokering margins and increased uncollectible
expense. In 1996, earnings were about the same as they were in 1995.
BGE Home Products & Services, Inc. and
Subsidiaries--Our Home Products and
Commercial Building Systems Businesses
BGE Home Products & Services, Inc. and subsidiaries:
o sells and services electric and gas appliances,
o engages in home improvements, and
o sells and services heating and air conditioning systems.
In 1997 and 1996, earnings increased due to improved performance in the service
and installation business.
Baltimore Gas and Electric Company and Subsidiaries 33
Liquidity and Capital Resources
Overview
Our business requires a great deal of capital. Our actual capital requirements
for the years 1995 through 1997, along with estimated amounts for the years 1998
through 2000, are shown below.
1995 1996 1997 1998 1999 2000
- ---------------------------------------------------------------------------------------------------------------------------------
(IN MILLIONS)
Utility Business Capital Requirements:
Construction expenditures (excluding AFC)
Electric $223 $219 $238 $236 $ 260 $ 273
Gas 70 84 89 77 76 72
Common 51 46 38 34 27 24
--------------------------------------------------------------
Total construction expenditures 344 349 365 347 363 369
AFC 22 10 8 8 11 14
Nuclear fuel (uranium purchases and processing charges) 46 47 44 50 50 48
Deferred energy conservation expenditures 46 31 27 12 10 10
Retirement of long-term debt and redemption of preference stock 279 184 243 117 344 264
--------------------------------------------------------------
Total utility business capital requirements 737 621 687 534 778 705
Diversified Business Capital Requirements:
Investment requirements 118 118 156 169 134 157
Retirement of long-term debt 55 52 188 164 137 246
--------------------------------------------------------------
Total diversified business capital requirements 173 170 344 333 271 403
Total capital requirements $910 $791 $1,031 $867 $1,049 $1,108
- -------------------------------------------------------------------==============================================================
Capital Requirements of Our Utility Business
We continuously review and change our construction program, so actual
expenditures may vary from the estimates for the years 1998 through 2000 in the
capital requirements chart.
Our projections of future electric construction expenditures do not include
costs to build more generating units. Electric construction expenditures include
improvements to our generating plants and transmission and distribution
facilities. They also include estimated costs for replacing the steam generators
and extending the operating licenses at Calvert Cliffs. The operating licenses
expire in 2014 for Unit 1 and in 2016 for Unit 2. We estimate these Calvert
Cliffs costs to be:
o $27 million in 1998,
o $38 million in 1999, and
o $44 million in 2000.
We estimate that during the three-year period 2001 through 2003, we will spend
an additional $175 million to complete the replacement of the steam generators
and extend the operating licenses of Calvert Cliffs.
If we do not replace the stream generators, we estimate that Calvert Cliffs
could not operate beyond the 2004-2006 time period. We expect the steam
generator replacements to occur during the 2002 spring refueling outage for Unit
1 and during the 2003 outage for Unit 2.
Our utility operations provided about 105% in 1997, 97% in 1996, and 100% in
1995, of the cash needed to meet our capital requirements, excluding cash needed
to retire debt and redeem preferred and preference stock.
During the three years from 1998 through 2000, we expect utility operations to
provide 106% of the cash needed to meet our capital requirements, excluding cash
needed to retire debt and redeem preference stock.
When we cannot meet utility capital requirements internally, we sell debt and
equity securities. We also sell securities when market conditions permit us to
refinance existing debt or preference stock at a lower cost. The amount of cash
we need and market conditions determine when and how much we sell. During the
three years ended December 31, 1997, we sold:
o $619 million of long-term debt,
o $60 million of preference stock, and
o $4 million of common stock.
Security Ratings
Independent credit-rating agencies rate our fixed-income securities. The ratings
indicate the agencies' assessment of our ability to pay interest, dividends, and
principal on these securities. These ratings affect how much it will cost us
when we sell these securities. The better the rating, the lower the cost of the
securities to us when we sell them. Our securities ratings at the date of this
report are shown in the following table. In October, 1997, Standard & Poors
upgraded our mortgage bonds from A+ to AA-.
Standard Moody's
& Poors Investors Duff & Phelps
Rating Group Service Credit Rating Co.
- ----------------------------------------------------------------
Mortgage Bonds AA- A1 AA-
Unsecured Debt A A2 A+
Preference Stock A "a2" A
Capital Requirements of Our Diversified Businesses
In the past, capital requirements of our diversified businesses only included
the Constellation Holdings Companies because they had the only significant
capital requirements. From time to time, however, our other diversified
businesses may develop significant capital requirements. As that occurs, we will
include the capital requirements of those businesses in the capital requirements
table above. As discussed under "Diversified Business Investment Requirements,"
capital requirements for Constellation Power Source--a subsidiary of
Constellation Energy Solutions, Inc., and ComfortLink--a general partnership in
which BGE is a partner, are also included this year.
34 Baltimore Gas and Electric Company and Subsidiaries
Our diversified businesses expect to expand their businesses. This may include
expansion in the energy marketing, power generation, financial investments, real
estate, and senior-living facility businesses. Such expansion could mean more
investments in and acquisition of new projects. Our diversified businesses have
met their capital requirements in the past through borrowing, cash from their
operations, and from time to time, loans or equity contributions from BGE. Our
diversified businesses plan to raise the cash needed to meet capital
requirements in the future through these same methods.
Diversified Business Investment Requirements
The investment requirements of our diversified businesses include:
o the Constellation Holdings Companies' investments in
financial limited partnerships and funding for the development
and acquisition of projects, as well as loans made to
project entities,
o funding for growing Constellation Power Source's power
marketing business, and
o ComfortLink's funding for construction of district energy projects.
Investment requirements for 1998 through 2000 include estimates of funding for
existing and anticipated projects. We continuously review and modify those
estimates. Actual investment requirements could vary a great deal from the
estimates on page 34 because they would be subject to several variables,
including:
o the type and number of projects selected for development,
o the effect of market conditions on those projects,
o the ability to obtain financing, and
o the availability of cash from operations.
The investment requirements exclude BGE's commitment to contribute up to $115
million in equity to Constellation Power Source, Inc. to fund its investment in
Orion Power Holdings, Inc.
Diversified Business Debt and Liquidity
Our diversified businesses plan to meet capital requirements by refinancing debt
as it comes due, by additional borrowing, and with cash generated by the
businesses. This includes cash from operations, sale of assets, and earned tax
benefits. BGE Home Products & Services may also meet capital requirements
through sales of receivables. We also discuss receivable sales in Note 12.
If the Constellation Holdings Companies can get a reasonable value for real
estate, additional cash may be obtained by selling real estate projects. The
Constellation Holdings Companies' ability to sell or liquidate assets will
depend on market conditions, and we cannot give assurances that these sales or
liquidations could be made. For more information, see the discussion of the real
estate business and market in the "Real Estate Development and Senior-Living
Facilities" section beginning on page 33.
In 1997, the Constellation Holdings Companies issued $289 million of three and
four-year notes. In addition, our diversified businesses have the following
revolving credit agreements to provide additional cash for short-term financial
needs:
Amount of Revolving
Credit Agreement
- ---------------------------------------------------------------
Constellation Holdings Companies $75 million
ComfortLink $50 million
Constellation Energy Solutions, Inc.
and Subsidiaries $10 million
- ---------------------------------------------------------------
Other Matters
Environmental Matters
We are subject to increasingly stringent federal, state, and local laws and
regulations that work to improve or maintain the quality of the environment. If
certain substances were disposed of or released at any of our properties,
whether currently operating or not, these laws and regulations require us to
remove or remedy the effect on the environment. This includes Environmental
Protection Agency Superfund sites. You will find details of our environmental
matters in Note 12 and in this Annual Report on Form 10-K under Item 1.
Business--Environmental Matters. These details include financial information.
Some of the information is about costs that may be material.
The Year 2000 Issue
The year 2000 issue affects virtually all companies and organizations. Many
existing computer programs and digital systems use only two digits to identify a
year in the date field. These programs and systems were designed and developed
without considering the impact of the upcoming change in the century. If not
corrected, many computer applications could fail or create erroneous results by
or at the year 2000.
In 1997, we formed a special task force to:
o identify and evaluate our systems and applications that may
be affected by the year 2000 issue,
o modify or replace those systems and applications so they
will work properly in the year 2000, and
o communicate with our suppliers to make sure they are
prepared for the year 2000.
We have identified and evaluated all of our systems and applications that may be
affected by the year 2000 issue, and have developed plans to ready these systems
and applications for the century change. Modification and replacement projects
are currently under way. We plan to complete our evaluation of suppliers'
systems and applications by mid-1998. We plan to have our systems and
applications ready for the year 2000 by mid-1999. We do not expect the costs to
address the year 2000 issue to be material.
Accounting Standards Issued
We will adopt the following statements that the Financial Accounting Standards
Board issued in 1997 on the dates indicated below:
o Statement of Financial Accounting Standards No. 130,
REPORTING COMPREHENSIVE INCOME, which we must adopt in our
financial statements for the quarter ended March 31, 1998, and
o Statement of Financial Accounting Standards No. 131,
DISCLOSURES ABOUT SEGMENTS OF AN ENTERPRISE AND RELATED
INFORMATION, which we must adopt in our financial statements
for the year ended December 31, 1998.
We do not expect the adoption of these standards to have a material impact on
our financial results or financial statement disclosures.
Baltimore Gas and Electric Company and Subsidiaries 35
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
Not applicable. However, we disclose information about our risk management
policies in NOTE 1 TO CONSOLIDATED FINANCIAL STATEMENTS.
36
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT ACCOUNTANTS
To the Shareholders of
Baltimore Gas and Electric Company
We have audited the consolidated financial statements and the financial
statement schedule of Baltimore Gas and Electric Company and Subsidiaries listed
in Item 14(a) of this Form 10-K. These financial statements and the financial
statement schedule are the responsibility of the Company's Management. Our
responsibility is to express an opinion on these financial statements and
financial statement schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
Management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Baltimore Gas
and Electric Company and Subsidiaries as of December 31, 1997 and 1996, and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 1997 in conformity with generally
accepted accounting principles. In addition, in our opinion, the financial
statement schedule referred to above, when considered in relation to the basic
financial statements taken as a whole, presents fairly, in all material
respects, the information required to be included therein.
We have also previously audited, in accordance with generally accepted
auditing standards, the consolidated balance sheets and statements of
capitalization at December 31, 1995, 1994, and 1993, and the related
consolidated statements of income, cash flows, common shareholders' equity, and
income taxes for each of the two years in the period ended December 31, 1994
(none of which are presented herein); and we expressed unqualified opinions on
those consolidated financial statements. In our opinion, the information set
forth in the Summary of Operations included in the Selected Financial Data for
each of the five years in the period ended December 31, 1997, appearing on page
25 is fairly stated in all material respects in relation to the financial
statements from which it has been derived.
/s/ COOPERS & LYBRAND L.L.P.
____________________________
COOPERS & LYBRAND L.L.P.
Baltimore, Maryland
January 21, 1998
37
Consolidated Statements of Income
YEAR ENDED DECEMBER 31, 1997 1996 1995
- --------------------------------------------------------------------------------------------------------------------
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
REVENUES
Electric $2,191.7 $2,208.7 $2,229.8
Gas 521.6 517.3 400.5
Diversified businesses 594.3 427.2 304.5
-------------------------------------------------
Total revenues 3,307.6 3,153.2 2,934.8
-------------------------------------------------
EXPENSES OTHER THAN INTEREST AND INCOME TAXES
Electric fuel and purchased energy 519.7 547.4 578.8
Disallowed replacement energy costs (see Note 12) -- 95.4 --
Gas purchased for resale 292.1 284.4 198.1
Operations 518.3 526.4 550.8
Maintenance 178.5 174.1 168.3
Diversified businesses--selling, general, and administrative 444.9 311.1 220.6
Write-downs of real estate investments (see Note 12) 70.8 -- --
Depreciation and amortization 342.9 330.2 317.4
Taxes other than income taxes 216.8 214.7 205.1
-------------------------------------------------
Total expenses other than interest and income taxes 2,584.0 2,483.7 2,239.1
-------------------------------------------------
INCOME FROM OPERATIONS 723.6 669.5 695.7
-------------------------------------------------
OTHER INCOME (EXPENSE)
Write-off of merger costs (see Note 12) (57.9) -- --
Allowance for equity funds used during construction 5.3 6.5 14.2
Equity in earnings of Safe Harbor Water Power Corporation 5.0 4.6 4.5
Net other income and (deductions) (5.2) (5.0) (9.9)
-------------------------------------------------
Total other income (expense) (52.8) 6.1 8.8
-------------------------------------------------
INCOME BEFORE INTEREST AND INCOME TAXES 670.8 675.6 704.5
-------------------------------------------------
INTEREST EXPENSE
Interest charges 241.2 217.6 219.7
Capitalized interest (8.4) (15.6) (15.0)
Allowance for borrowed funds used during construction (2.8) (3.5) (7.7)
-------------------------------------------------
Net interest expense 230.0 198.5 197.0
-------------------------------------------------
INCOME BEFORE INCOME TAXES 440.8 477.1 507.5
INCOME TAXES 158.0 166.3 169.5
-------------------------------------------------
NET INCOME 282.8 310.8 338.0
PREFERRED AND PREFERENCE STOCK DIVIDENDS 28.7 38.5 40.6
-------------------------------------------------
EARNINGS APPLICABLE TO COMMON STOCK $ 254.1 $ 272.3 $ 297.4
- -------------------------------------------------------------------=================================================
AVERAGE SHARES OF COMMON STOCK OUTSTANDING 147.7 147.6 147.5
EARNINGS PER COMMON SHARE AND
EARNINGS PER COMMON SHARE--ASSUMING DILUTION $1.72 $1.85 $2.02
- -------------------------------------------------------------------=================================================
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
38 Baltimore Gas and Electric Company and Subsidiaries
Consolidated Balance Sheets
AT DECEMBER 31, 1997 1996
- -------------------------------------------------------------------------------
(IN MILLIONS)
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 162.6 $ 66.7
Accounts receivable (net of allowance for
uncollectibles of $24.1 and $18.0 respectively) 419.8 419.5
Trading securities 119.7 68.8
Fuel stocks 87.6 87.1
Materials and supplies 164.2 147.7
Prepaid taxes other than income taxes 65.2 64.7
Other 27.4 44.7
----------------------
Total current assets 1,046.5 899.2
----------------------
INVESTMENTS AND OTHER ASSETS
Real estate projects 446.8 525.8
Power generation projects 451.7 379.1
Financial investments 196.5 204.4
Nuclear decommissioning trust fund 145.3 116.4
Net pension asset 113.0 84.5
Safe Harbor Water Power Corporation 34.4 34.4
Senior living facilities 62.2 36.4
Other 108.1 92.2
----------------------
Total investments and other assets 1,558.0 1,473.2
----------------------
UTILITY PLANT
Plant in service
Electric 6,725.6 6,514.9
Gas 846.9 777.0
Common 554.1 523.5
----------------------
Total plant in service 8,126.6 7,815.4
Accumulated depreciation (2,843.4) (2,617.1)
----------------------
Net plant in service 5,283.2 5,198.3
Construction work in progress 215.2 221.9
Nuclear fuel (net of amortization) 127.9 132.9
Plant held for future use 25.2 25.5
----------------------
Net utility plant 5,651.5 5,578.6
----------------------
DEFERRED CHARGES
Regulatory assets (net) 470.7 512.3
Other 46.7 81.0
----------------------
Total deferred charges 517.4 593.3
----------------------
TOTAL ASSETS $8,773.4 $8,544.3
- ---------------------------------------------------------======================
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
CERTAIN PRIOR-YEAR AMOUNTS HAVE BEEN RECLASSIFIED TO CONFORM WITH THE CURRENT
YEAR'S PRESENTATION.
Baltimore Gas and Electric Company and Subsidiaries 39
Consolidated Balance Sheets
AT DECEMBER 31, 1997 1996
- ---------------------------------------------------------------------------------------------------------
(IN MILLIONS)
Liabilities and Capitalization
CURRENT LIABILITIES
Short-term borrowings $ 316.1 $ 333.2
Current portions of long-term debt and preference stock 271.9 280.8
Accounts payable 203.0 172.9
Customer deposits 30.1 28.0
Accrued taxes 5.5 6.5
Accrued interest 58.4 57.4
Dividends declared 66.3 66.9
Accrued vacation costs 36.2 34.3
Other 44.3 37.1
-------------------------
Total current liabilities 1,031.8 1,017.1
-------------------------
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred income taxes 1,294.9 1,295.9
Postretirement and postemployment benefits 185.5 169.2
Decommissioning of federal uranium enrichment facilities 34.9 38.6
Other 67.0 65.5
-------------------------
Total deferred credits and other liabilities 1,582.3 1,569.2
-------------------------
CAPITALIZATION
Long-term debt 2,988.9 2,758.8
Redeemable preference stock 90.0 134.5
Preference stock not subject to mandatory redemption 210.0 210.0
Common shareholders' equity 2,870.4 2,854.7
-------------------------
Total capitalization 6,159.3 5,958.0
-------------------------
COMMITMENTS, GUARANTEES, AND CONTINGENCIES--SEE NOTE 12
TOTAL LIABILITIES AND CAPITALIZATION $8,773.4 $8,544.3
- --------------------------------------------------------------------------------=========================
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
CERTAIN PRIOR-YEAR AMOUNTS HAVE BEEN RECLASSIFIED TO CONFORM WITH THE CURRENT
YEAR'S PRESENTATION.
40 Baltimore Gas and Electric Company and Subsidiaries
Consolidated Statements of Cash Flows
YEAR ENDED DECEMBER 31, 1997 1996 1995
- -----------------------------------------------------------------------------------------------------------------------------------
(IN MILLIONS)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $282.8 $310.8 $338.0
Adjustments to reconcile to net cash provided by operating activities
Depreciation and amortization 396.8 383.1 379.0
Deferred income taxes 7.4 26.0 103.5
Investment tax credit adjustments (7.5) (7.6) (8.1)
Deferred fuel costs 18.3 0.5 5.6
Deferred energy conservation revenues -- 28.5 1.3
Disallowed replacement energy costs -- 95.4 --
Accrued pension and postemployment benefits (18.0) (13.8) (7.6)
Write-off of merger costs 57.9 -- --
Write-downs of real estate investments 70.8 -- --
Allowance for equity funds used during construction (5.3) (6.5) (14.2)
Equity in earnings of affiliates and joint ventures (net) (42.5) (48.3) (21.3)
Changes in current assets, other than sales of accounts receivable (54.7) (88.0) (107.4)
Changes in current liabilities, other than short-term borrowings 42.6 (4.9) (7.3)
Other (22.6) 26.7 6.7
-----------------------------------------
Net cash provided by operating activities 726.0 701.9 668.2
-----------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Net issuance (maturity) of short-term borrowings (17.1) 53.9 215.6
Proceeds from issuance of
Long-term debt 622.0 383.2 184.4
Preference stock -- -- 59.3
Common stock -- 3.7 0.3
Proceeds from sales of receivables -- 10.0 2.0
Reacquisition of long-term debt (343.3) (158.5) (315.1)
Redemption of preferred and preference stock (104.5) (112.6) (73.0)
Common stock dividends paid (239.2) (233.1) (227.2)
Preferred and preference stock dividends paid (29.7) (37.0) (40.1)
Other 2.5 (1.2) --
-----------------------------------------
Net cash used in financing activities (109.3) (91.6) (193.8)
-----------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Utility construction expenditures (including AFC) (373.2) (360.5) (366.0)
Allowance for equity funds used during construction 5.3 6.5 14.2
Nuclear fuel expenditures (43.6) (46.8) (46.3)
Deferred energy conservation expenditures (27.1) (31.4) (45.5)
Contributions to nuclear decommissioning trust fund (17.6) (25.5) (9.8)
Merger costs (20.9) (28.5) (5.1)
Purchases of marketable equity securities (23.0) (32.7) (18.5)
Sales of marketable equity securities 46.5 39.7 49.8
Other financial investments (0.4) 7.1 9.4
Real estate projects 24.2 (55.3) (15.6)
Power generation systems (44.3) (5.3) (34.4)
Other (46.7) (34.3) (21.8)
-----------------------------------------
Net cash used in investing activities (520.8) (567.0) (489.6)
-----------------------------------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 95.9 43.3 (15.2)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 66.7 23.4 38.6
-----------------------------------------
CASH AND CASH EQUIVALENTS AT END OF YEAR $162.6 $ 66.7 $ 23.4
- -------------------------------------------------------------------------------------------=========================================
OTHER CASH FLOW INFORMATION
Cash paid during the year for:
Interest (net of amounts capitalized) $224.2 $193.6 $195.3
Income taxes $171.2 $160.1 $ 99.6
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
CERTAIN PRIOR-YEAR AMOUNTS HAVE BEEN RECLASSIFIED TO CONFORM WITH THE CURRENT
YEAR'S PRESENTATION.
Baltimore Gas and Electric Company and Subsidiaries 41
Consolidated Statements of Common Shareholders' Equity
Unrealized
Gain (Loss)
on Available Pension
Common Stock Retained For Sale Liability Total
YEARS ENDED DECEMBER 31, 1997, 1996, AND 1995 Shares Amount Earnings Securities Adjustment Amount
- ------------------------------------------------------------------------------------------------------------------------------------
(DOLLAR AMOUNTS IN MILLIONS, NUMBER OF SHARES IN THOUSANDS)
BALANCE AT DECEMBER 31, 1994 147,527 $1,425.4 $1,312.6 $(2.5) $(16.5) $2,719.0
Net income 338.0 338.0
Dividends declared
Preferred and preference stock (40.6) (40.6)
Common stock ($1.55 per share) (228.6) (228.6)
Common stock issued 0.3 0.3
Other 0.1 0.1
Net unrealized gain on securities 10.0 10.0
Deferred taxes on net unrealized gain on securities (3.5) (3.5)
Pension liability adjustment 25.4 25.4
Deferred taxes on pension liability adjustment (8.9) (8.9)
--------------------------------------------------------------------------
BALANCE AT DECEMBER 31, 1995 147,527 1,425.8 1,381.4 4.0 -- 2,811.2
Net income 310.8 310.8
Dividends declared
Preferred and preference stock (38.5) (38.5)
Common stock ($1.59 per share) (234.6) (234.6)
Common stock issued 140 3.7 3.7
Other 0.4 0.4
Net unrealized gain on securities 2.6 2.6
Deferred taxes on net unrealized gain on securities (0.9) (0.9)
--------------------------------------------------------------------------
BALANCE AT DECEMBER 31, 1996 147,667 1,429.9 1,419.1 5.7 -- 2,854.7
Net income 282.8 282.8
Dividends declared
Preference stock (28.7) (28.7)
Common stock ($1.63 per share) (240.7) (240.7)
Other 3.1 3.1
Net unrealized loss on securities (1.2) (1.2)
Deferred taxes on net unrealized loss on securities 0.4 0.4
--------------------------------------------------------------------------
BALANCE AT DECEMBER 31, 1997 147,667 $1,433.0 $1,432.5 $4.9 $ -- $2,870.4
- ----------------------------------------------------------==========================================================================
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
CERTAIN PRIOR-YEAR AMOUNTS HAVE BEEN RECLASSIFIED TO CONFORM WITH THE CURRENT
YEAR'S PRESENTATION.
42 Baltimore Gas and Electric Company and Subsidiaries
Consolidated Statements of Capitalization
AT DECEMBER 31, 1997 1996
- ------------------------------------------------------------------------------------------------------------------------
(IN MILLIONS)
LONG-TERM DEBT
First Refunding Mortgage Bonds of BGE
6 1/8% Series, due August 1, 1997 $ -- $ 24.9
Floating rate series, due April 15, 1999 125.0 125.0
8.40% Series, due October 15, 1999 91.1 91.1
5 1/2% Series, due July 15, 2000 125.0 125.0
8 3/8% Series, due August 15, 2001 122.3 122.4
7 1/8% Series, due January 1, 2002 -- 22.7
7 1/4% Series, due July 1, 2002 124.5 124.5
5 1/2% Installment Series, due July 15, 2002 9.8 10.4
6 1/2% Series, due February 15, 2003 124.8 124.8
6 1/8% Series, due July 1, 2003 124.9 124.9
5 1/2% Series, due April 15, 2004 125.0 125.0
Remarketed floating rate series, due September 1, 2006 125.0 125.0
7 1/2% Series, due January 15, 2007 123.5 123.7
6 5/8% Series, due March 15, 2008 124.9 125.0
7 1/2% Series, due March 1, 2023 125.0 125.0
7 1/2% Series, due April 15, 2023 100.0 100.0
---------------------------------
Total First Refunding Mortgage Bonds of BGE 1,570.8 1,619.4
---------------------------------
Other long-term debt of BGE
Term bank loan due March 29, 2001 -- 50.0
Medium-term notes, Series B 100.0 100.0
Medium-term notes, Series C 143.0 183.0
Medium-term notes, Series D 225.0 138.0
Medium-term notes, Series E 183.5 --
Pollution control loan, due July 1, 2011 36.0 36.0
Port facilities loan, due June 1, 2013 48.0 48.0
Adjustable rate pollution control loan, due July 1, 2014 20.0 20.0
5.55% Pollution control revenue refunding loan, due July 15, 2014 47.0 47.0
Economic development loan, due December 1, 2018 35.0 35.0
6.00% Pollution control revenue refunding loan, due April 1, 2024 75.0 75.0
Variable rate pollution control loan, due June 1, 2027 8.8 --
---------------------------------
Total other long-term debt of BGE 921.3 732.0
---------------------------------
Long-term debt of Constellation Holdings Companies
Loans under revolving credit agreement
Variable rates based on LIBOR, due December 9, 1999 -- 65.0
Mortgage and construction loans and other collateralized notes
8.69% mortgage note, due January 28, 1998 28.4 24.9
7.90% mortgage note, due September 12, 2000 8.6 8.8
8.00% mortgage note, due July 31, 2001 0.1 0.1
8.00% mortgage note, due October 30, 2003 1.6 1.5
7.50% mortgage note, due October 9, 2005 9.7 9.8
Variable rate mortgage notes, due through 2009 93.5 94.9
7.357% mortgage note, due March 15, 2009 5.5 5.8
9.65% mortgage note, due February 1, 2028 9.7 9.7
8.00% mortgage note, due November 1, 2033 1.2 --
Unsecured notes 579.1 387.2
---------------------------------
Total long-term debt of Constellation Holdings Companies 737.4 607.7
---------------------------------
Long-term debt of other diversified businesses
Loans under revolving credit agreement 22.0 12.0
---------------------------------
Unamortized discount and premium (13.7) (14.5)
Current portion of long-term debt (248.9) (197.8)
---------------------------------
Total long-term debt $2,988.9 $2,758.8
---------------------------------
CONTINUED ON PAGE 44
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
CERTAIN PRIOR-YEAR AMOUNTS HAVE BEEN RECLASSIFIED TO CONFORM WITH THE CURRENT
YEAR'S PRESENTATION.
Baltimore Gas and Electric Company and Subsidiaries 43
Consolidated Statements of Capitalization
AT DECEMBER 31, 1997 1996
- ----------------------------------------------------------------------------------------------------------------------------------
(IN MILLIONS)
PREFERENCE STOCK
Cumulative, $100 par value, 6,500,000 shares authorized
Redeemable preference stock
7.50%, 1986 Series, 365,000 and 395,000 shares outstanding. Callable
at $102.50 per share prior to October 1, 2001 and at lesser amounts thereafter $ 36.5 $ 39.5
6.75 %, 1987 Series, 425,000 and 440,000 shares outstanding. Callable
at $102.25 per share prior to April 1, 2002 and at lesser amounts thereafter 42.5 44.0
7.80%, 1989 Series, 500,000 shares redeemed at par on July 1, 1997 -- 50.0
8.25%, 1989 Series, 100,000 shares redeemed at par on October 1, 1997 -- 10.0
8.625%, 1990 Series, 130,000 and 390,000 shares outstanding 13.0 39.0
7.85%, 1991 Series, 210,000 and 350,000 shares outstanding 21.0 35.0
Current portion of redeemable preference stock (23.0) (83.0)
---------------------------------
Total redeemable preference stock 90.0 134.5
---------------------------------
Preference stock not subject to mandatory redemption
7.78%, 1973 Series, 200,000 shares outstanding, callable at $101 per share 20.0 20.0
7.125%, 1993 Series, 400,000 shares outstanding, not callable prior to July 1, 2003 40.0 40.0
6.97%, 1993 Series, 500,000 shares outstanding, not callable prior to October 1, 2003 50.0 50.0
6.70%, 1993 Series, 400,000 shares outstanding, not callable prior to January 1, 2004 40.0 40.0
6.99%, 1995 Series, 600,000 shares outstanding, not callable prior to October 1, 2005 60.0 60.0
---------------------------------
Total preference stock not subject to mandatory redemption 210.0 210.0
---------------------------------
COMMON SHAREHOLDERS' EQUITY
Common stock without par value, 175,000,000 shares authorized; 147,667,114
shares issued and outstanding at December 31, 1997 and 1996. (At December
31, 1997 166,893 shares were reserved for the Employee Savings Plan and
3,277,656 shares were reserved for the Dividend Reinvestment and Stock Purchase Plan.) 1,433.0 1,429.9
Retained earnings 1,432.5 1,419.1
Unrealized gain on available-for-sale securities 4.9 5.7
---------------------------------
Total common shareholders' equity 2,870.4 2,854.7
---------------------------------
TOTAL CAPITALIZATION $6,159.3 $5,958.0
- -------------------------------------------------------------------------------------------------=================================
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
CERTAIN PRIOR-YEAR AMOUNTS HAVE BEEN RECLASSIFIED TO CONFORM WITH THE CURRENT
YEAR'S PRESENTATION.
44 Baltimore Gas and Electric Company and Subsidiaries
Consolidated Statements of Income Taxes
YEAR ENDED DECEMBER 31, 1997 1996 1995
- ----------------------------------------------------------------------------------------------------------------------------------
(DOLLAR AMOUNTS IN MILLIONS)
INCOME TAXES
Current $158.1 $147.9 $ 74.1
-----------------------------------------------
Deferred
Change in tax effect of temporary differences (1.0) 22.0 116.9
Change in income taxes recoverable through future rates 8.0 4.9 (1.0)
Deferred taxes credited (charged) to shareholders' equity 0.4 (0.9) (12.4)
-----------------------------------------------
Deferred taxes charged to expense 7.4 26.0 103.5
Investment tax credit adjustments (7.5) (7.6) (8.1)
-----------------------------------------------
Income taxes per Consolidated Statements of Income $158.0 $166.3 $169.5
- -----------------------------------------------------------------------------------===============================================
RECONCILIATION OF INCOME TAXES COMPUTED AT STATUTORY
FEDERAL RATE TO TOTAL INCOME TAXES
Income before income taxes $440.8 $477.1 $507.5
Statutory federal income tax rate 35% 35% 35%
-----------------------------------------------
Income taxes computed at statutory federal rate 154.3 167.0 177.6
Increases (decreases) in income taxes due to
Depreciation differences not normalized on regulated activities 13.9 12.6 11.0
Allowance for equity funds used during construction (1.9) (2.3) (5.0)
Amortization of deferred investment tax credits (7.5) (7.7) (8.1)
Tax credits flowed through to income (0.5) (0.5) (0.5)
Amortization of deferred tax rate differential on regulated activities (2.3) (1.9) (2.0)
State income taxes 6.2 4.1 1.6
Other (4.2) (5.0) (5.1)
-----------------------------------------------
Total income taxes $158.0 $166.3 $169.5
- -----------------------------------------------------------------------------------===============================================
Effective federal income tax rate 35.8% 34.9% 33.4%
AT DECEMBER 31, 1997 1996
- ----------------------------------------------------------------------------------------------------------------------
(DOLLAR AMOUNTS IN MILLIONS)
DEFERRED INCOME TAXES
Deferred tax liabilities
Accelerated depreciation $ 953.5 $ 920.6
Allowance for funds used during construction 206.7 209.2
Income taxes recoverable through future rates 89.8 92.6
Deferred termination and postemployment costs 41.1 45.6
Deferred fuel costs 1.5 7.9
Leveraged leases 25.2 27.6
Percentage repair allowance 38.7 38.4
Energy conservation expenditures 24.5 26.6
Other 191.5 175.6
-----------------------------
Total deferred tax liabilities 1,572.5 1,544.1
-----------------------------
Deferred tax assets
Accrued pension and postemployment benefit costs 37.6 40.6
Deferred investment tax credits 44.3 46.9
Capitalized interest and overhead 44.5 42.5
Contributions in aid of construction 39.7 35.7
Nuclear decommissioning liability 24.3 20.0
Other 87.2 62.5
-----------------------------
Total deferred tax assets 277.6 248.2
-----------------------------
Deferred tax liability, net $1,294.9 $1,295.9
- -----------------------------------------------------------------------------------------=============================
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
CERTAIN PRIOR-YEAR AMOUNTS HAVE BEEN RECLASSIFIED TO CONFORM WITH THE CURRENT
YEAR'S PRESENTATION.
Baltimore Gas and Electric Company and Subsidiaries 45
Notes to Consolidated Financial Statements
Note 1. Significant Accounting Policies
- --------------------------------------------------------------------------------
Nature of Our Business
Baltimore Gas and Electric Company (BGE) is the parent company and conducts our
primary business--the electric and gas utility business. That business serves
Baltimore City and all or part of 10 Central Maryland counties. We also conduct
various diversified businesses in subsidiary companies. We describe our
diversified businesses in Note 3.
Consolidation Policy
We use three different accounting methods to report our investments in our
subsidiaries or other companies: consolidation, the equity method, and the cost
method.
Consolidation
We use consolidation when we own a majority of the voting stock of the
subsidiary. This means the accounts of our subsidiaries are combined with our
accounts. We eliminate intercompany balances and transactions when we
consolidate these accounts. Our consolidated financial statements include the
accounts of:
o BGE,
o Constellation Holdings, Inc. and Subsidiaries (the Constellation Holdings
Companies),
o Constellation Energy Solutions, Inc. and Subsidiaries, and
o BGE Home Products & Services, Inc. and Subsidiaries.
The Equity Method
We usually use the equity method to report corporate joint ventures,
partnerships, and affiliated companies (including power generation projects)
where we hold a 20% to 50% voting interest. Under the equity method, we report:
o our interest in the entity as an investment in our Consolidated Balance
Sheets, and
o our percentage share of the earnings from the entity in our Consolidated
Statements of Income.
The only time we do not use this method is if we can exercise control over the
operations and policies of the company. If we have control, accounting rules
require us to use consolidation. We report our investment in Safe Harbor Water
Power Corporation under the equity method.
The Cost Method
We usually use the cost method if we hold less than a 20% voting interest in an
investment. Under the cost method, we report our investment at cost in our
Consolidated Balance Sheets. The only time we do not use this method is when we
can exercise significant influence over the operations and policies of the
company. If we have significant influence, accounting rules require us to use
the equity method.
Regulation of Utility Business
The Maryland Public Service Commission (Maryland PSC) regulates our utility
business. Generally, we use the same accounting policies and practices used by
nonregulated companies for financial reporting under generally accepted
accounting principles.
However, sometimes the Maryland PSC orders an accounting treatment different
from that used by nonregulated companies to determine the rates we charge our
customers. We discuss this further in Note 5.
Utility Revenues
We record utility revenues in our Consolidated Statements of Income when we
provide service to customers.
Fuel and Purchased Energy Costs
We incur costs for:
o the fuel we use to generate electricity,
o purchases of electricity from others, and
o natural gas that we resell.
These costs are shown in our Consolidated Statements of Income as "electric fuel
and purchased energy" and "gas purchased for resale." We discuss each of these
separately below.
Fuel Used to Generate Electricity and Purchases of Electricity From Others
Under the electric fuel rate clause set by the Maryland PSC, we charge our
electric customers for:
o the fuel we use to generate electricity (nuclear fuel, coal, gas, or oil),
and
o the net cost of purchases and sales of electricity, primarily with other
utilities.
We charge the actual costs of these items to customers with no profit to us. To
do this, we must keep track of what we spend and what we collect from customers
under the fuel rate in a given period. Usually these two amounts are not the
same because there is a difference between the time we spend the money and the
time we collect it from our customers.
Under the electric fuel rate clause, we defer (include as an asset or liability
in our Consolidated Balance Sheets and exclude from our Consolidated Statements
of Income) the difference between our actual costs of fuel and energy and what
we collect from customers under the fuel rate in a given period. We either bill
or refund our customers that difference in the future. We discuss this further
in Note 5.
We calculate the electric fuel rate using three factors:
o the mix of generating plants we used over the last 24 months,
o the latest three-month average fuel cost for each generating unit, and
o the net cost of purchases and sales of electricity, primarily with other
utilities, over the last 24 months.
We may change the fuel rate only if the calculated rate is more than 5% above or
below the rate in effect. The fuel rate is affected most by the amount of
electricity generated at our Calvert Cliffs Nuclear Power Plant (Calvert Cliffs)
because the cost of nuclear fuel is cheaper than coal, gas, or oil.
46 Baltimore Gas and Electric Company and Subsidiaries
We also report two other items as "electric fuel and purchased energy" in our
Consolidated Statements of Income:
o amortization of nuclear fuel (described under "Utility Plant" later in this
note). We amortize nuclear fuel based on the energy produced over the life
of the fuel. We pay quarterly fees to the Department of Energy for the
future disposal of spent nuclear fuel, and accrue these fees based on the
kilowatt-hours of electricity sold. We bill our customers for nuclear fuel
as described earlier in this note.
o amortization of deferred costs of decommissioning and decontaminating the
Department of Energy's uranium enrichment facilities. We discuss these
costs further in Note 5.
Extended outages at Calvert Cliffs drive up fuel costs and may result in fuel
rate proceedings before the Maryland PSC. In these proceedings, the Maryland PSC
would consider whether any portion of the extra fuel costs should be paid by BGE
instead of passed on to customers. We discuss the financial impact of past
extended outages in Note 12.
Natural Gas
We charge our gas customers for the natural gas they consume using "gas cost
adjustment clauses" set by the Maryland PSC. These clauses operate the same as
the electric fuel rate clause described earlier in this note. However, effective
October 1996, the Maryland PSC approved a modification of the gas cost
adjustment clauses to provide a market based rates incentive mechanism. Under
market based rates our actual cost of gas is compared to a market index (a
measure of the market price of gas in a given period). The difference between
our actual cost and the market index is shared equally between BGE (which
benefits shareholders) and customers.
Risk Management
We engage in risk management activities in our gas business and in our
diversified businesses. We separately describe these activities for each
business below.
Gas Business
In 1996, we began using basis swaps in the winter months (November through
March) to hedge price risk associated with natural gas purchases. Under internal
guidelines, we are not permitted to try to predict market changes.
We defer, as unrealized gains or losses, the net amount we owe (unrealized
losses) or are due (unrealized gains) under the swaps in our Consolidated
Balance Sheets. At December 31, 1997, we had outstanding basis swap agreements
covering 15.4 million decatherms of natural gas purchases through March 1998. We
had unrealized gains of $1.0 million related to the outstanding agreements. When
amounts are paid under the agreements, we report the payments as gas costs in
our Consolidated Statements of Income.
Diversified Businesses
Our subsidiary, Constellation Power Source, engages in power marketing
activities, which include trading electricity, other energy commodities, and
related derivatives (such as forwards, options, and swaps). Constellation Power
Source reports trading activities using the mark-to-market method of accounting.
Under the mark-to-market method of accounting, we report:
o commodity positions and derivatives at fair value in our Consolidated
Balance Sheets, and
o changes in fair value as diversified business revenues in our Consolidated
Statements of Income.
At December 31, 1997, Constellation Power Source had derivative assets with a
fair value of about $9.4 million and derivative liabilities with a fair value of
about $8.6 million.
Market Risk
We measure our exposure to market risk at any point in time by comparing our
open positions to a market estimate of fair value. The market prices we use to
determine fair value are based on management's best estimates, which consider
various factors including:
o closing exchange prices, o time value of money, and
o over-the-counter prices, o volatility factors.
At December 31, 1997, our exposure to market risk was not material.
Taxes
We summarize our income taxes in the Consolidated Statements of Income Taxes on
page 45. As you read this section, it may be helpful to refer to those
statements.
Income Tax Expense
We have two categories of income taxes in our Consolidated Statements of
Income--current and deferred. We describe each of these below.
Our current income tax expense consists solely of regular tax less applicable
tax credits. Our 1996 and 1995 current income tax expense amounts include
alternative minimum tax credits of $30 million in 1996 and $40 million in 1995.
The alternative minimum tax can be carried forward indefinitely and used as tax
credits in years when our regular tax liability exceeds the alternative minimum
tax liability. We do not have any remaining alternative minimum tax credits.
Our deferred income tax expense is equal to the changes in the deferred income
tax liability and regulatory asset (described later in this note) during the
year, excluding amounts charged or credited to common shareholders' equity.
Investment Tax Credits
We have also deferred the investment tax credit associated with our regulated
utility business in our Consolidated Balance Sheets as a regulatory liability.
The regulatory liability is amortized evenly to income over the life of each
property. We discuss this further in Note 5. We reduce income tax expense in our
Consolidated Statements of Income for the investment tax credit and other tax
credits associated with our nonregulated diversified businesses, other than
leveraged leases.
Deferred Income Tax Assets and Liabilities
We must report some of our assets and liabilities differently for our financial
statements than we do for income tax purposes. The tax effects of the
differences in these items are reported as deferred income tax assets or
liabilities in our Consolidated Balance Sheets. We measure the assets and
liabilities using income tax rates that are currently in effect.
Baltimore Gas and Electric Company and Subsidiaries 47
A portion of our total deferred income tax liability relates to our utility
business, but has not been reflected in the rates we charge our customers. We
refer to this portion of the liability as "income taxes recoverable through
future rates." We have recorded that portion of the liability as a regulatory
asset in our Consolidated Balance Sheets. We discuss this further in Note 5.
Franchise Taxes
We pay Maryland public service company franchise tax instead of state income tax
on our utility revenue from sales in Maryland. We include the franchise tax in
"taxes other than income taxes" in our Consolidated Statements of Income.
Inventory
We report the majority of our fuel stocks and materials and supplies at average
cost.
Evaluation of Assets for Impairment
Statement of Financial Accounting Standards No. 121, ACCOUNTING FOR THE
IMPAIRMENT OF LONG-LIVED ASSETS AND FOR LONG-LIVED ASSETS TO BE DISPOSED OF,
applies particular requirements to some of our assets that have long lives (some
examples are utility property and equipment, and real estate). We determine if
those assets are impaired by comparing their undiscounted expected future cash
flows to their carrying amount in our accounting records. We recognize an
impairment loss if the undiscounted expected future cash flows are less than the
carrying amount of the asset.
REAL ESTATE PROJECTS
In Note 4, we summarize the real estate projects that are in our Consolidated
Balance Sheets. The projects consist of the Constellation Holdings Companies'
investments in:
o rental and operating properties, that they are holding for investment, and
o properties under development, that they are holding for future development
and subsequent sale.
The Constellation Holdings Companies include the costs incurred to acquire and
develop these properties as part of the costs of the properties. Generally, the
Constellation Holdings Companies report these properties at cost, unless the
amount invested exceeds the fair value. In these cases, the Constellation
Holdings Companies write down the projects to their fair values.
Financial Investments and Trading Securities
In Note 4, we summarize the financial investments that are in our Consolidated
Balance Sheets.
Statement of Financial Accounting Standards No. 115, ACCOUNTING FOR CERTAIN
INVESTMENTS IN DEBT AND EQUITY SECURITIES, applies particular requirements to
some of our investments in debt and equity securities. We report those
investments at fair value, and we use specific identification to determine their
cost for computing realized gains or losses. We classify these investments as
either trading securities or available-for-sale securities, which we describe
separately below. We report investments that are not covered by Statement of
Financial Accounting Standards No. 115 at their cost.
Trading Securities
The Constellation Holdings Companies classify some of their investments in
marketable equity securities and financial limited partnerships as trading
securities. We include any unrealized gains or losses on these securities in
diversified business revenues in our Consolidated Statements of Income.
Available-for-Sale Securities
We classify our investments in the nuclear decommissioning trust fund as
available-for-sale securities. We include any unrealized gains or losses on the
trust assets as a change in the decommissioning reserve. We describe the nuclear
decommissioning trust and the reserve under the heading "Decommissioning Costs"
later in this note.
In addition, the Constellation Holdings Companies classify some of their
investments in marketable equity securities as available-for-sale securities. We
include any unrealized gains or losses on these securities in shareholders'
equity in our Consolidated Balance Sheets. We also include the Constellation
Holdings Companies' portion of unrealized gains or losses on securities of
equity-method (described earlier in this note) investees in shareholders'
equity.
Utility Plant, Depreciation and Amortization, and Decommissioning
Utility Plant
Utility plant is the term we use to describe our utility business property and
equipment that is in use, being held for future use, or under construction. We
summarize utility plant in our Consolidated Balance Sheets. We report our
utility plant at its original cost, which includes:
o material and labor,
o contractor costs,
o construction overhead costs (where applicable), and
o an allowance for funds used during construction (described later in this
note).
We charge retired or otherwise-disposed-of utility plant to accumulated
depreciation.
We own an undivided interest in the Keystone and Conemaugh electric generating
plants in Western Pennsylvania, as well as in the transmission line that
transports the plants' output to the joint owners' service territories. Our
ownership interests in these plants are 20.99% in Keystone and 10.56% in
Conemaugh. These ownership interests represented a net investment of $152
million at December 31, 1997, and $153 million at December 31, 1996. We report
these properties in the same accounts we use for our other utility plant
(described above).
Depreciation Expense
Generally, we compute depreciation by applying composite, straight-line rates
(approved by the Maryland PSC) to the average investment in classes of
depreciable property. We depreciate vehicles based on their estimated useful
lives. As a result of the Maryland PSC's November 1995 gas base rate order, we
revised our gas utility plant depreciation rates to reflect the results of a
detailed depreciation study. The revised rates increased depreciation expense by
approximately $2.4 million annually.
48 Baltimore Gas and Electric Company and Subsidiaries
Our 1995 depreciation expense includes the write-off of expenditures associated
with a second combustion turbine at our Perryman site that will not be built.
This write-off reduced after-tax earnings during 1995 by $9.7 million, or $.07
per share. The construction of the first 140-megawatt combustion turbine at
Perryman was completed, and the unit was placed in service, during June 1995.
Amortization Expense
Amortization is an accounting process of reducing an amount in our Consolidated
Balance Sheets evenly over a period of time. When we reduce amounts in our
Consolidated Balance Sheets, we increase amortization expense in our
Consolidated Statements of Income. An amount is considered fully amortized when
it has been reduced to zero.
Decommissioning Costs
We must accumulate a reserve for the costs that we expect to incur in the future
to decommission the radioactive portion of Calvert Cliffs. We do this based on a
sinking fund methodology. In 1995, the Maryland PSC authorized us to record
decommissioning expense based on a facility-specific cost estimate so we can
accumulate a decommissioning reserve of $521 million in 1993 dollars by the end
of Calvert Cliffs' service life in 2016, adjusted to reflect expected inflation.
We have reported the decommissioning reserve in "accumulated depreciation" in
our Consolidated Balance Sheets. The total reserve was $201.6 million at
December 31, 1997, and $167.5 million at December 31, 1996.
To fund the costs we expect to incur to decommission the plant, we established
an external decommissioning trust in accordance with Nuclear Regulatory
Commission (NRC) regulations. We report the assets in the trust in "nuclear
decommissioning trust fund" in our Consolidated Balance Sheets. The NRC requires
utilities to provide financial assurance that they will accumulate sufficient
funds to pay for the cost of nuclear decommissioning based upon either a generic
NRC formula or a facility-specific decommissioning cost estimate. We use the
facility-specific cost estimate (mentioned above) for funding these costs and
providing the required financial assurance.
Allowance for Funds Used During Construction
and Capitalized Interest
Allowance for Funds Used During Construction (AFC)
We finance construction projects with borrowed funds and equity funds. We are
allowed by the Maryland PSC to record the costs of these funds as part of the
cost of construction projects in our Consolidated Balance Sheets. We do this
through the AFC, which we calculate using a rate authorized by the Maryland PSC.
We bill our customers for the AFC plus a return after the utility plant is
placed in service.
Prior to November 1995, we used a pre-tax rate of 9.40% to calculate AFC for all
of our utility plant. Effective November 1995, the Maryland PSC reduced the
pre-tax AFC rates to 9.04% for gas plant and 9.36% for common plant. We continue
to use 9.40% for electric plant. We compound AFC annually.
Capitalized Interest
The Constellation Holdings Companies capitalize interest costs incurred to
finance real estate developed for internal use and power generation development
projects.
Long-Term Debt
We defer (include as an asset or liability in our Consolidated Balance Sheets
and exclude from our Consolidated Statements of Income) all costs related to the
issuance of long-term debt. These costs include underwriters' commissions,
discounts or premiums, and other costs such as legal, accounting and regulatory
fees, and printing costs. We amortize these costs over the life of the debt.
When we incur gains or losses on debt that we retire prior to maturity, we
amortize those gains or losses over the remaining original life of the debt.
Cash Flows
For the purpose of reporting our cash flows, we define cash equivalents as
highly liquid investments that mature in three months or less.
Use of Accounting Estimates
Management makes estimates and assumptions when preparing financial statements
under generally accepted accounting principles. These estimates and assumptions
affect various matters, including:
o our reported amounts of assets and liabilities in our Consolidated Balance
Sheets at the dates of the financial statements,
o our disclosure of contingent assets and liabilities at the dates of the
financial statements, and
o our reported amounts of revenues and expenses in our Consolidated
Statements of Income during the reporting periods.
These estimates involve judgments with respect to, among other things, future
economic factors that are difficult to predict and are beyond management's
control. As a result, actual amounts could differ from these estimates.
RECLASSIFICATIONS
We have reclassified certain prior-year amounts for comparative purposes. These
reclassifications did not affect consolidated net income for the years
presented.
Baltimore Gas and Electric Company and Subsidiaries 49
Note 2. Information by Business Segment
- --------------------------------------------------------------------------------
We have three business segments: electric, gas, and diversified businesses
(subsidiaries). Our electric business generates, purchases, and sells
electricity. Our gas business purchases, transports, and sells natural gas. Our
diversified businesses are involved in various activities which we describe in
Note 3. We show selected financial information for each of our business segments
in the following table.
Construction Identifiable
Segment Intersegment Total Income from Depreciation/ Expenditures Assets at
Revenues Revenues Revenues Operations Amortization (Including AFC) December 31
- ------------------------------------------------------------------------------------------------------------------------------------
(IN MILLIONS)
1997--Electric $2,191.7 $ 0.3 $2,192.0 $596.8 $286.5 $278.7 $6,204.7
Gas 521.6 -- 521.6 63.5 39.3 94.5 896.9
Diversified businesses 594.3 10.3 604.6 63.3 17.1 -- 1,595.2
Other identifiable assets -- -- -- -- -- -- 76.6
Intercompany eliminations -- (10.6) (10.6) -- -- -- --
-------------------------------------- ------ ------ ------ --------
Total $3,307.6 $ -- $3,307.6 $723.6 $342.9 $373.2 $8,773.4
- -----------------------------------====================================== ====== ====== ====== ========
1996--Electric $2,208.7 $ 0.3 $2,209.0 $498.0 $279.3 $262.5 $6,222.6
Gas 517.3 -- 517.3 68.9 37.8 98.0 810.1
Diversified businesses 427.2 6.8 434.0 102.6 13.1 -- 1,400.6
Other identifiable assets -- -- -- -- -- -- 111.0
Intercompany eliminations -- (7.1) (7.1) -- -- -- --
-------------------------------------- ------ ------ ------ --------
Total $3,153.2 $ -- $3,153.2 $669.5 $330.2 $360.5 $8,544.3
- -----------------------------------====================================== ====== ====== ====== ========
1995--Electric $2,229.8 $ 1.3 $2,231.1 $574.3 $276.3 $288.5 $6,193.4
Gas 400.5 -- 400.5 48.1 29.6 77.5 748.5
Diversified businesses 304.5 6.6 311.1 73.3 11.5 -- 1,266.1
Other identifiable assets -- -- -- -- -- -- 69.6
Intercompany eliminations -- (7.9) (7.9) -- -- -- --
-------------------------------------- ------ ------ ------ --------
Total $2,934.8 $ -- $2,934.8 $695.7 $317.4 $366.0 $8,277.6
- -----------------------------------====================================== ====== ====== ====== ========
Note 3. Information About Our Subsidiaries
- --------------------------------------------------------------------------------
Our diversified business subsidiaries are organized in three groups:
o Our power generation, financial investments, and real estate businesses,
o Our energy marketing businesses, and
o Our home products and commercial building systems businesses.
Our Power Generation, Financial Investments,
and Real Estate Businesses
We refer to all of these together as the Constellation Holdings Companies.
Constellation Holdings, Inc. is a wholly owned subsidiary of BGE and holds all
of the stock of the following three subsidiaries:
o Constellation Power, Inc.--develops, owns, and operates power generation
projects,
o Constellation Investments, Inc.--engages in financial investments, and
o Constellation Real Estate Group, Inc.--develops, owns, and manages real
estate and senior-living facilities.
We show condensed financial information for the Constellation Holdings Companies
in the following table. We have not reflected the elimination of intercompany
balances or transactions that are eliminated in our consolidated financial
statements. We describe this further in Note 1.
1997 1996 1995
- -----------------------------------------------------------------
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
Income Statements
Revenues
Real estate projects $152.7 $80.8 $108.4
Power generation systems 109.1 93.1 57.7
Financial investments 51.9 38.9 25.2
-----------------------------
Total revenues 313.7 212.8 191.3
Expenses other than interest
and income taxes 238.8 113.2 114.4
-----------------------------
Income from operations 74.9 99.6 76.9
Minority interest (3.2) (0.3) (2.3)
Interest expense (56.4) (45.0) (46.7)
Capitalized interest 8.4 14.6 13.6
Income tax expense (11.8) (26.6) (14.4)
-----------------------------
Net income $ 11.9 $42.3 $ 27.1
- ------------------------------------=============================
Contribution to our earnings
per share of common stock $.08 $.29 $.18
- ------------------------------------=============================
Balance Sheets
Current assets $ 170.4 $ 115.7 $ 98.5
Noncurrent assets 1,190.0 1,189.7 1,102.5
-------------------------------
Total assets $1,360.4 $1,305.4 $1,201.0
- ----------------------------------===============================
Current liabilities $ 181.1 $ 134.0 $ 70.4
Noncurrent liabilities 837.0 775.2 778.5
Shareholder's equity 342.3 396.2 352.1
-------------------------------
Total liabilities and
shareholder's equity $1,360.4 $1,305.4 $1,201.0
- ----------------------------------===============================
50 Baltimore Gas and Electric Company and Subsidiaries
The 1997 income statement includes after-tax write-downs of real estate projects
totaling $46 million. We describe these write-downs in the "Real Estate
Development and Senior-Living Facilities" section of Management's Discussion and
Analysis on page 33.
The 1996 income statement includes a $14.6 million after-tax gain on the sale of
a power purchase agreement that was offset by:
o a $7.0 million after-tax write-off of an investment in two geothermal
wholesale power generating projects that sell electricity under California
power purchase agreements,
o a $3.0 million after-tax write-off of development costs for a coal-fired
power project, and
o a $6.2 million after-tax write-off of a portion of an investment in a solar
power project.
Our Energy Marketing Businesses
Constellation Energy Solutions, Inc. is a wholly owned subsidiary of BGE and
serves as the holding company for our three energy marketing businesses:
o Constellation Power Source, Inc.--provides power marketing and risk
management services to wholesale customers in North America by purchasing
and selling electric power, other energy commodities, and related
derivatives.
o Constellation Energy Source, Inc.--provides natural gas brokering and
related services for wholesale and retail customers.
o Constellation Energy Projects & Services, Inc. and Subsidiaries--provides a
broad range of customized energy services, including private electric and
gas distribution systems, energy consulting, power quality services, and
campus and multi-building energy systems.
Our Home Products and Commercial Building Systems Businesses
BGE Home Products & Services, Inc. and subsidiaries:
o sells and services electric and gas appliances,
o engages in home improvements, and
o sells and services heating and air conditioning systems.
Other
Safe Harbor Water Power Corporation is a producer of hydroelectric power. BGE
owns two-thirds of Safe Harbor's total capital stock, including one-half of the
voting stock, and a two-thirds interest in its retained earnings.
Note 4. Real Estate Projects and Financial Investments
- --------------------------------------------------------------------------------
Real Estate Projects
Real estate projects consist of the following investments held by the
Constellation Holdings Companies:
AT DECEMBER 31, 1997 1996
- ---------------------------------------------------------------
(IN MILLIONS)
Properties under development $220.8 $286.2
Rental and operating properties
(net of accumulated depreciation) 225.6 237.7
Other real estate ventures 0.4 1.9
-------------------------
Total real estate projects $446.8 $525.8
- --------------------------------------=========================
Financial Investments
Financial investments consist of the following investments held by the
Constellation Holdings Companies:
AT DECEMBER 31, 1997 1996
- --------------------------------------------------------------
(IN MILLIONS)
Insurance companies $ 88.8 $ 76.8
Marketable equity securities 33.3 46.2
Financial limited partnerships 43.6 48.1
Leveraged leases 30.8 33.3
-------------------------
Total financial investments $196.5 $204.4
- --------------------------------------=========================
Investments Classified as Available-for-Sale
We classify our investments in the nuclear decommissioning trust fund and the
Constellation Holdings Companies' marketable equity securities (shown above) as
available-for-sale. This means we do not expect to hold them to maturity and we
do not consider them trading securities.
We show the fair values, gross unrealized gains and losses, and amortized cost
bases for these available-for-sale securities, exclusive of $3.5 million of
unrealized net gains on securities of equity-method investees, in the following
tables.
Amortized Unrealized Unrealized Fair
AT DECEMBER 31, 1997 Cost Basis Gains Losses Value
- -----------------------------------------------------------------------
(IN MILLIONS)
Marketable Equity Securities $ 77.3 $12.0 $(0.5) $ 88.8
U.S. Government agency 14.9 0.2 -- 15.1
State municipal bonds 65.5 2.2 -- 67.7
---------------------------------------
Totals $157.7 $14.4 $(0.5) $171.6
- --------------------------------=======================================
Amortized Unrealized Unrealized Fair
AT DECEMBER 31, 1996 Cost Basis Gains Losses Value
- -----------------------------------------------------------------------
(IN MILLIONS)
Marketable Equity Securities $ 52.5 $ 8.0 $(0.1) $ 60.4
U.S. Government agency 18.1 0.3 -- 18.4
State municipal bonds 73.6 2.2 (0.1) 75.7
---------------------------------------
Totals $144.2 $10.5 $(0.2) $154.5
- --------------------------------=======================================
Gross and net realized gains and losses on available-for-sale securities were as
follows:
1997 1996 1995
- ------------------------------------------------------------------
(IN MILLIONS)
Gross realized gains $9.3 $4.3 $5.5
Gross realized losses (0.6) (0.2) (2.5)
----------------------------------
Net realized gains $8.7 $4.1 $3.0
- --------------------------------==================================
The U.S. Government agency obligations and state municipal bonds (shown above)
mature on the following schedule:
AT DECEMBER 31, 1997 AMOUNT
- ---------------------------------------------------------------
(IN MILLIONS)
Less than 1 year $ 1.0
1-5 years 24.1
5-10 years 51.8
More than 10 years 5.9
-----
Total maturities of debt securities $82.8
- ---------------------------------------------------------=====
Baltimore Gas and Electric Company and Subsidiaries 51
Note 5. Regulatory Assets (net)
- --------------------------------------------------------------------------------
As discussed in Note 1, the Maryland PSC regulates our utility business.
Generally, we use the same accounting policies and practices used by
nonregulated companies for financial reporting under generally accepted
accounting principles. However, sometimes the Maryland PSC orders an accounting
treatment different from that used by nonregulated companies to determine the
rates we charge our customers. When this happens, we must defer certain utility
expenses and income in our Consolidated Balance Sheets as regulatory assets and
liabilities. We then record them in our Consolidated Statements of Income (using
amortization) when we include them in the rates we charge our customers.
We have recorded these regulatory assets and liabilities in our Consolidated
Balance Sheets in accordance with Statement of Financial Accounting Standards
No. 71, Accounting for the Effects of Certain Types of Regulation. If we were
required to terminate application of that statement for all of our regulated
operations, we would have to record the amounts of all regulatory assets and
liabilities in our Consolidated Statements of Income at that time. This means
our earnings would be reduced by the total net amount in the table below, net of
applicable income taxes.
We summarize our regulatory assets and liabilities in the following table, and
we discuss each of them separately below.
AT DECEMBER 31, 1997 1996
- ------------------------------------------------------------------
(IN MILLIONS)
Income taxes recoverable through future rates $256.5 $264.5
Deferred postretirement and
postemployment benefit costs 96.4 89.2
Deferred nuclear expenditures 77.7 82.1
Deferred energy conservation expenditures 55.8 46.7
Deferred costs of decommissioning
federal uranium enrichment facilities 42.4 46.0
Deferred environmental costs 38.8 47.7
Deferred termination benefit costs 21.0 41.1
Deferred fuel costs 4.4 22.7
Deferred investment tax credits (126.6) (133.9)
Other 4.3 6.2
----------------
Total regulatory assets (net) $470.7 $512.3
- --------------------------------------------------================
Income Taxes Recoverable Through Future Rates
As described in Note 1, income taxes recoverable through future rates are the
portion of our deferred income tax liability that is applicable to our utility
business, but has not been reflected in the rates we charge our customers. These
income taxes represent the tax effect of temporary differences in depreciation
and the allowance for equity funds used during construction, offset by
differences in deferred tax rates and deferred taxes on deferred investment tax
credits (discussed later in this note). We amortize these amounts as the
temporary differences reverse.
Deferred Postretirement and Postemployment Benefit Costs
Deferred postretirement and postemployment benefit costs are the costs we
recorded under Statements of Financial Accounting Standards No. 106 (for
postretirement benefits) and No. 112 (for postemployment benefits) in excess of
the costs we included in the rates we charge our customers. We will amortize
these costs over a 15-year period beginning in 1998. We discuss these costs
further in Note 6.
Deferred Nuclear Expenditures
Deferred nuclear expenditures are the net unamortized balance of certain
operations and maintenance costs at Calvert Cliffs. These expenditures consist
of:
o costs incurred from 1979 through 1982 for inspecting and repairing seismic
pipe supports,
o expenditures incurred from 1989 through 1994 associated with nonrecurring
phases of certain nuclear operations projects, and
o expenditures incurred during 1990 for investigating leaks in the
pressurizer heater sleeves.
We are amortizing these costs over the remaining life of the plant in accordance
with the Maryland PSC's orders.
Deferred Energy Conservation Expenditures
Deferred energy conservation expenditures include two components:
o operations costs (labor, materials, and indirect costs) associated with
energy conservation programs approved by the Maryland PSC, which we are
amortizing over five years in accordance with the Maryland PSC's orders,
and
o revenues we collected from customers in 1996 in excess of our profit limit
under the energy conservation surcharge.
The Maryland PSC allows us to collect from customers money spent on conservation
programs under an "energy conservation surcharge." However, under this surcharge
the Maryland PSC limits what our profit can be. If, at the end of the year, we
have exceeded our allowed profit, we lower the amount of future surcharges to
our customers to correct the amount of overage, plus interest.
During 1996, we exceeded our profit limit under the energy conservation
surcharge. As a result, we deferred $28.5 million of our 1996 revenue from
surcharge billings as a regulatory liability. To correct the overage, we lowered
the surcharge on our customers' bills from July 1997 to June 1998.
Deferred Costs of Decommissioning Federal Uranium Enrichment Facilities
Deferred costs of decommissioning federal uranium enrichment facilities are the
unamortized portion of our required contributions to a fund for decommissioning
and decontaminating the Department of Energy's uranium enrichment facilities. We
are required, along with other domestic utilities, by the Energy Policy Act of
1992 to make contributions to the fund. The contributions are generally payable
over 15 years with escalation for inflation and are based upon the proportionate
amount of uranium enriched by the Department of Energy for each utility. We are
amortizing these costs over the contribution period as a cost of fuel. We also
discuss this in Note 1.
Deferred Environmental Costs
Deferred environmental costs are the estimated costs of investigating and
cleaning up contaminated sites we own. We discuss this further in Note 12. We
are amortizing $21.6 million of these costs (the amount we had incurred through
October 1995) over a 10-year period in accordance with the Maryland PSC's
November 1995 order.
52 Baltimore Gas and Electric Company and Subsidiaries
Deferred Termination Benefits
Deferred termination benefit costs are the net unamortized balance of the cost
of certain termination benefits offered to employees of our regulated utility
operations. We describe these termination benefits further in Note 7. We are
amortizing these costs over a five-year period in accordance with the Maryland
PSC's orders.
Deferred Fuel Costs
As described in Note 1, deferred fuel costs are the difference between our
actual costs of electric fuel, net purchases and sales of electricity, and
natural gas and our fuel rate revenues collected from customers. We reduce
deferred fuel costs as we collect them from customers.
We show our deferred fuel costs in the following table.
AT DECEMBER 31, 1997 1996
- ------------------------------------------------------------------
(IN MILLIONS)
Electric deferred fuel costs
Costs deferred (over-recovered) $(19.0) $113.2
Disallowed replacement
energy costs (see Note 12) -- (118.0)
---------------------
Net electric deferred (over-
recovered) fuel costs (19.0) (4.8)
Gas deferred fuel costs 23.4 27.5
---------------------
Total deferred fuel costs $ 4.4 $ 22.7
- ---------------------------------------------=====================
Deferred Investment Tax Credits
As described in Note 1, deferred investment tax credits are investment tax
credits associated with our regulated utility business. Under federal income tax
regulations, we do not deduct deferred investment tax credits from rate base.
Note 6. Pension, Postretirement, Other Postemployment, and Employee Savings Plan
Benefits
- --------------------------------------------------------------------------------
We offer pension, postretirement, other postemployment, and employee savings
plan benefits. We describe each of these separately below.
Pension Benefits
We sponsor several defined benefit pension plans for our employees. A defined
benefit plan specifies the amount of benefits a plan participant is to receive
using information about the participant. Our largest plan covers nearly all BGE
employees and certain employees of our subsidiaries. Our other plans, which are
not material in amount, provide supplemental benefits to certain key employees.
Our employees do not contribute to these plans. Generally, we calculate the
benefits under these plans based on age, years of service, and pay.
Sometimes we amend the plans retroactively. These retroactive plan amendments
require us to recalculate benefits related to participants' past service. We
amortize the change in the benefit costs from these plan amendments on a
straight-line basis over the average remaining service period of active
employees. We fund the plans by contributing at least the minimum amount
required under Internal Revenue Service regulations. We calculate the amount of
funding using an actuarial method called the projected unit credit cost method.
The assets in all of the plans at December 31, 1997 were mostly marketable
equity and fixed income securities, and group annuity contracts.
We show the funded status of all of the plans in the following table.
AT DECEMBER 31, 1997 1996
- ------------------------------------------------------------------
(IN MILLIONS)
Vested benefit obligation $ 702.0 $695.6
Nonvested benefit obligation 40.0 18.0
------------------
Accumulated benefit obligation 742.0 713.6
Projected benefits related to
increase in future compensation levels 160.0 132.7
------------------
Projected benefit obligation 902.0 846.3
Plan assets at fair value (912.3) (792.5)
------------------
Projected benefit obligation less plan assets (10.3) 53.8
Unrecognized prior service cost (19.4) (21.9)
Unrecognized net loss (84.2) (117.2)
Unamortized net asset from
adoption of FASB Statement No. 87 0.9 0.8
------------------
Accrued pension asset $(113.0) $ (84.5)
- ------------------------------------------------==================
We show the components of total net pension cost in the following table. We do
not include the cost of termination benefits described in Note 7 in net pension
cost.
YEAR ENDED DECEMBER 31, 1997 1996 1995
- ------------------------------------------------------------------
(IN MILLIONS)
Service cost-benefits
earned during the period $16.8 $16.1 $11.4
Interest cost on projected
benefit obligation 61.3 59.9 58.4
Actual return on plan assets (130.0) (57.7) (150.5)
Net amortization and deferral 70.0 2.1 94.7
------------------------------
Total net pension cost 18.1 20.4 14.0
Amount capitalized as
construction cost (2.5) (2.4) (1.4)
------------------------------
Total net pension cost
charged to expense $15.6 $18.0 $12.6
- ------------------------------------==============================
Postretirement Benefits
We sponsor defined benefit postretirement health care and life insurance plans
which cover nearly all BGE employees and certain employees of our subsidiaries.
Generally, we calculate the benefits under these plans based on age, years of
service, and pension benefit levels. We do not fund these plans.
For nearly all of the health care plans, retirees make contributions to cover a
portion of the plan costs. Contributions for employees who retire after June 30,
1992 are calculated based on age and years of service. The amount of retiree
contributions increase based on expected increases in medical costs. For the
life insurance plan, retirees do not make contributions to cover a portion of
the plan costs.
Effective January 1, 1993, we adopted Statement of Financial Accounting
Standards No. 106, Employers' Accounting for Postretirement Benefits Other Than
Pensions. The adoption of that statement caused:
o a transition obligation, which we are amortizing over 20 years, and
o an increase in annual postretirement benefit costs, which we discuss later
in this note.
Baltimore Gas and Electric Company and Subsidiaries 53
For our diversified businesses, we expense all postretirement benefit costs. For
our regulated utility business, we accounted for the increase in annual
postretirement benefit costs under two Maryland PSC rate orders:
o In an April 1993 rate order, the Maryland PSC allowed us to expense
one-half and defer, as a regulatory asset (see Note 5), the other half of
the increase in annual postretirement benefit costs related to our utility
business.
o In a November 1995 rate order, the Maryland PSC allowed us to expense all
of the increase in annual postretirement benefit costs related to our gas
business.
Beginning in 1998, the Maryland PSC authorized us to:
o expense all of the increase in annual postretirement benefit costs related
to our electric business, and
o amortize the regulatory asset for postretirement benefit costs related to
our utility business over 15 years.
The Maryland PSC authorized us to reflect these changes in our current electric
base rates and will adjust our gas base rates to recover the higher costs that
will be recognized in 1998.
Our treatment of the increase in annual postretirement benefit costs meets
guidelines established by the Emerging Issues Task Force of the Financial
Accounting Standards Board for deferring postretirement benefit costs as a
regulatory asset.
We show the components of the accumulated postretirement benefit obligation and
a reconciliation of these amounts to the accrued postretirement benefit
liability in the following table.
AT DECEMBER 31, 1997 1996
- -------------------------------------------------------------------
Health Life Health Life
Care Insurance Care Insurance
- -------------------------------------------------------------------
(IN MILLIONS)
Accumulated postretirement
benefit obligation:
Retirees $164.5 $47.3 $163.9 $45.5
Active employees 87.7 20.8 82.4 19.3
---------------------------------
Total accumulated post-
retirement benefit obligation 252.2 68.1 246.3 64.8
Unrecognized transition
obligation (132.2) (38.4) (141.1) (41.0)
Unrecognized net loss (3.8) (7.1) (7.4) (5.7)
---------------------------------
Accrued postretirement
benefit liability $116.2 $22.6 $ 97.8 $18.1
- ----------------------------------=================================
We show the components of net postretirement benefit cost in the following
table. We do not include the cost of termination benefits described in Note 7 in
net postretirement benefit cost.
YEAR ENDED DECEMBER 31, 1997 1996 1995
- ------------------------------------------------------------------
(IN MILLIONS)
Service cost--benefits earned
during the period $ 5.4 $ 5.5 $ 3.9
Interest cost on accumulated post
retirement benefit obligation 21.8 21.9 21.2
Amortization of transition obligation 11.4 11.4 11.4
Net amortization and deferral 0.1 0.2 (0.1)
-------------------------
Total net postretirement benefit cost 38.7 39.0 36.4
Amount capitalized
as construction cost (7.6) (6.2) (5.3)
Amount deferred (7.2) (7.4) (8.0)
-------------------------
Total net postretirement benefit
cost charged to expense $23.9 $25.4 $23.1
- ------------------------------------------========================
Other Postemployment Benefits
We provide the following postemployment benefits:
o health and life insurance benefits to our employees and certain employees
of our subsidiaries who are found to be disabled under our Disability
Insurance Plan, and
o income replacement payments for employees found to be disabled before
November 1995 (payments for employees found to be disabled after that date
are paid by an insurance company, and the cost is paid by employees).
The liability for these benefits totaled $45.4 million as of December 31, 1997
and $50.8 million as of December 31, 1996.
Effective December 31, 1993, we adopted Statement of Financial Accounting
Standards No. 112, EMPLOYERS' ACCOUNTING FOR POSTEMPLOYMENT BENEFITS. The
portion of the liability attributable to regulated activities as of December 31,
1993 was deferred as a regulatory asset (see Note 5), consistent with the
Maryland PSC's orders for postretirement benefits (described earlier in this
note). We will amortize the regulatory asset over 15 years beginning in 1998.
The Maryland PSC authorized us to reflect this change in our current electric
base rates and will adjust our gas base rates to recover the higher costs that
will be recognized in 1998.
Assumptions
We made the assumptions below to calculate the pension, postretirement, and
other postemployment benefit liabilities.
AT DECEMBER 31, 1997 1996
- -----------------------------------------------------------------
Discount rate
Pension and postretirement benefits 7.25% 7.5%
Other postemployment benefits 6.0 6.0
Average increase in
future compensation levels 4.0 4.0
Expected long-term rate of
return on assets 9.0 9.0
We assumed the health care inflation rates to be:
o in 1997, 6.0% for both Medicare-eligible retirees and retirees not covered
by Medicare, and
o in 1998, 8.0% for Medicare-eligible retirees and 9.5% for retirees not
covered by Medicare.
After 1998, we assumed both rates will decrease by 0.5% annually to a rate of
5.5% in the years 2003 and 2006. A one-percent increase in the health care
inflation rate from the assumed rates would increase the accumulated
postretirement benefit obligation by approximately $40 million as of December
31, 1997 and would increase the combined service and interest costs of the
postretirement benefit cost by approximately $4 million annually.
Employee Savings Plan Benefits
We also sponsor a defined contribution savings plan that is offered to all
eligible BGE employees and certain employees of our subsidiaries. In a defined
contribution plan, the benefits a participant is to receive result from regular
contributions to a participant account. Under this plan, we make matching
contributions to participant accounts. We made matching contributions to this
plan of:
o $8.5 million in 1997,
o $9.4 million in 1996, and
o $8.5 million in 1995.
54 Baltimore Gas and Electric Company and Subsidiaries
Note 7. Termination Benefits
- --------------------------------------------------------------------------------
Termination Benefits Offered in 1992
We offered a Voluntary Special Early Retirement Program to eligible employees
who retired from February 1, 1992 through April 1, 1992. The termination
benefits of this program cost $6.6 million and consisted mostly of an enhanced
pension benefit. We are amortizing the cost of these benefits over a five-year
period in accordance with the Maryland PSC's April 1993 order.
Termination Benefits Offered in 1993
We offered a second Voluntary Special Early Retirement Program to eligible
employees who retired as of February 1, 1994. The termination benefits of this
program consisted mostly of enhanced pension and postretirement benefits. As
part of this program, we accomplished further employee reductions by eliminating
positions, and offering additional benefits to employees affected by the
eliminations. We deferred $88.3 million of the costs of this program that were
attributable to regulated activities. We are amortizing these costs over a
five-year period, consistent with the Maryland PSC's previous orders.
Note 8. Short-Term Borrowings
- --------------------------------------------------------------------------------
SUMMARY OF SHORT-TERM BORROWINGS
Our short-term borrowings include bank loans, commercial paper notes, and bank
lines of credit. Short-term borrowings mature within one year from the date of
the financial statements. We pay commitment fees to banks for providing us lines
of credit. When we borrow under the lines of credit, we pay market interest
rates.
We summarize our short-term borrowings in the following table.
AT DECEMBER 31, 1997 1996
- ---------------------------------------------------------------
(IN MILLIONS)
BGE's bank loans $ -- $ 8.8
BGE's commercial paper notes 316.1 324.4
----------------------
Total short-term borrowings $316.1 $333.2
- ------------------------------------------=====================
We had unused bank lines of credit supporting our commercial paper notes of $231
million at December 31, 1997 and $203 million at December 31, 1996. These
amounts do not include unused revolving credit agreements of $100 million at
December 31, 1997 and $150 million at December 31, 1996 that are discussed in
Note 9.
Weighted-Average Interest Rates
Our weighted average effective interest rates for short-term borrowings were as
follows:
YEAR ENDED DECEMBER 31, 1997 1996
- ------------------------------------------------------------------
Bank loans 5.00% 4.93%
Commercial Paper Notes 5.66 5.53
Note 9. Long-Term Debt
- --------------------------------------------------------------------------------
Long-term debt matures more than one year from the date of the financial
statements. We summarize our long-term debt in the Consolidated Statements of
Capitalization on page 43. As you read this section, it may be helpful to refer
to those statements. We discuss BGE's, the Constellation Holdings Companies',
and other diversified businesses' long-term debt separately below.
BGE's Long-Term Debt
BGE's First Refunding Mortgage Bonds
BGE's first refunding mortgage bonds are secured by a mortgage lien on nearly
all of our assets, including all utility properties and franchises and our
subsidiary capital stock. Our subsidiary capital stock pledged under the
mortgage includes that of:
o Constellation Holdings, Inc.,
o Constellation Energy Solutions, Inc.,
o BGE Home Products & Services, Inc., and
o Safe Harbor Water Power Corporation.
BGE is required to make an annual sinking fund payment each August 1 to the
mortgage trustee. The amount of the payment is equal to 1% of the highest
principal amount of bonds outstanding during the preceding 12 months. The
trustee uses these funds to retire bonds from any series through repurchases or
calls for early redemption. However, the trustee cannot call the following bonds
for early redemption:
o 5 1/2% Installment Series, due 2002 o 6 1/2% Series, due 2003
o 8.40% Series, due 1999 o 6 1/8% Series, due 2003
o 5 1/2% Series, due 2000 o 5 1/2% Series, due 2004
o 8 3/8% Series, due 2001 o 7 1/2% Series, due 2007
o 7 1/4% Series, due 2002 o 6 5/8% Series, due 2008
We must pay principal on the 5 1/2% Installment Series as follows:
YEAR
- ---------------------------------------------------------------
(IN MILLIONS)
1998 and 1999 $ 0.7
2000 and 2001 0.9
2002 6.7
Holders of the Remarketed Floating Rate Series Due September 1, 2006 have the
option to require BGE to repurchase their bonds at face value on September 1 of
each year. BGE is required to repurchase and retire at par any bonds that are
not remarketed or purchased by the remarketing agent. BGE also has the option to
redeem all or some of these bonds at face value each September 1.
BGE's Other Long-Term Debt
BGE has $100 million of revolving credit agreements with several banks that are
available through 2000. At December 31, 1997, BGE had no outstanding borrowings
under these agreements. These banks charge us commitment fees based on the daily
average of the unborrowed amount, and we pay market interest rates on any
borrowings. These agreements also serve as back-up credit support for BGE's
commercial paper notes, as described in Note 8.
Baltimore Gas and Electric Company and Subsidiaries 55
We show the weighted-average interest rates and maturity dates for BGE's
fixed-rate medium-term notes outstanding at December 31, 1997 in the following
table.
Weighted-Average
Series Interest Rate Maturity Dates
- ---------------------------------------------------------------
B 8.43% 1998-2006
C 7.15% 1998-2003
D 6.36% 1998-2006
E 6.70% 2006-2012
Some of the medium-term notes include a "put option." These put options allow
the holders to sell their notes back to BGE on the put option dates at a price
equal to 100% of the principal amount. The following is a summary of medium-term
notes with put options.
Series E Notes Principal Put Option Dates
- --------------------------------------------------------------
(IN MILLIONS)
6.75%, due 2012 $60.0 June 2002 and 2007
6.75%, due 2012 $25.0 June 2004 and 2007
6.73%, due 2012 $25.0 June 2004 and 2007
Constellation Holdings Companies' Long-Term Debt
Revolving Credit Agreement
The Constellation Holdings Companies have a $75 million unsecured revolving
credit agreement that matures December 9, 1999, which they use to provide
liquidity for general corporate purposes. The Constellation Holdings Companies
pay a commitment fee based on the daily average of the unborrowed portion of the
commitment. At December 31, 1997, the Constellation Holdings Companies had no
outstanding borrowings under this agreement.
Mortgage and Construction Loans
The Constellation Holdings Companies' mortgage and construction loans and other
collateralized notes have varying terms. The following mortgage notes require
monthly principal and interest payments:
o 7.90%, due in 2000 o 7.357%, due in 2009
o 8.00%, due in 2001 o 9.65%, due in 2028
o 7.50%, due in 2005
The 8.00% mortgage note due in 2003 requires interest payments until maturity.
The variable rate mortgage notes require periodic payment of principal and
interest. The 8.00% mortgage note due in 2033, requires interest payments
initially then monthly principal and interest payments.
Unsecured Notes
The unsecured notes mature on the following schedule:
Amount
- ---------------------------------------------------------------
(IN MILLIONS)
7.05%, due April 22, 1998 $ 25.0
7.06%, due September 9, 1998 20.0
8.48%, due October 15, 1998 75.0
7.30%, due April 22, 1999 90.0
8.73%, due October 15, 1999 15.0
7.125%, due March 13, 2000 15.0
7.55%, due April 22, 2000 35.0
7.50%, due May 5, 2000 139.0
7.43%, due September 9, 2000 30.0
7.66%, due May 5, 2001 135.0
8.00%, due December 31, 2000 0.1
-------
Total unsecured notes at December 31, 1997 $579.1
- ---------------------------------------------------------======
Other Diversified Businesses' Long-Term Debt
ComfortLink, a general partnership in which BGE is a partner, has a $50 million
unsecured revolving credit agreement that matures September 26, 2001. Under the
terms of the agreement, ComfortLink has the option to obtain loans at various
rates for terms up to nine months. ComfortLink pays a facility fee on the total
amount of the commitment. At December 31, 1997, ComfortLink had $22 million
outstanding under this agreement.
Constellation Energy Source has a $10 million revolving credit agreement that
matures February 1, 2000. At December 31, 1997, Constellation Energy Source had
no outstanding borrowings under this agreement.
Maturities of Long-Term Debt
All of our long-term borrowings mature on the following schedule (includes
sinking fund requirements):
Diversified
YEAR BGE Businesses
- -------------------------------------------------------
(IN MILLIONS)
1998 $ 93.6 $155.3
1999 334.5 131.9
2000 253.8 244.5
2001 198.6 185.0
2002 156.2 2.8
Thereafter 1,455.4 39.9
-------------------------------
Total long-term debt
at December 31, 1997 $2,492.1 $759.4
- ------------------------===============================
At December 31, 1997, BGE had long-term loans totaling $255 million that mature
after 2002 that lenders could potentially require us to repay early. Of this
amount, $145 million could potentially be repaid in 1998, $60 million could be
repaid in 2002, and $50 million could be repaid thereafter. We have the ability
and intent to refinance such debt by issuing medium-term notes or by borrowing
under our revolving credit agreements, if necessary.
Weighted Average Interest Rates for Variable Rate Debt
Our weighted average interest rates for variable rate debt were:
YEAR ENDED DECEMBER 31, 1997 1996
- -----------------------------------------------------------------
BGE
Floating rate series mortgage bonds 6.11% 5.87%
Remarketed floating rate
series mortgage bonds 5.75 5.63
Medium-term notes, series D 5.78 --
Pollution control loan 3.63 3.49
Port facilities loan 3.71 3.59
Adjustable rate pollution control loan 3.90 3.90
Economic development loan 3.69 3.57
Variable rate pollution control loan 3.73 --
CONSTELLATION HOLDINGS COMPANIES
Loans under credit agreement 5.99 6.08
Mortgage and construction loans
and other collateralized notes 8.10 8.33
OTHER DIVERSIFIED BUSINESSES
Loans under credit agreement 6.04 6.13
56 Baltimore Gas and Electric Company and Subsidiaries
Note 10. Redeemable Preference Stock
- --------------------------------------------------------------------------------
PRIORITY
For the payment of dividends and in the event of liquidation of BGE, we rank
preference stock prior to common stock. We rank all preference stock equally.
Sinking Fund Redemptions
Required Sinking Fund Redemptions
Some of our preference stock issues have annual sinking fund requirements. Under
those requirements, we must redeem some of our preference stock at $100 per
share annually. We summarize the redemptions required in the following table.
Beginning
Series Shares Year
- --------------------------------------------------------------
7.50%, 1986 Series 15,000 1992
6.75%, 1987 Series 15,000 1993
8.625%, 1990 Series 130,000 1996
7.85%, 1991 Series 70,000 1997
The following table summarizes the annual required redemptions of all redeemable
preference stock.
YEAR
- --------------------------------------
(IN MILLIONS)
1998 $ 23.0
1999 10.0
2000 10.0
2001 3.0
2002 3.0
Thereafter 64.0
------
Total required redemptions $113.0
- --------------------------------======
Optional Sinking Fund Redemptions
For each series, we have the option to redeem shares in addition to the annual
sinking fund requirements. Each year, we may redeem an amount up to the required
annual number of sinking fund shares at $100 per share.
Other Redemptions
We also have the option to fully redeem the 7.50%, 1986 Series, and the 6.75%,
1987 Series, at the prices shown in the Consolidated Statements of
Capitalization on page 44.
Note 11. Leases
- --------------------------------------------------------------------------------
There are two types of leases--operating and capital. Capital leases qualify as
sales or purchases of property and are reported in the Consolidated Balance
Sheets. All other leases are operating leases and are reported in the
Consolidated Statements of Income. We present information about our operating
leases below.
Outgoing Lease Payments
We, as lessee, lease some facilities and equipment used in our business. The
lease agreements expire on various dates and have various renewal options. We
expense all lease payments associated with our regulated utility operations.
Lease expense was:
o $9.5 million in 1997,
o $11.6 million in 1996, and
o $12.2 million in 1995.
At December 31, 1997, we owed future minimum payments for long-term
noncancelable operating leases as follows:
YEAR
- --------------------------------------------------
(IN MILLIONS)
1998 $ 5.9
1999 3.6
2000 3.3
2001 2.8
2002 2.3
Thereafter 5.6
-----
Total future minimum lease payments $23.5
- ---------------------------------------------=====
Incoming Lease Rentals
Some Constellation Holdings Companies, as landlords, lease office and retail
space to others. These operating leases expire over periods ranging from one to
20 years, and have options to renew. At December 31, 1997, the Constellation
Holdings Companies had property under operating leases with a net book value of
$184.9 million.
At December 31, 1997, tenants owed the Constellation Holdings Companies future
minimum rentals under operating leases as follows:
YEAR
- ---------------------------------------------------
(IN MILLIONS)
1998 $ 17.9
1999 18.1
2000 17.7
2001 16.2
2002 14.6
Thereafter 63.1
------
Total future minimum lease rentals $147.6
- ---------------------------------------------======
Baltimore Gas and Electric Company and Subsidiaries 57
Note 12. Commitments, Guarantees, and Contingencies
- --------------------------------------------------------------------------------
Commitments
We have made substantial commitments in connection with our utility construction
program for future years. In addition, we have entered into three long-term
contracts for the purchase of electric generating capacity and energy. The
contracts expire in 2001, 2013, and 2023. We made payments under these contracts
of:
o $65.6 million in 1997,
o $64.1 million in 1996, and
o $68.4 million in 1995.
At December 31, 1997, we estimate our future payments for capacity and energy
that we are obligated to buy under these contracts to be:
YEAR
- ---------------------------------------------------------------
(IN MILLIONS)
1998 $ 81.4
1999 92.2
2000 92.8
2001 63.2
2002 42.1
Thereafter 765.3
--------
Total estimated future payments for
capacity and energy under long-term contracts $1,137.0
- -------------------------------------------------------========
Some Constellation Holdings Companies have committed to contribute additional
capital and to make additional loans to some affiliates, joint ventures, and
partnerships in which they have an interest. At December 31, 1997, the total
amount of investment requirements committed to by the Constellation Holdings
Companies was $35 million.
In December, 1994, BGE and BGE Home Products & Services entered into agreements
with a financial institution to sell on an ongoing basis an undivided interest
in a designated pool of customer receivables. Under the agreements, BGE can sell
up to a total of $40 million, and BGE Home Products & Services can sell up to a
total of $50 million. Under the terms of the agreements, the buyer of the
receivables has limited recourse against BGE and has no recourse against BGE
Home Products & Services. BGE and BGE Home Products & Services have recorded a
reserve for credit losses. At December 31, 1997, BGE had sold $35 million and
BGE Home Products & Services had sold $47 million of receivables under these
agreements.
Guarantees
BGE guarantees two-thirds of certain debt of Safe Harbor Water Power
Corporation. The maximum amount of our guarantee is $23 million. At December 31,
1997, Safe Harbor Water Power Corporation had outstanding debt of $30 million,
of which $20 million is guaranteed by BGE.
BGE also issued an $11 million guaranty for debt under the revolving credit
agreement of Constellation Energy Source. At December 31, 1997, Constellation
Energy Source had no outstanding borrowings under this agreement.
At December 31, 1997, the Constellation Holdings Companies had guaranteed
outstanding loans and letters of credit of certain power generation and real
estate projects totaling $46 million. Also, the Constellation Holdings Companies
guarantee certain other borrowings of various power generation and real estate
projects.
We assess the risk of material loss from these guarantees to be minimal.
Termination of Proposed Merger With
Potomac Electric Power Company
As previously disclosed, in September 1995 we signed an agreement with Potomac
Electric Power Company to merge together into a new company, Constellation
Energy Corporation, after all necessary regulatory approvals were received. In
December 1997, both companies mutually terminated the merger agreement.
Accordingly, in 1997, we wrote off $57.9 million of costs related to the merger.
We have reported the write-off as "write-off of merger costs" in our
Consolidated Statements of Income. This write-off reduced after-tax earnings by
$37.5 million.
Environmental Matters
Clean Air
The Clean Air Act of 1990 contains two titles designed to reduce emissions of
sulfur dioxide and nitrogen oxide (NOx) from electric generating stations -
Title IV and Title I.
Title IV addresses emissions of sulfur dioxide. Compliance is required in two
phases:
o Phase I became effective January 1, 1995. We met the requirements of this
phase by installing flue gas desulfurization systems (scrubbers), switching
fuels, and retiring some units.
o Phase II must be implemented by 2000. We are currently examining what
actions we should take to comply with this phase. We expect to meet the
compliance requirements through some combination of installing flue gas
desulfurization systems (scrubbers), switching fuels, retiring some units,
or allowance trading.
Title I addresses emissions of NOx, but the regulations of this title have not
been finalized by the government. As a result, our plans for complying with this
title are less certain. By 1999 the regulations require more NOx controls for
ozone attainment at our generating plants. The additional controls will result
in more expenditures, but it is difficult to estimate the level of those
expenditures since the regulations have not been finalized. However, based on
existing and proposed regulations, we currently estimate that the additional
controls at our generating plants will cost approximately $90 million.
In July 1997, the government published new National Ambient Air Quality
Standards for very fine particulates and revised standards for ozone attainment.
These standards may require increased controls at our fossil generating plants
in the future. We cannot estimate the cost of these increased controls at this
time because the states, including Maryland, still need to determine what
reductions in pollutants will be necessary to meet the federal standards.
Waste Disposal
The Environmental Protection Agency and several state agencies have notified us
that we are considered a potentially responsible party with respect to the
cleanup of certain environmentally contaminated sites owned and operated by
others. We cannot estimate the cleanup costs for all of these sites. We can,
however, estimate that our 15.79% share of the possible cleanup costs at one of
these sites, Metal Bank of America (a metal reclaimer in Philadelphia) could be
approximately $7 million higher than amounts we have recorded. This estimate is
based on the highest estimate of costs in the range of reasonably possible
alternatives. The cleanup costs for some of the remaining sites
58 Baltimore Gas and Electric Company and Subsidiaries
could be significant, but we do not expect them to have a material effect on our
financial position or results of operations.
Also, we are investigating several sites where gas was manufactured in the past.
The investigation of these sites includes reviewing possible actions to remove
coal tar. In late December 1996, we signed a consent order with the Maryland
Department of the Environment that requires us to implement remedial action
plans for contamination at and around the Spring Gardens site. We have submitted
the required remedial action plans and the Maryland Department of the
Environment is in the process of reviewing them. Based on several remedial
action options for all sites, the costs we consider to be probable to remedy the
contamination are estimated to total $50 million in nominal dollars (including
inflation). We have recorded these costs as a liability on our Consolidated
Balance Sheets and have deferred these costs, net of accumulated amortization
and amounts we recovered from insurance companies, as a regulatory asset. We
discuss this further in Note 5. We are also required by accounting rules to
disclose additional costs we consider to be less likely than probable costs, but
still "reasonably possible" of being incurred at these sites. Because of the
results of studies at these sites, it is reasonably possible that these
additional costs could exceed the amount we recognized by approximately $48
million in nominal dollars ($11 million in current dollars, plus the impact of
inflation at 3.1% over a period of up to 60 years).
Nuclear Insurance
If there were an accident or an extended outage at either unit of Calvert
Cliffs, it could have a substantial adverse financial effect on BGE. The primary
contingencies that would result from an incident at Calvert Cliffs could
include:
o the physical damage to the plant,
o the recoverability of replacement power costs, and
o our liability to third parties for property damage and bodily injury.
We have insurance policies that cover these contingencies, but the policies have
certain exclusions. Furthermore, the costs that could result from a covered
major accident or a covered extended outage at either of the Calvert Cliffs
units could exceed our insurance coverage limits.
For physical damage to Calvert Cliffs, we have $2.75 billion of property
insurance from an industry mutual insurance company. If an outage at either of
the two units at Calvert Cliffs is caused by an insured physical damage loss and
lasts more than 17 weeks, we have insurance coverage for replacement power costs
up to $487.2 million per unit, provided by an industry mutual insurance company.
This amount can be reduced by up to $94.6 million per unit if an outage to both
units at the plant is caused by a single insured physical damage loss. If
accidents at any insured plants cause a shortfall of funds at the industry
mutual, all policyholders could be assessed with our share being up to $31
million.
In addition we, as well as others, could be charged for a portion of any third
party claims associated with a nuclear incident at any commercial nuclear power
plant in the country. Under the provisions of the Price Anderson Act, the limit
for third party claims from a nuclear incident is $8.92 billion. If third party
claims exceed $200 million (the amount of primary insurance), our share of the
total liability for third party claims could be up to $159 million per incident.
That amount would be payable at a rate of $20 million per year.
As an operator of a commercial nuclear power plant in the United States, we are
required to purchase insurance to cover radiation injury claims of certain
nuclear workers. On January 1, 1998, a new insurance policy became effective for
all operators requiring coverage for current operations. Waiving the right to
make additional claims under the old policy was a condition for acceptance under
the new policy. We describe both the old and new policies below.
o BGE nuclear worker claims reported on or after January 1, 1998 are covered
by a new insurance policy with an annual industry aggregate limit of $200
million for radiation injury claims against all operators insured by this
policy.
o All nuclear worker claims reported prior to January 1, 1998 are still
covered by the old insurance policies. Insureds under the old policies,
with no current operations, are not required to purchase the new policy
described above, and may still make claims against the old policies for the
next 10 years. If radiation injury claims under these old policies exceed
the policy reserves, all policyholders could be assessed, with our share
being up to $6.3 million.
If claims under these polices exceed the coverage limits, the provisions of the
Price Anderson Act (discussed above) would apply.
Recoverability of Electric Fuel Costs
By law, we are allowed to recover our cost of electric fuel as long as the
Maryland PSC finds that, among other things, we have kept the productive
capacity of our generating plants at a reasonable level. To do this, the
Maryland PSC will perform an evaluation of each outage (other than regular
maintenance outages) at our generating plants. The evaluation will determine if
we used all reasonable and cost-effective maintenance and operating control
procedures to try to prevent the outage.
Effective January 1, 1987, the Maryland PSC established a Generating Unit
Performance Program to measure, annually, whether we, and other utilities, have
maintained the productive capacity of our generating plants at reasonable
levels. To do this, the program uses a system-wide generating performance target
and an individual performance target for each base load generating unit. In fuel
rate hearings, actual generating performance adjusted for planned outages will
be compared first to the system-wide target. If that target is met, it should
mean that the requirements of Maryland law have been met. If the system-wide
target is not met, each unit's adjusted actual generating performance will be
compared to its individual performance target to determine if the requirements
of Maryland law have been met and, if not, to determine the basis for possibly
imposing a penalty on BGE. Even if we meet these targets, other parties to fuel
rate hearings may still question whether we used all reasonable and
cost-effective procedures to try to prevent an outage. If the Maryland PSC
decides that we were deficient in some way, the Maryland PSC may not allow us to
recover the cost of replacement energy.
The two units at Calvert Cliffs use the cheapest fuel. As a result, the costs of
replacement energy associated with outages at these units can be significant. We
cannot estimate the amount of replacement energy costs that could be challenged
or disallowed in future fuel rate proceedings, but such amounts could be
material.
Baltimore Gas and Electric Company and Subsidiaries 59
During 1989 through 1991 we had extended outages at Calvert Cliffs. These
outages drove up fuel costs, and resulted in fuel rate proceedings before the
Maryland PSC for several years. In these proceedings, the Maryland PSC
considered whether any portion of the extra fuel costs should be charged to BGE
instead of passed on to customers.
In December 1996, we settled the proceedings by agreeing not to bill our
customers for $118 million of electric replacement energy costs associated with
these outages. All costs associated with the outages in excess of $118 million
have already been collected from customers through the fuel rate. In 1990, we
wrote off $35 million of these costs. In 1996, we wrote off the remaining $83
million plus $5.6 million of related financing charges. The 1996 write-offs,
together, reduced after-tax earnings by $57.6 million.
Also in 1996, we wrote off $6.8 million of fuel costs related to earlier outages
that were disallowed by the Maryland PSC. This write-off reduced 1996 after-tax
earnings by $4.5 million.
We have reported all of the 1996 write-offs as "disallowed replacement energy
costs" in our Consolidated Statements of Income.
California Power Purchase Agreements
The Constellation Holdings Companies have $261 million invested in 16 projects
that sell electricity in California under power purchase agreements called
"Interim Standard Offer No. 4" agreements. Earnings from these projects were
$37.3 million, or $.25 per share, in 1997.
Under these agreements, the projects supply electricity to utility companies at:
o a fixed rate for capacity and energy for the first 10 years of the
agreements, and
o a fixed rate for capacity plus a variable rate for energy based on the
utilities' avoided cost for the remaining term of the agreements.
Generally, a "capacity rate" is paid to a power plant for its availability to
supply electricity, and an "energy rate" is paid for the electricity actually
generated. "Avoided cost" generally is the cost of a utility's cheapest
next-available source of generation to service the demands on its system.
We use the term transition period to describe the timeframe when the 10-year
periods for fixed energy rates expire for these 16 power generation projects and
they begin supplying electricity at variable rates. The transition period for
some of the projects began in 1996 and will continue for the remaining projects
through 2000. At the date of this report, six projects had already transitioned
to variable rates and three other projects will transition in 1998. The
remaining seven projects will transition in 1999 or 2000.
The projects that have already transitioned to variable rates have had lower
revenues under variable rates than they did under fixed rates. However, we have
not yet experienced total lower earnings from the California projects because
the combined revenues from the remaining projects, which continued to supply
electricity at fixed rates, were high enough to offset the lower revenues from
the variable-rate projects. When the remaining projects transition to variable
rates, we expect the revenues from those projects to also be lower than they are
under fixed rates. It is difficult to estimate how much lower the revenues may
be, but the Constellation Holdings Companies' earnings could be affected
significantly. However, the California projects that make the highest revenues
will transition to variable rates in 1999 and 2000. As a result, we do not
expect the Constellation Holdings Companies to have significantly lower earnings
due to the transition to variable rates before 2000.
The Constellation Holdings Companies are pursuing alternatives for some of these
power generation projects including:
o repowering the projects to reduce operating costs,
o changing fuels to reduce operating costs,
o renegotiating the power purchase agreements to improve the terms,
o restructuring financings to improve the financing terms, and
o selling its ownership interests in the projects.
We cannot predict the financial effects of the switch from fixed to variable
rates on the Constellation Holdings Companies or on BGE, but the effects could
be material.
Constellation Real Estate
Most of the Constellation Holdings Companies' real estate projects are in the
Baltimore-Washington corridor. The area has had a surplus of available land and
office space in recent years, during a time of low economic growth and corporate
downsizings. The projects have been economically hurt by these conditions.
The Constellation Holdings Companies' real estate portfolio has continued to
incur carrying costs and depreciation over the years. Additionally, the
Constellation Holdings Companies have been charging interest payments to expense
rather than capitalizing them for some undeveloped land where development
activities have stopped. These carrying costs, depreciation, and interest
expenses have decreased earnings and are expected to continue to do so.
Cash flow from real estate operations has not been enough to make the monthly
loan payments on some of these projects. Cash shortfalls have been covered by
cash from Constellation Holdings. Constellation Holdings obtained those funds
from the cash flow from other Constellation Holdings Companies and through
additional borrowing.
We consider market demand, interest rates, the availability of financing, and
the strength of the economy in general when making decisions about our real
estate investments. If we were to sell our real estate projects in the current
market, we would have losses, although the amount of the losses is hard to
predict.
Management's current real estate strategy is to hold each real estate project
until we can realize a reasonable value for it. Management evaluates strategies
for all its businesses, including real estate, on an ongoing basis. We
anticipate that competing demands for our financial resources and changes in the
utility industry will cause us to evaluate thoroughly all diversified business
strategies on a regular basis so we use capital and other resources in a manner
that is most beneficial. Depending on market conditions in the future, we could
also have losses on any future sales.
60 Baltimore Gas and Electric Company and Subsidiaries
It may be helpful for you to understand when we are required, by accounting
rules, to write down the value of a real estate investment to market value. A
write-down is required in either of two cases. The first is if we change our
intent about a project from an intent to hold to an intent to sell and the
market value of that project is below book value. The second is if the expected
cash flow from the project is less than the investment in the project.
In 1997, the Constellation Holdings Companies recorded the following write-downs
of their investments in two projects:
o a $14.1 million after-tax write-down of the investment in Church Street
Station--an entertainment, dining, and retail complex in Orlando,
Florida--which occurred because the Constellation Holdings Companies have
now decided to sell rather than keep the project, and
o a $31.9 million after-tax write-down of the investment in Piney Orchard--a
mixed-use, planned-unit development--which occurred because the expected
cash flow from the project was less than the Constellation Holdings
Companies' investment in the project.
Note 13. Fair Value of Financial Instruments
- --------------------------------------------------------------------------------
We show the carrying amounts and fair values of financial instruments included
in our Consolidated Balance Sheets in the following table, and we describe some
of the items separately below.
AT DECEMBER 31, 1997 1996
- ----------------------------------------------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
- ----------------------------------------------------------------
(IN MILLIONS)
Cash and cash equivalents $162.6 $162.6 $66.7 $66.7
Net accounts receivable 419.8 419.8 419.5 419.5
Other current assets 128.8 128.8 75.0 75.0
Investments and other
assets for which it is:
Practicable to
estimate fair value 197.4 198.8 184.5 185.7
Not practicable to
estimate fair value 57.5 -- 62.2 --
Short-term borrowings 316.1 316.1 333.2 333.2
Current portions of long-term
debt and preference stock 271.9 271.9 280.8 280.8
Accounts payable 203.0 203.0 172.9 172.9
Other current liabilities 204.4 204.4 194.1 194.1
Deferred credits and
other liabilities 9.6 9.6 -- --
Long-term debt 2,988.9 3,069.8 2,758.8 2,767.7
Redeemable preference
stock 90.0 93.5 134.5 141.6
Other Current Assets and Other Current Liabilities
The financial instruments included in other current assets are trading
securities and miscellaneous loans receivable of the Constellation Holdings
Companies. The financial instruments included in other current liabilities are
the total current liabilities from our Consolidated Balance Sheets excluding
short-term borrowings, current portions of long-term debt and preference stock,
accounts payable, and accrued vacation costs. The carrying amounts of current
assets and current liabilities are the same as their fair values because these
instruments have short maturities.
Investments and Other Assets
Practicable to Estimate Fair Value
Investments and other assets include investments in common and preferred
securities, which are classified as financial investments in our Consolidated
Balance Sheets, and the nuclear decommissioning trust fund. We base the fair
value of investments and other assets on quoted market prices where available.
Not Practicable to Estimate Fair Value
It was not practicable to estimate the fair value of the Constellation Holdings
Companies' investments in:
o several financial partnerships that invest in nonpublic debt and equity
securities,
o several partnerships that own solar powered energy production facilities,
and
o a company involved in developing international power projects.
This is because the timing and amount of cash flows from these investments are
difficult to predict. We report these investments at their original cost in our
Consolidated Balance Sheets.
The investments in financial partnerships totaled $43.6 million at December 31,
1997 and $48.1 million at December 31, 1996, representing ownership interests up
to 10%. The total assets of all of these partnerships totaled $6 billion at
December 31, 1996 (which is the latest information available).
The investments in solar powered energy production facility partnerships totaled
$10.9 million at December 31, 1997 and $11.0 million December 31, 1996,
representing ownership interests up to 12%. The total assets of all of these
partnerships totaled $39.8 million at December 31, 1996 (which is the latest
information available).
Long-Term Debt and Preference Stock
We estimate the fair value of fixed-rate long-term debt and redeemable
preference stock using quoted market prices where available or by discounting
remaining cash flows at current market rates. The carrying amount of
variable-rate long-term debt approximates fair value.
Guarantees
It was not practicable to determine the fair value of certain loan guarantees of
BGE and the Constellation Holdings Companies. BGE guaranteed outstanding debt of
$20 million at December 31, 1997 and $21 million at December 31, 1996. The
Constellation Holdings Companies guaranteed outstanding debt totaling $43
million at December 31, 1997 and $47 million at December 31, 1996. We do not
anticipate that we will need to fund these guarantees.
Baltimore Gas and Electric Company and Subsidiaries 61
Note 14. Quarterly Financial Data (Unaudited)
- --------------------------------------------------------------------------------
Our quarterly financial information has not been audited but, in management's
opinion, includes all adjustments necessary for a fair presentation. Our utility
business is seasonal in nature with the peak sales periods generally occurring
during the summer and winter months. Accordingly, comparisons among quarters of
a year may not represent overall trends and changes in operations.
1997 Quarterly Data
Earnings Earnings
Income Applicable Per Share
From Net to Common of Common
Revenues Operations Income Stock Stock
- -------------------------------------------------------------------------------
(IN MILLIONS, EXCEPT PER-SHARE AMOUNTS)
Quarter Ended:
March 31 $ 887.7 $163.9 $ 72.1 $ 64.2 $0.43
June 30 746.4 78.8 15.0 7.1 0.05
September 30 860.8 321.0 171.4 164.4 1.11
December 31 812.7 159.9 24.3 18.4 0.12
------------------------------------------------------------
Year Ended:
December 31 $3,307.6 $723.6 $282.8 $254.1 $1.72
- -------------------============================================================
Our first quarter results include a $12.0 million after-tax write-down, by the
Constellation Holdings Companies, of an investment in a real estate project (see
Note 12).
Our second quarter results include a $31.9 million after-tax write-down, by the
Constellation Holdings Companies, of an investment in a real estate project (see
Note 12).
Our fourth quarter results include a:
o $37.5 million after-tax write-off of merger costs (see Note 12).
o $2.1 million after-tax write-down, by the Constellation Holdings Companies,
of an investment in a real estate project (see Note 12).
1996 Quarterly Data
Earnings Earnings
Income Applicable Per Share
From Net to Common of Common
Revenues Operations Income Stock Stock
- ------------------------------------------------------------------------------
(IN MILLIONS, EXCEPT PER-SHARE AMOUNTS)
Quarter Ended:
March 31 $ 861.3 $201.3 $100.8 $ 91.1 $0.62
June 30 731.7 148.6 64.5 52.4 0.36
September 30 826.0 275.7 146.5 137.9 0.93
December 31 734.2 43.9 (1.0) (9.1) (0.06)
-----------------------------------------------------------
Year Ended:
December 31 $3,153.2 $669.5 $310.8 $272.3 $1.85
- -------------------===========================================================
Our second quarter results include a:
o $4.5 million after-tax write-off of disallowed replacement energy costs
(see Note 12).
o $14.6 million after-tax gain on the sale by a Constellation partnership of
a power purchase agreement (see Note 3).
o $7.0 million after-tax write-off of the Constellation Holdings Companies'
investment in two geothermal wholesale power generating projects (see Note
3).
o $3.0 million after-tax write-off, by the Constellation Holdings Companies,
of development costs for a coal-fired power project (see Note 3).
Our third quarter results include a $6.2 million after-tax write-off by the
Constellation Holdings Companies of a portion of a solar power project
investment (see Note 3).
Our fourth quarter results include a $57.6 million after-tax write-off of
disallowed replacement energy costs (see Note 12).
The sum of the quarterly earnings per share amounts may not equal the total for
the year due to the effects of rounding.
62 Baltimore Gas and Electric Company and Subsidiaries
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH
ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
Not applicable.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF
THE REGISTRANT
The information required by this item with respect to directors is set
forth on pages 5 through 9 under "Board of Directors" in the Proxy Statement and
is incorporated herein by reference.
The information required by this item with respect to executive officers
is, pursuant to instruction 3 of paragraph (b) of Item 401 of Regulation S-K,
set forth in Item 10 of Part I of this Form 10-K under "Executive Officers of
the Registrant," except that information with regard to a late filing of a
Section 16(a) report by an executive officer is set forth on page 9 under
"Section 16(a) Beneficial Ownership Reporting Compliance" in the Proxy Statement
and is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item is set forth on page 8 under "Board
of Directors," on pages 11 through 16 under "Executive Compensation," and on
pages 17 through 19 under "Report of Committee on Management on Executive
Compensation" in the Proxy Statement and is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS AND MANAGEMENT
The information required by this item is set forth on page 10 under
"Security Ownership" in the Proxy Statement and is incorporated herein by
reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED
TRANSACTIONS
The information required by this item is set forth on page 9 under "Board
of Directors -- Certain Relationships and Transactions" in the Proxy Statement
and is incorporated herein by reference.
63
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) The following documents are filed as a part of this Report:
1. Financial Statements:
Report of Independent Accountants dated January 21, 1998 of
Coopers & Lybrand L.L.P.
Consolidated Statements of Income for three years ended
December 31, 1997
Consolidated Balance Sheets at December 31, 1997 and December 31, 1996
Consolidated Statements of Cash Flows for three years ended
December 31, 1997
Consolidated Statements of Common Shareholders' Equity for three years
ended December 31, 1997
Consolidated Statements of Capitalization at December 31, 1997 and
December 31, 1996
Consolidated Statements of Income Taxes for three years ended
December 31, 1997
Notes to Consolidated Financial Statements
2. Financial Statement Schedules:
Schedule II -- Valuation and Qualifying Accounts
Schedules other than Schedule II are omitted as not applicable or not
required.
3. Exhibits Required by Item 601 of Regulation S-K.
64
EXHIBIT
NUMBER
- -------
*3(a) -- Charter of BGE, restated as of August 16, 1996. (Designated as Exhibit No. 3 in Form 10-Q dated
November 14, 1996, File No. 1-1910.)
3(b) -- By-Laws of BGE, as amended to January 23, 1998.
*4(a) -- Supplemental Indenture between BGE and Bankers Trust Company, as Trustee, dated as of June 20, 1995,
supplementing, amending and restating Deed of Trust dated February 1, 1919. (Designated as Exhibit
No. 4 in Form 10-Q dated August 11, 1995, File No. 1-1910.); and the following Supplemental
Indentures between BGE and Bankers Trust Company, Trustee:
DESIGNATED IN
----------------------------------------------------------------------------
EXHIBIT
DATED FILE NO. NUMBER
-------------------- --------- ------------
*July 15, 1977 2-59772 2-3
(3 Indentures)
*October 15, 1989 1-1910 (Form 10-Q dated November 14, 1989) 4(a)
*August 15, 1991 33-45259 (Form S-3 Registration) 4(a)(i)
*January 15, 1992 33-45259 (Form S-3 Registration) 4(a)(ii)
*July 1, 1992 1-1910 (Form 8-K Report for January 29, 1993) 4(a)
*February 15, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(i)
*March 1, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(ii)
*March 15, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(iii)
*April 15, 1993 1-1910 (Form 10-Q dated May 13, 1993) 4
*July 1, 1993 1-1910 (Form 10-Q dated August 13, 1993) 4(a)
*July 15, 1993 1-1910 (Form 10-Q dated August 13, 1993) 4(b)
*October 15, 1993 1-1910 (Form 10-Q dated November 12, 1993) 4
*March 15, 1994 1-1910 (Form 10-K Annual Report for 1993) 4(a)
*June 15, 1996 1-1910 (Form 10-Q dated August 13, 1996) 4
*4(b) -- Indenture dated July 1, 1985, between BGE and The Bank of New York (Successor to Mercantile-Safe
Deposit and Trust Company), Trustee. (Designated in Registration File No.
2-98443 as Exhibit 4(a)); as supplemented by Supplemental Indentures dated as of October 1, 1987
(Designated in Form 8-K, dated November 13, 1987, File No. 1-1910 as Exhibit 4(a)) and as of January
26, 1993 (Designated in Form 8-K, dated January 29, 1993, File No. 1-1910 as Exhibit 4(b).)
*10(a) -- Baltimore Gas and Electric Company Executive Benefits Plan, as amended and restated. (Designated as
Exhibit No. 10(a) in Form 10-Q dated November 14, 1996, File No. 1-1910.)
*10(b) -- Executive Incentive Plan of the Baltimore Gas and Electric Company. (Designated as Exhibit No. 10(b)
to the Annual Report on Form 10-K for the year ended December 31, 1992, File No. 1-1910.)
*10(c) -- Baltimore Gas and Electric Company 1995 Long-Term Incentive Plan. (Designated as Exhibit No. 10(c) to
the Annual Report on Form 10-K for the year ended December 31, 1994, File No. 1-1910.)
*10(d) -- Baltimore Gas and Electric Company Nonqualified Deferred Compensation Plan, as amended and restated.
(Designated as Exhibit No. 10(d) to the Annual Report on Form 10-K for the year ended December 31,
1996, File No. 1-1910.)
*10(e) -- Amended and Restated Baltimore and Gas and Electric Company Deferred Compensation Plan for
Non-Employee Directors (formerly Baltimore Gas and Electric Company Deferred Compensation Plan for
Non-Employee Directors). (Designated as Exhibit No. 10 in Form 10-Q dated November 13, 1997, File No.
1-1910.)
*10(f) -- Baltimore Gas and Electric Company Retirement Plan for Non-Employee Directors, as amended and
restated. (Designated as Exhibit No. 10(f) to the Annual Report on Form 10-K for the year ended
December 31, 1994, File No. 1-1910.) (Terminated effective August 1, 1997.)
*10(g) -- Summary of Baltimore Gas and Electric Company Long Term Performance Program. (Designated as Exhibit
No. 10(h) to the Annual Report on Form 10-K for the year ended December 31, 1993, File No. 1-1910.)
*10(h) -- Grantor Trust Agreement Dated as of July 31, 1994 between Baltimore Gas and Electric Company and
Citibank, N.A. (Designated as Exhibit No. 10(h) to the Annual Report on Form 10-K for the year ended
December 31, 1994, File No. 1-1910.)
*10(i) -- Summary of Constellation Holdings, Inc. Annual Incentive Plan. (Designated as Exhibit No. 10(g) to
the Annual Report on Form 10-K for the year ended December 31, 1992, File No.
1-1910.)
65
*10(j) -- Summary of 1994-96 Long Term Incentive Plan of Constellation Holdings, Inc. (Designated as Exhibit
No. 10(l) to the Annual Report on Form 10-K for the year ended December 31, 1994, File No. 1-1910.)
10(k) -- Severance Agreements between BGE and six key employees.
10(l) -- Constellation Holdings, Inc. Deferred Compensation Plan for Non-Employee Directors.
*10(m) -- Severance Agreements between BGE and 15 key employees. (Designated as Exhibit No. 10(o) to the Annual
Report on Form 10-K for the year ended December 31, 1995, File No. 1-1910.)
*10(n) -- Grantor Trust Agreement dated as of June 1, 1996 between Baltimore Gas and Electric Company and T.
Rowe Price Trust Company. (Designated as Exhibit No. 10(b) in Form 10-Q dated August 13, 1996, File
No. 1-1910.)
12 -- Computation of Ratio of Earnings to Fixed Charges and Computation of Ratio of Earnings to Combined
Fixed Charges and Preferred and Preference Dividend Requirements.
21 -- Subsidiaries of the Registrant.
23 -- Consent of Coopers & Lybrand L.L.P., Independent Accountants.
27 -- Financial Data Schedule.
*99(a) -- Indemnification of Directors and Officers of the Company. (Designated as Exhibit No. 28(a) to the
Annual Report on Form 10-K for the year ended December 31, 1988, File No. 1-1910.)
*99(b) -- Corporations and Associations Article, Section 2-418 of the Annotated Code of Maryland. (Designated
as Exhibit 28(b) to the Annual Report on Form 10-K for the year ended December 31, 1987, File No.
1-1910.)
- ---------------
*Incorporated by Reference.
(b) Reports on Form 8-K:
DATE FILED ITEM REPORTED
---------- -------------
October 30, 1997 Item 5. Other Events
Item 7. Financial Statements and Exhibits
December 23, 1997 Item 5. Other Events
Item 7. Financial Statements and Exhibits
66
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- ---------------------------------------------- -------- --------------------------- ------------------ --------
ADDITIONS
---------------------------
BALANCE CHARGED
AT TO BALANCE
BEGINNING COSTS CHARGED TO OTHER AT END
OF AND ACCOUNTS -- (DEDUCTIONS) -- OF
DESCRIPTION PERIOD EXPENSES DESCRIBE DESCRIBE PERIOD
- ---------------------------------------------- -------- ------- ---------------- ------------------ --------
(IN MILLIONS)
Reserves deducted in the Balance Sheet from
the assets to which they apply:
Accumulated Provision for Uncollectibles
1997..................................... $ 18.0 $ 34.4 $ -- $(28.3)(A) $ 24.1
1996..................................... 16.4 24.9 -- (23.3)(A) 18.0
1995..................................... 14.9 19.2 -- (17.7)(A) 16.4
Valuation Allowance --
Net unrealized (gain) loss on available
for sale securities
1997..................................... (8.8) -- 1.2(B) -- (7.6)
1996..................................... (6.2) -- (2.6)(B) -- (8.8)
1995..................................... 3.8 -- (10.0)(B) -- (6.2)
Valuation Allowance --
Net unrealized (gain) loss on nuclear
decommissioning trust fund
1997..................................... (3.7) -- (6.3)(C) -- (10.0)
1996..................................... (2.2) -- (1.5)(C) -- (3.7)
1995..................................... 1.8 -- (4.0)(C) -- (2.2)
Provision for possible disallowance of
replacement energy costs
1997..................................... 118.0 -- -- (118.0)(D) --
1996..................................... 35.0 83.0 -- -- 118.0
1995..................................... 35.0 -- -- -- 35.0
Energy projects under development reserves
1997..................................... 5.2 0.3 -- (5.5)(E) --
1996..................................... .3 5.2 -- (.3)(E) 5.2
1995..................................... 1.8 -- -- (1.5)(E) .3
- ---------------
(A) Represents principally net amounts charged off as uncollectible.
(B) Represents net unrealized (gains)/losses (credited)/charged to common
shareholders' equity.
(C) Represents net unrealized (gains)/losses (credited)/charged to accumulated
depreciation.
(D) Represents removal of a reserve based on actual disallowance of replacement
energy costs.
(E) Represents removal of a reserve associated with an energy project of a
subsidiary which was abandoned.
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
67
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, Baltimore Gas and Electric Company, the Registrant, has
duly caused this Report to be signed on its behalf by the undersigned, thereunto
duly authorized.
BALTIMORE GAS AND ELECTRIC COMPANY
(REGISTRANT)
Date: March 27, 1998 By /s/ C. H. POINDEXTER
___________________________________
C. H. POINDEXTER
CHAIRMAN OF THE BOARD
Pursuant to the requirements of the Securities Exchange Act of 1934, this
Report has been signed below by the following persons on behalf of Baltimore Gas
and Electric Company, the Registrant, and in the capacities and on the dates
indicated.
SIGNATURE TITLE DATE
--------- ----- ----
Principal executive officer and director:
By /s/ C. H. POINDEXTER Chairman of the Board and March 27, 1998
______________________________________________ Director
C. H. POINDEXTER
Principal financial and accounting officer:
By /s/ D. A. BRUNE Vice President and Secretary March 27, 1998
______________________________________________
D. A. BRUNE
Directors:
/s/ H. F. BALDWIN Director March 27, 1998
_________________________________________________
H. F. BALDWIN
/s/ B. B. BYRON Director March 27, 1998
_________________________________________________
B. B. BYRON
/s/ J. O. COLE Director March 27, 1998
_________________________________________________
J. O. COLE
/s/ D. A. COLUSSY Director March 27, 1998
_________________________________________________
D. A. COLUSSY
/s/ E. A. CROOKE Director March 27, 1998
_________________________________________________
E. A. CROOKE
/s/ J. R. CURTISS Director March 27, 1998
_________________________________________________
J. R. CURTISS
/s/ J. W. GECKLE Director March 27, 1998
_________________________________________________
J. W. GECKLE
/s/ F. A. HRABOWSKI III Director March 27, 1998
_________________________________________________
F. A. HRABOWSKI III
/s/ N. LAMPTON Director March 27, 1998
_________________________________________________
N. LAMPTON
/s/ G. V. MCGOWAN Director March 27, 1998
_________________________________________________
G. V. MCGOWAN
/s/ G. L. RUSSELL, JR. Director March 27, 1998
_________________________________________________
G. L. RUSSELL, JR.
/s/ M. D. SULLIVAN Director March 27, 1998
_________________________________________________
M. D. SULLIVAN
68
EXHIBIT INDEX
EXHIBIT
NUMBER
- -------
*3(a) -- Charter of BGE, restated as of August 16, 1996. (Designated as Exhibit No. 3 in Form 10-Q dated
November 14, 1996, File No. 1-1910.)
3(b) -- By-Laws of BGE, as amended to January 23, 1998.
*4(a) -- Supplemental Indenture between BGE and Bankers Trust Company, as Trustee, dated as of June 20, 1995,
supplementing, amending and restating Deed of Trust dated February 1, 1919. (Designated as Exhibit
No. 4 in Form 10-Q dated August 11, 1995, File No. 1-1910.); and the following Supplemental
Indentures between BGE and Bankers Trust Company, Trustee:
DESIGNATED IN
------------------------------------------------------------------------------
EXHIBIT
DATED FILE NO. NUMBER
-------------------- --------- ------------
*July 15, 1977 2-59772 2-3
(3 Indentures)
*October 15, 1989 1-1910 (Form 10-Q dated November 14, 1989) 4(a)
*August 15, 1991 33-45259 (Form S-3 Registration) 4(a)(i)
*January 15, 1992 33-45259 (Form S-3 Registration) 4(a)(ii)
*July 1, 1992 1-1910 (Form 8-K Report for January 29, 1993) 4(a)
*February 15, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(i)
*March 1, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(ii)
*March 15, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(iii)
*April 15, 1993 1-1910 (Form 10-Q dated May 13, 1993) 4
*July 1, 1993 1-1910 (Form 10-Q dated August 13, 1993) 4(a)
*July 15, 1993 1-1910 (Form 10-Q dated August 13, 1993) 4(b)
*October 15, 1993 1-1910 (Form 10-Q dated November 12, 1993) 4
*March 15, 1994 1-1910 (Form 10-K Annual Report for 1993) 4(a)
*June 15, 1996 1-1910 (Form 10-Q dated August 13, 1996) 4
*4(b) -- Indenture dated July 1, 1985, between BGE and The Bank of New York (Successor to Mercantile-Safe
Deposit and Trust Company), Trustee. (Designated in Registration File No.
2-98443 as Exhibit 4(a)); as supplemented by Supplemental Indentures dated as of October 1, 1987
(Designated in Form 8-K, dated November 13, 1987, File No. 1-1910 as Exhibit 4(a)) and as of
January 26, 1993 (Designated in Form 8-K, dated January 29, 1993, File No. 1-1910 as Exhibit
4(b).)
*10(a) -- Baltimore Gas and Electric Company Executive Benefits Plan, as amended and restated. (Designated
as Exhibit No. 10(a) in Form 10-Q dated November 14, 1996, File No. 1-1910.)
*10(b) -- Executive Incentive Plan of the Baltimore Gas and Electric Company. (Designated as Exhibit No.
10(b) to the Annual Report on Form 10-K for the year ended December 31, 1992, File No. 1-1910.)
*10(c) -- Baltimore Gas and Electric Company 1995 Long-Term Incentive Plan. (Designated as Exhibit No. 10(c)
to the Annual Report on Form 10-K for the year ended December 31, 1994, File No. 1-1910.)
*10(d) -- Baltimore Gas and Electric Company Nonqualified Deferred Compensation Plan, as amended and
restated. (Designated as Exhibit No. 10(d) to the Annual Report on Form 10-K for the year ended
December 31, 1996, File No. 1-1910.)
*10(e) -- Amended and Restated Baltimore and Gas and Electric Company Deferred Compensation Plan for
Non-Employee Directors (formerly Baltimore Gas and Electric Company Deferred Compensation Plan for
Non-Employee Directors). (Designated as Exhibit No. 10 in Form 10-Q dated November 13, 1997, File
No. 1-1910.)
*10(f) -- Baltimore Gas and Electric Company Retirement Plan for Non-Employee Directors, as amended and
restated. (Designated as Exhibit No. 10(f) to the Annual Report on Form 10-K for the year ended
December 31, 1994, File No. 1-1910.) (Terminated effective August 1, 1997.)
*10(g) -- Summary of Baltimore Gas and Electric Company Long Term Performance Program. (Designated as
Exhibit No. 10(h) to the Annual Report on Form 10-K for the year ended December 31, 1993, File No.
1-1910.)
*10(h) -- Grantor Trust Agreement Dated as of July 31, 1994 between Baltimore Gas and Electric Company and
Citibank, N.A. (Designated as Exhibit No. 10(h) to the Annual Report on Form 10-K for the year
ended December 31, 1994, File No. 1-1910.)
69
*10(i) -- Summary of Constellation Holdings, Inc. Annual Incentive Plan. (Designated as Exhibit No. 10(g) to
the Annual Report on Form 10-K for the year ended December 31, 1992, File No.
1-1910.)
*10(j) -- Summary of 1994-96 Long Term Incentive Plan of Constellation Holdings, Inc. (Designated as Exhibit
No. 10(l) to the Annual Report on Form 10-K for the year ended December 31, 1994, File No.
1-1910.)
10(k) -- Severance Agreements between BGE and six key employees.
10(l) -- Constellation Holdings, Inc. Deferred Compensation Plan for Non-Employee Directors.
*10(m) -- Severance Agreements between BGE and 15 key employees. (Designated as Exhibit No. 10(o) to the
Annual Report on Form 10-K for the year ended December 31, 1995, File No. 1-1910.)
*10(n) -- Grantor Trust Agreement dated as of June 1, 1996 between Baltimore Gas and Electric Company and T.
Rowe Price Trust Company. (Designated as Exhibit No. 10(b) in Form 10-Q dated August 13, 1996,
File No. 1-1910.)
12 -- Computation of Ratio of Earnings to Fixed Charges and Computation of Ratio of Earnings to Combined
Fixed Charges and Preferred and Preference Dividend Requirements.
21 -- Subsidiaries of the Registrant.
23 -- Consent of Coopers & Lybrand L.L.P., Independent Accountants.
27 -- Financial Data Schedule.
*99(a) -- Indemnification of Directors and Officers of the Company. (Designated as Exhibit No. 28(a) to the
Annual Report on Form 10-K for the year ended December 31, 1988, File No. 1-1910.)
*99(b) -- Corporations and Associations Article, Section 2-418 of the Annotated Code of Maryland.
(Designated as Exhibit 28(b) to the Annual Report on Form 10-K for the year ended December 31,
1987, File No. 1-1910.)
- ---------------
*Incorporated by Reference.
70