UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
Date of Report (Date of earliest event reported): March 7, 1997
BALTIMORE GAS AND ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
Maryland 1-1910 52-0280210
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(State of incorporation) (Commission (IRS Employer
File Number) Identification No.)
39 W. Lexington Street Baltimore, Maryland 21201
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(Address of principal executive offices) (Zip Code)
410-783-5920
(Registrant's telephone number, including area code)
Not Applicable
(Former name, former address and former fiscal year, if changed since last
report)
<PAGE>
The term "Company" is used in this Current Report, except where otherwise
specifically indicated by the context, to refer to Baltimore Gas and Electric
Company ("BGE") and Subsidiaries.
ITEM 5. Other Events (pages 3 through 37)
The following financial information for the Company for the year ended December
31, 1996 is set forth in this Form 8-K:
Selected Financial Data
Management's Discussion and Analysis of Financial Condition and Results of
Operations
Report of Management
Report of Independent Accountants
Consolidated Statements of Income
Consolidated Balance Sheets
Consolidated Statements of Cash Flows
Consolidated Statements of Common Shareholders' Equity
Consolidated Statements of Capitalization
Consolidated Statements of Income Taxes
Notes to Consolidated Financial Statements
2
<PAGE>
Selected Financial Data
<TABLE>
<CAPTION>
Compound
1996 1995 1994 1993 1992 Growth
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(Dollar amounts in thousands, except per share amounts) 5-Year 10-Year
<S> <C>
Summary of Operations
Total Revenues $3,153,247 $2,934,799 $2,782,985 $2,741,385 $2,559,536 4.63% 4.63%
Expenses Other Than Interest and Income
Taxes 2,483,782 2,239,107 2,147,726 2,124,993 2,024,227 4.15 5.21
-------------------------------------------------------------
Income From Operations 669,465 695,692 635,259 616,392 535,309 6.54 2.73
Other Income 6,130 8,819 32,365 20,310 22,132 (26.25) (9.83)
-------------------------------------------------------------
Income Before Interest and Income Taxes 675,595 704,511 667,624 636,702 557,441 5.55 2.49
Net Interest Expense 198,438 196,977 190,154 188,764 189,747 0.19 5.82
-------------------------------------------------------------
Income Before Income Taxes 477,157 507,534 477,470 447,938 367,694 8.37 1.39
Income Taxes 166,333 169,527 153,853 138,072 103,347 14.22 1.65
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Net Income 310,824 338,007 323,617 309,866 264,347 4.17 1.25
Preferred and Preference Stock Dividends 38,536 40,578 39,922 41,839 42,247 (2.05) 3.67
-------------------------------------------------------------
Earnings Applicable to Common Stock $ 272,288 $ 297,429 $ 283,695 $ 268,027 $ 222,100 5.26 0.95
=============================================================
Earnings Per Share of Common Stock $1.85 $2.02 $1.93 $1.85 $1.63 2.07 (1.26)
Dividends Declared Per Share of Common
Stock $1.59 $1.55 $1.51 $1.47 $1.43 2.58 3.03
Ratio of Earnings to Fixed Charges 3.10 3.21 3.14 3.00 2.65 6.43 (2.97)
Ratio of Earnings to Fixed Charges and
Preferred and Preference Stock Dividends
Combined 2.44 2.52 2.47 2.34 2.08 6.04 (2.68)
Financial Statistics at Year End
Total Assets $8,550,970 $8,316,663 $8,037,502 $7,829,613 $7,208,660 3.68 6.44
=============================================================
Capitalization
Long-term debt $2,758,769 $2,598,254 $2,584,932 $2,823,144 $2,376,950 2.91 5.62
Preferred stock -- 59,185 59,185 59,185 59,185 -- --
Redeemable preference stock 134,500 242,000 279,500 342,500 395,500 (19.53) 10.40
Preference stock not subject to mandatory
redemption 210,000 210,000 150,000 150,000 110,000 13.81 6.68
Common shareholders' equity 2,857,113 2,812,682 2,717,866 2,620,511 2,534,639 5.82 5.77
-------------------------------------------------------------
Total Capitalization $5,960,382 $5,922,121 $5,791,483 $5,995,340 $5,476,274 3.12 5.63
=============================================================
Book Value Per Share of Common Stock $19.35 $19.07 $18.42 $17.94 $17.63 2.62 3.43
Number of Common Shareholders 77,550 79,811 81,505 82,287 80,371 1.74 0.07
</TABLE>
Baltimore Gas and Electric Company and Subsidiaries
3
<PAGE>
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:
(bullet) what factors affect our business,
(bullet) what our earnings and costs were in 1996 and 1995,
(bullet) why those earnings and costs were different from the year before,
(bullet) where our earnings came from,
(bullet) how all of this affects our overall financial condition,
(bullet) what our expenditures for capital projects were in 1994 through 1996
and what we expect them to be in 1997 through 1999, and
(bullet) where cash will come from to pay 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 15, which present the results of
our operations for 1996, 1995, and 1994. 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.
You may notice some changes in this year's discussion, compared to past years.
This is because we volunteered to participate in a pilot program with the
Securities and Exchange Commission to write financial documents in plain
English. As a result, we have re-written our entire Management's Discussion and
Analysis section. Our goal is to discuss our financial condition in language
that is more easily understood.
BGE and Potomac Electric Power Company have agreed to merge into a new company
named Constellation Energy Corporation. We plan to complete the merger as soon
as we obtain all regulatory approvals. These matters are discussed in more
detail in Note 12 beginning on page 32 and in a Registration Statement on
Form S-4 (Registration No. 33-64799). The merger may impact many of the matters
discussed in Management's Discussion and Analysis including earnings, results of
electric operations, expenses, liquidity, and capital resources.
The electric utility industry is undergoing rapid and substantial change.
Competition is increasing. The regulatory environment (federal and state) is
shifting. These matters are discussed briefly in the "Competition and Response
to Regulatory Change" section on page 6 in Management's Discussion and Analysis.
They are discussed in detail in our Annual Reports on Form 10-K. BGE
continuously evaluates these changes. Based on the evaluations, BGE refines
short and long term business plans with the primary goal of protecting our
security holders' investments and providing them with superior returns on their
investment in BGE. In order to support this primary goal, we also focus on other
groups who impact our primary goal. For example, we stress providing low cost,
reliable power to our electric customers. As you read Management's Discussion
and Analysis, many BGE initiatives to support our primary goal are mentioned.
These include the proposed merger with Potomac Electric Power Company, designed
to position us to remain competitive as the industry changes, and our
diversification effort. We enter new businesses which we believe will support
our primary goal. For example, new businesses may be opportunities to:
(bullet) provide customers of our core energy business additional services, or
(bullet) attract new customers for our core energy business, or
(bullet) expand our diversified stream of revenues.
We believe our newest subsidiary, Constellation Power Source, Inc., will satisfy
all three criteria. Its proposed power marketing business is described in detail
in our Annual Reports on Form 10-K.
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Results of Operations
In this section, we discuss our 1996 and 1995 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
1996 1995 1994
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Earnings per share from
current-year operations:
Utility business $1.96 $1.84 $1.81
Diversified businesses (subsidiaries) .31 .18 .12
----------------------
Total earnings per share from
current-year operations 2.27 2.02 1.93
Disallowed replacement
energy costs (see Note 12) (.42) -- --
----------------------
Total earnings per share $1.85 $2.02 $1.93
======================
1996
Our 1996 total earnings decreased $25.1 million, or $.17 per share, from 1995.
Our total earnings decreased because we reserved for disallowed replacement
energy costs. We discuss this in detail in the "Disallowed Replacement Energy
Costs" section on page 7.
In 1996, we had higher utility earnings from current-year operations due to
three factors: we sold more electricity and gas due to colder winter weather
(people use more gas and electricity to heat their homes in colder 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
current-year operations except we sold less electricity in the third quarter due
to milder summer weather. We discuss our utility earnings in more detail
beginning on page 6.
Baltimore Gas and Electric Company and Subsidiaries
4
<PAGE>
In 1996, we had higher earnings from our diversified business subsidiaries
mostly because the Constellation Companies had higher earnings from power
generation projects and financial investments. We discuss our diversified
business earnings in more detail beginning on page 10.
1995
Our 1995 total earnings increased $13.7 million, or $.09 per share, from 1994.
In 1995, we had higher utility earnings mostly due to greater sales of
electricity during an extremely hot summer and higher electricity and gas sales
resulting from colder fall weather. We would have had even higher utility
earnings except for the mild weather in the first half of the year, lower net
other income and deductions (miscellaneous non-operating income and expenses),
and lower allowance for funds used during construction (an accounting procedure
used to exclude the cost of capital from expense and include it as part of the
cost of utility plant construction).
In 1995, we had higher earnings from our diversified businesses mostly because
the Constellation Companies had higher earnings from power generation projects
and financial investments.
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
The Maryland Public Service Commission (Maryland Commission) 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 Commission 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 Commission 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
Commission 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 (nuclear
fuel, coal, gas, or oil) we use to generate electricity. The actual cost of the
fuel is passed on to the customer with no profit. 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 Commission. We discuss Market Based Rates in more detail in the
"Gas Cost Adjustments" section on page 8 and in Note 1 on page 23.
From time to time, when necessary to cover increased costs, we ask the Maryland
Commission for base rate increases. Not every request for base rate increases is
granted in full. However, the Maryland Commission has historically allowed BGE
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.
The following chart shows the number of cooling and heating degree days in 1996
and 1995, shows the percentage changes in the number of degree days from prior
years, and shows the number of degree days in a "normal" year as represented by
the 30-year average.
30-Year
1996 1995 Average
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Cooling degree days 786 1,056 804
Percentage change
compared to prior year (25.6)% 11.3%
Heating degree days 5,138 4,601 4,901
Percentage change
compared to prior year 11.7% (1.5)%
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.
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.
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 1996 and 1995.
Baltimore Gas and Electric Company and Subsidiaries
5
<PAGE>
Competition and Response to Regulatory Change
Our business is also affected by competition. Electric utilities are facing
competition on three fronts:
(bullet) in the construction of generating units to meet increased demand for
electricity,
(bullet) in the sale of their electricity in the bulk power markets, and
(bullet) 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. In
September 1995, we decided that a merger with Potomac Electric Power Company
would help us compete by maintaining low-cost production and increasing our
size. The pending merger is more thoroughly discussed in Note 12 on page 32.
Although we believe the merger will improve our competitive position in the
future, no one can predict the ultimate effect competition or regulatory change
will have on our earnings or on the earnings of the merged company.
We will continue to develop strategies to keep us competitive. These strategies
might include one or more of the following:
(bullet) the complete or partial separation of our generation, transmission, and
distribution functions
(bullet) other internal restructuring
(bullet) mergers or acquisitions of utility or non-utility businesses
(bullet) addition or disposition of portions of our service territories
(bullet) spin-off or distribution of one or more 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 our
Annual Reports on Form 10-K under the headings "Electric Regulatory Matters and
Competition" and "Gas Regulatory Matters and Competition."
Utility Business Earnings per Share of Common Stock
1996 1995 1994
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Utility earnings per share from
current-year operations:
Electric business $1.75 $1.70 $1.71
Gas business .21 .14 .10
-------------------------
Total utility earnings per share
from current-year operations 1.96 1.84 1.81
Disallowed replacement
energy costs (see Note 12) (.42) -- --
-------------------------
Total utility earnings per share $1.54 $1.84 $1.81
=========================
Our 1996 total utility earnings decreased $44.5 million, or $.30 per share, from
1995. Our 1995 utility earnings increased $5.6 million, or $.03 per share, from
1994.
We discuss the factors affecting utility earnings below.
Electric Operations
Electric Revenues
The changes in electric revenues in 1996 and 1995 compared to the respective
prior year were caused by:
1996 1995
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(In millions)
Electric system sales volumes $ 0.4 $ 43.4
Base rates (2.5) 23.2
Fuel rates (12.3) (13.8)
----------------------
Total change in electric revenues
from electric system sales (14.4) 52.8
Interchange and other sales (11.1) 49.0
Other 4.5 1.4
----------------------
Total change in electric revenues $(21.0) $103.2
======================
Electric System Sales Volumes
"Electric system sales" are sales to customers in our service territory at rates
set by the Maryland Commission. 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 1996 and 1995 compared to the respective prior year were:
1996 1995
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Residential 2.5% 2.8%
Commercial (0.3) 2.3
Industrial 0.1 3.6
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. As mentioned above, weather impacts residential, more than commercial and
industrial, sales. In 1996 other items offset the impact of weather on
commercial and industrial sales. Other items include the demand for power to
fuel manufacturing equipment and office machinery, which vary with changes in
the customers' businesses. For example, if a manufacturing plant has a slow
year, it will make less product and use less power to run its assembly lines.
In 1995, we sold more electricity to residential and commercial customers mostly
because we had an increase in the number of customers and we had extremely hot
summer weather and cold fall weather. We would have sold even more electricity
to those customers except we had milder weather in the first half of 1995
compared to 1994. We sold more electricity to industrial customers mostly
because we had an increase in the number of customers and more demand for
electricity from Bethlehem Steel (our largest customer).
Base Rates
In 1996, base rate revenues were about the same as they were in 1995. Although
we sold more electricity this year, our revenues did not increase because the
higher sales occurred during the winter when our base rates are lower.
Baltimore Gas and Electric Company and Subsidiaries
6
<PAGE>
In 1995, base rate revenues were higher than in 1994 because of a higher energy
conservation surcharge and also because we did not have to reduce conservation
revenues as we did in 1994, when we exceeded our allowed profit.
From July 1, 1993, through June 30, 1994, we exceeded our profit limit under the
energy conservation surcharge. To correct the overage, we lowered the surcharge
on our customers' bills from December 1993 to November 1994. As a result, we
billed $20.1 million less than we would have otherwise. We also exceeded the
limit on our profit during 1996. Therefore, we excluded $28.5 million of our
1996 surcharge billings from revenue, and we will lower the surcharge on our
customers' bills beginning in July 1997 to correct the overage.
Fuel Rates
The fuel rate is the rate the Maryland Commission allows us to charge our
customers for our actual cost of fuel with no profit to us. If the cost of fuel
goes up, the Maryland Commission permits us to increase the fuel rate. If the
cost of fuel goes down, our customers benefit from a reduction in the fuel rate.
The fuel rate is impacted most by the amount of electricity generated at the
Calvert Cliffs Nuclear Power Plant because the cost of nuclear fuel is cheaper
than coal, gas, or oil. (See Note 1 on page 23 for a further discussion of how
the fuel rate increases and decreases.)
Changes in the fuel rate normally do not affect earnings. However, if the
Maryland Commission disallows recovery of any part of the fuel costs, our
earnings are reduced. (We discuss this more thoroughly in the "Electric Fuel and
Purchased Energy Expenses" section below and in Note 12 on page 34.)
In 1996 and 1995, fuel rate revenues decreased due to a lower fuel rate because
we were able to operate plants with the lowest fuel costs to generate
electricity during the previous 24 months. Fuel rate revenues would have been
even lower except we sold more electricity. In 1995, the fuel rate was also
lower compared to 1994 because of lower fuel costs.
Interchange and Other Sales
"Interchange and other sales" are sales of energy in the Pennsylvania-New
Jersey-Maryland Interconnection (PJM) and to others. The PJM is a regional power
pool of eight utility member companies, including BGE. We sell energy to PJM
members and to others after we have satisfied the demand for electricity in our
own system.
In 1996, we had lower interchange and other sales compared to 1995 because we
generated less electricity at our Calvert Cliffs Nuclear Power Plant. 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.
In 1995, interchange and other sales increased because we were able to operate
plants with the lowest fuel costs to generate electricity, had available
capacity, and had lower costs than other utilities. Specifically, we had greater
generation from our coal-fired Brandon Shores Power Plant, and our Calvert
Cliffs Nuclear Power Plant generated a record level of electricity during 1995.
Electric Fuel and Purchased Energy Expenses
1996 1995 1994
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(In millions)
Actual costs $539.2 $554.5 $541.2
Net recovery of costs
under electric fuel
rate clause (see Note 1) 8.2 24.3 1.1
Disallowed replacement
energy costs (including
carrying charges)
(see Note 12) 95.4 -- --
--------------------------
Total electric fuel and
purchased energy expenses $642.8 $578.8 $542.3
==========================
Actual Costs
In 1996, our actual cost of fuel to generate electricity (nuclear fuel, coal,
gas, or oil) and electricity we bought from other utilities was 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.
In 1995, our actual cost of fuel to generate electricity and electricity we
bought from other utilities was higher than in 1994 mostly because we generated
more electricity and the price of electricity and capacity we bought from other
utilities was higher. Our actual costs would have been even higher except we
were able to use a less-costly mix of generating plants, mostly because of
shorter refueling and maintenance downtime at our Calvert Cliffs Nuclear Power
Plant.
Electric Fuel Rate Clause
The "electric fuel rate clause" (determined by the Maryland Commission) requires
that we defer (to include as an asset or liability on the balance sheet and
exclude from income and expense) the difference between our actual costs of fuel
and our fuel rate revenues collected from customers through the fuel rate. We
bill or refund that difference to customers in the future.
In 1996 and 1995, our actual fuel costs were lower than the fuel rate revenues
we collected from our customers. As a result, we recovered fuel costs which we
had deferred in prior years.
Disallowed Replacement Energy Costs
During 1989 through 1991 we experienced extended outages at our Calvert Cliffs
Nuclear Power Plant. These outages have been the subject of ongoing fuel rate
proceedings before the Maryland Commission for several years (see Note 12 on
page 34).
In December 1996, we entered into a settlement agreement with the Maryland
People's Counsel and the Maryland Commission Staff. We agreed not to bill our
customers for $118 million of electric replacement energy costs associated with
these extended outages. We set up a reserve for $35 million of these costs in
1990. In 1996, we increased that reserve by $83 million and we wrote off $5.6
million of related carrying charges. In addition, we wrote off $6.8 million of
fuel costs that were disallowed by the Maryland Commission in May 1996 (we
discuss these costs further in Note 12 on page 34). These write-offs and the
increase in the reserve significantly increased our total purchased fuel and
energy expenses in 1996. The remainder of the replacement energy costs
associated with the extended outage has already been recovered from customers
through the fuel rate.
Baltimore Gas and Electric Company and Subsidiaries
7
<PAGE>
Gas Operations
Gas Revenues
The changes in gas revenues in 1996 and 1995 compared to the respective prior
year were caused by:
1996 1995
- --------------------------------------------------------------------------------
(In millions)
Gas system sales volumes $ 8.2 $ 0.2
Base rates 18.9 6.4
Gas cost adjustments 62.1 (27.4)
---------------------
Total change in gas revenues
from gas system sales 89.2 (20.8)
Off-system sales 26.6 --
Other 1.0 0.1
---------------------
Total change in gas revenues $116.8 $(20.7)
=====================
Gas System Sales Volumes
The percentage changes in our gas system sales volumes, by type of customer, in
1996 and 1995 compared to the respective prior year were:
1996 1995
- --------------------------------------------------------------------------------
Residential 8.9% (0.2)%
Commercial 2.8 1.3
Industrial (2.3) 47
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.
In 1995, we sold about the same amount of gas to residential customers as we did
in 1994. We sold more gas to commercial customers for three reasons: an increase
in the number of customers, increased gas usage per customer, and colder weather
in the fall of 1995. We would have sold even more gas to commercial customers
except for milder weather in the first half of 1995. We sold more gas to
industrial customers due to greater gas usage per customer.
Base Rates
In 1996, base rate revenues were higher than in 1995 because in November 1995,
the Maryland Commission allowed us to increase our gas base rates. This
increased our annual base rate revenues for 1996 by $19.3 million, or
approximately 3.7% of total 1996 gas revenues. 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).
In 1995, our base rate revenues were higher than in 1994 because of the energy
conservation surcharge.
Gas Cost Adjustments
Prior to October 1996, the Maryland Commission allowed us to recover the actual
cost of the gas sold to our customers through "gas cost adjustment clauses."
These clauses require that we defer the difference between our actual cost of
gas and the gas revenues we collect from customers. We bill or refund that
difference to customers in the future.
Effective October 1996, the Maryland Commission approved a modification of the
gas cost adjustment clauses to provide a "Market Based Rates" incentive
mechanism. In general terms, 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), and half of the difference belongs to shareholders. We discuss this in
more detail in Note 1 on page 23.
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 1996, gas cost revenues increased because we had to pay more for gas and we
sold more gas. In 1995, gas cost revenues decreased because we paid less for gas
and we sold less gas.
Off-System Sales
Off-system gas sales, which are direct sales to suppliers and end users of
natural gas outside our service territory, also are not subject to gas cost
adjustments. We began sales of off-system gas during the first quarter of 1996.
The Maryland Commission 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).
Gas Purchased For Resale Expenses
1996 1995 1994
- --------------------------------------------------------------------------------
(In millions)
Actual costs $295.4 $205.9 $222.7
Net recovery (deferral) of
costs under gas adjustment
clauses (see Note 1) (11.0) (7.8) 1.9
---------------------------
Total gas purchased for
resale expenses $284.4 $198.1 $224.6
===========================
Actual Costs
Actual costs include the cost of gas purchased for resale to our customers and
for sale off-system. These costs do not include the cost of gas purchased by
delivery service customers, including Bethlehem Steel.
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).
In 1995, actual gas costs decreased compared to 1994 because of the considerably
lower market price of gas. This decrease would have been even greater except
that we received supplier refunds in 1994 which reduced actual gas costs that
year.
Gas Adjustment Clauses
We charge customers for the cost of gas sold through gas adjustment clauses
(determined by the Maryland Commission), as discussed under "Gas Cost
Adjustments" earlier in this section.
In 1996 and 1995, the portion of our actual gas costs subject to these clauses
was higher than the revenues we collected from our customers. As a result, we
deferred the difference and will collect the costs from our customers in the
future. These deferrals decreased our total gas purchased for resale expenses in
1996 and 1995.
Baltimore Gas and Electric Company and Subsidiaries
8
<PAGE>
Other Operating Expenses
Operations and Maintenance Expenses
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. In 1995, our
operations and maintenance expenses were about the same as they were in 1994.
Depreciation and Amortization Expenses
We describe depreciation and amortization expenses in Note 1 on page 24.
In 1996, our depreciation and amortization expense increased $12.8 million from
1995 for two reasons:
(bullet) we had more utility plant in service to be depreciated (as our level of
utility plant that is in service changes, the amount of our
depreciation expense changes), and
(bullet) we had more energy conservation program costs to be amortized.
The increase in these expenses would have been even greater except that in 1995
depreciation and amortization expense included $14.2 million for the write-off
of certain costs of our Perryman site, which is covered in more detail below. In
1996, depreciation and amortization expense did not include any such write-off.
In 1995, our depreciation and amortization expense increased $21.5 million over
1994 because we had more utility plant in service to be depreciated (mostly
because of some capital additions to our Calvert Cliffs Nuclear Power Plant),
and we had a higher level of energy conservation program costs to be amortized.
In addition, we completed a study of the cost to decommission Calvert Cliffs.
(Decommission is a term used in the nuclear industry for the permanent shut-down
of a nuclear power plant which usually occurs when the plant's license expires.)
The study resulted in a higher estimated cost of decommissioning, which
increased decommissioning expense (included in depreciation and amortization
expense) by $9 million annually.
Our 1995 and 1994 depreciation and amortization expense reflected the write-off
of expenditures associated with future generation facilities at our Perryman
site which will not be built. We discuss the write-off of expenditures at our
Perryman site further in Note 1 on page 24. The write-off of these costs
increased our 1995 depreciation and amortization expense by $14.2 million and
increased our 1994 expense by $15.7 million.
Taxes Other Than Income Taxes
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.
In 1995, taxes (other than income taxes) were $5.4 million higher than in 1994
mostly due to higher property taxes resulting from more utility plant in
service.
Other Income and Expenses
Allowance for Funds Used During Construction (AFC)
AFC is an accounting procedure used to exclude the cost of capital from expense
and include it as part of the cost of utility plant construction. AFC is
calculated at a rate authorized by the Maryland Commission. We describe AFC
further in Note 1 on page 24.
In 1996 and 1995, we had lower AFC compared to prior years because we completed
several projects and started less new construction. In 1996, we also had lower
AFC because the Maryland Commission decreased the gas AFC rate in November 1995
from 9.40% to 9.04%. This meant we were not authorized to record as much gas AFC
in 1996 as we were in 1995 and 1994.
Net Other Income and Deductions
Net other income and deductions represent miscellaneous income and expenses
which are not directly related to operations.
In 1996, net other income and deductions increased $4.9 million compared to 1995
mostly because the Constellation Companies had lower deductions not directly
related to operations and BGE had about $2 million more of other interest and
finance charge income.
In 1995, net other income and deductions decreased $16.2 million compared to
1994 because we had about $12 million less of other interest and finance charge
income, and we had about $4 million lower income from the sale of receivables
(money customers owe to us) and property. We sell receivables to a financial
institution under agreements which are discussed in Note 12 on page 32.
Interest Charges
Interest charges represent the interest we paid on outstanding debt.
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.
In 1995, we had $5.3 million higher interest charges compared to 1994 because we
had more debt outstanding and short-term interest rates were higher.
Income Taxes
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.
In 1995, our income taxes increased because we had higher taxable income from
both our utility operations and our diversified businesses.
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 on page 33 and in our Annual Reports 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.
Baltimore Gas and Electric Company and Subsidiaries
9
<PAGE>
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 include:
(bullet) Constellation Holdings, Inc. and Subsidiaries, together known as the
Constellation Companies
(bullet) BGE Home Products & Services, Inc. and Subsidiary
(bullet) BGE Energy Projects & Services, Inc. and Subsidiaries
(bullet) Constellation Energy Source, Inc. (formerly named BNG, Inc.)
Diversified Business Earnings Per Share of Common Stock
1996 1995 1994
- --------------------------------------------------------------------------------
Constellation Companies $ .29 $ .18 $ .09
BGE Home Products & Services .02 .00 .03
BGE Energy Projects & Services .00 .00 -
Constellation Energy Source .00 .00 .00
-------------------------
Total diversified business
earnings per share $ .31 $ .18 $ .12
=========================
Our 1996 diversified business earnings increased $19.3 million, or $.13 per
share, from 1995. Our 1995 diversified business earnings increased $8.2 million,
or $.06 per share, from 1994. These increases mostly reflect higher earnings
from the Constellation Companies.
We discuss factors affecting the earnings of each diversified business
subsidiary below.
Constellation Companies' Operations
The Constellation Companies engage in the following:
(bullet) development, ownership, and operation of power generation projects,
(bullet) financial investments, and
(bullet) development, ownership, and management of real estate and
senior-living facilities.
Earnings per share from the Constellation Companies were:
1996 1995 1994
- --------------------------------------------------------------------------------
Power generation $ .18 $ .13 $ .10
Financial investments .14 .08 .03
Real estate development and
senior-living facilities (.02) (.02) (.03)
Other (.01) (.01) (.01)
-------------------------
Total Constellation Companies'
earnings per share $ .29 $ .18 $ .09
=========================
Power Generation
The Constellation Companies' power generation business develops, owns, and
operates power generation facilities.
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:
(bullet) a $7.0 million after-tax write-off of Constellation's investment in
two geothermal wholesale power generating projects,
(bullet) a $3.0 million after-tax write-off of development costs for a proposed
coal-fired power project that will not be built, and
(bullet) a $6.2 million after-tax write-off of a portion of an investment in a
solar power project, in which Constellation has a minority ownership
interest, expected to be restructured with the lender.
In 1995, earnings increased from 1994 mostly due to our share of higher
earnings from energy projects and a profit made on the sale of some
operating and maintenance contracts.
California Power Purchase Agreements
The Constellation Companies have $227 million invested in 16 projects that
sell electricity in California under power purchase agreements called "Interim
Standard Offer No. 4" agreements.
Under these agreements, the projects supply electricity to utility companies at:
(bullet) a fixed rate for capacity and energy the first 10 years of the
agreements, and
(bullet) 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.
From 1996 through 2000, the 10-year periods for fixed energy rates expire for
these 16 power generation projects and they begin supplying electricity at
variable rates. When this happens, the revenues at these projects are expected
to be lower than they are now. It is difficult to estimate how much lower the
revenues may be, but the Constellation Companies' earnings could be affected
significantly.
Eight projects begin supplying electricity at variable rates in 1997 and 1998.
This means the Constellation Companies could experience lower earnings from
those projects. However, the remaining projects, which will continue to supply
electricity at fixed rates, are expected to have higher revenues in 1997 and
1998. These higher revenues may offset the lower revenues from the variable-rate
projects during those years.
The California projects that make the highest revenues will begin supplying
electricity at variable rates in 1999 and 2000. As a result, we do not expect
the Constellation Companies to have significantly lower earnings due to the
switch from fixed to variable rates before 2000.
Baltimore Gas and Electric Company and Subsidiaries
10
<PAGE>
In the second quarter of 1996, Constellation determined that its investments in
two of these plants are not expected to be fully recoverable. Accordingly, as
mentioned earlier in this section, the Constellation Companies recorded a $7.0
million after-tax write-off of the investment in these plants.
Constellation is pursuing alternatives for some of these power generation
projects including:
(bullet) repowering the projects to reduce operating costs,
(bullet) changing fuels to reduce operating costs,
(bullet) renegotiating the power purchase agreements to improve the terms,
(bullet) restructuring financings to improve the financing terms, and
(bullet) selling its ownership interests in the projects.
We cannot predict the financial effects of the switch from fixed to variable
rates on the Constellation Companies or on BGE, but the effects could be
material.
International
Historically, Constellation's power generation projects have been in the United
States. Over the last two years, however, Constellation has sought projects
in Latin America. As of December 31, 1996, Constellation had invested about
$17.1 million and committed another $6.5 million in power projects in Latin
America. In the future, Constellation's power generation business may be
expanding further in both domestic and international projects.
Financial Investments
Earnings from Constellation's portfolio of financial investments include:
(bullet) income from marketable securities,
(bullet) income from financial limited partnerships, and
(bullet) income from financial guaranty insurance companies.
In 1996, earnings were higher than in 1995 because of better earnings from
marketable securities and increased gains from financial limited partnerships.
In 1995, earnings were higher compared to 1994 due to: increased earnings from
marketable securities, increased gains from financial limited partnerships, and
higher earnings from financial guaranty insurance companies.
Real Estate Development and Senior-Living Facilities
Constellation's real estate development business includes:
(bullet) land under development,
(bullet) office buildings,
(bullet) retail projects,
(bullet) distribution facility projects,
(bullet) an entertainment, dining, and retail complex in Orlando, Florida,
(bullet) a mixed-use planned-unit development, and
(bullet) senior-living facilities.
Most of these 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. Our projects have been
economically hurt by these conditions. Earnings from real estate development and
senior-living facilities in 1996 and 1995 were essentially
unchanged from prior years.
Constellation's real estate portfolio has continued to incur carrying costs and
depreciation over the years. Additionally, the Constellation 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 Companies and through additional
borrowing.
We will 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. We believe that until the economy shows sustained growth and
there is more demand for new development, our real estate values will not
improve much. 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, changes in the
utility industry, and the proposed merger with Potomac Electric Power Company,
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.
It may be helpful for you to understand when we are required, by accounting
rules, to writedown the value of a real estate investment to market value. A
writedown 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.
BGE Home Products & Services' Operations
BGE Home Products & Services engages in:
(bullet) sales and service of electric and gas appliances,
(bullet) home improvements, and
(bullet) sales and service of heating and air conditioning systems.
In 1996, earnings increased due to improved performance in the service and
installation business. In 1995, earnings decreased compared to 1994 largely due
to lower income from the sale of receivables during 1995. We sell receivables to
a financial institution under agreements which are discussed in Note 12 on page
32.
Baltimore Gas and Electric Company and Subsidiaries
11
<PAGE>
BGE Energy Projects & Services' Operations
BGE Energy Projects & Services provides a broad range of customized energy
services, including:
(bullet) power quality services,
(bullet) customer electrical system improvements,
(bullet) lighting and mechanical engineering and installation services,
(bullet) campus and multi-building energy systems,
(bullet) energy consulting and financial contracts,
(bullet) district energy systems through Comfort Link (a partnership with the
Poole and Kent Company), and
(bullet) private electric and gas distribution systems.
This subsidiary was formed in November 1995. It had no significant earnings in
1996 or 1995.
Constellation Energy Source's Operations
Constellation Energy Source (formerly named BNG, Inc.) engages in natural gas
brokering. This subsidiary had no significant earnings in 1996 or 1995.
- --------------------------------------------------------------------------------
Liquidity and Capital Resources
Overview
Our business requires a great deal of capital. Our actual capital requirements
for the years 1994 through 1996, along with estimated amounts for the years 1997
through 1999, are shown below.
<TABLE>
<CAPTION>
1994 1995 1996 1997 1998 1999
- ---------------------------------------------------------------------------------------------------------------------------
(In millions)
<S> <C>
Utility Business Capital Requirements:
Construction expenditures (excluding AFC)
Electric $345 $223 $219 $230 $216 $ 215
Gas 68 70 84 72 70 73
Common 42 51 46 33 39 37
-----------------------------------------------------
Total construction expenditures 455 344 349 335 325 325
AFC 34 22 10 7 7 7
Nuclear fuel (uranium purchases and processing charges) 42 46 47 49 50 50
Deferred energy conservation expenditures 41 46 31 24 19 18
Deferred nuclear expenditures 8 -- -- -- -- --
Retirement of long-term debt and redemption of preference stock 203 279 184 173 117 270
-----------------------------------------------------
Total utility business capital requirements 783 737 621 588 518 670
-----------------------------------------------------
Diversified Business Capital Requirements:
Investment requirements 51 118 118 214 180 205
Retirement of long-term debt 37 55 52 108 165 186
-----------------------------------------------------
Total diversified business capital requirements 88 173 170 322 345 391
-----------------------------------------------------
Total capital requirements $871 $910 $791 $910 $863 $1,061
=====================================================
</TABLE>
Capital Requirements of Our Utility Business
Capital requirements for our utility business do not include costs to complete
the pending merger with Potomac Electric Power Company. These costs, currently
estimated to be $150 million, are discussed in more detail in Note 12 on page
32.
We continuously review and change our construction program, so actual
expenditures may vary from the estimates for the years 1997 through 1999 in the
capital requirements chart. Additionally, actual capital requirements may be
different than the estimates for 1997 through 1999 because adjustments which may
result from the pending merger with Potomac Electric Power Company have not been
considered in those estimates.
Electric construction expenditures include:
(bullet) installation of a 5,000 kilowatt diesel generator which was placed in
service in 1996 at our Calvert Cliffs Nuclear Power Plant, and
(bullet) improvements to other generating plants and to our transmission and
distribution facilities.
Our projections of future electric construction expenditures do not include
costs to build more generating units.
Our utility operations provided about 96% in 1996, 100% in 1995, and 72% in
1994, of the cash needed to meet our capital requirements, excluding cash needed
to retire debt and redeem preferred and preference stock. In addition, in 1994,
the sale of some receivables provided $70 million in cash. This is discussed in
more detail in Note 12 on page 32.
Baltimore Gas and Electric Company and Subsidiaries
12
<PAGE>
During the three years from 1997 through 1999, we expect utility operations to
provide 115% of the cash needed to meet our capital requirements, excluding cash
needed to retire debt and redeem preference stock. This estimate does not
consider the pending merger with Potomac Electric Power Company.
When we cannot meet utility capital requirements internally, we sell debt and
equity securities. The amount of cash we need and market conditions determine
when and how much we sell. During the three years ended December 31, 1996, we
sold:
(bullet) $540 million of long-term debt,
(bullet) $60 million of preference stock, and
(bullet) $39 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 to
sell these securities. The better the rating, the cheaper it is for us to sell.
At the date of this report, our securities ratings were as follows:
Standard Moody's
& Poors Investors Duff & Phelps
Rating Group Service Credit Rating Co.
- --------------------------------------------------------------------------------
Mortgage Bonds A+ 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 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 on
page 12. As discussed below under "Investment Requirements," capital
requirements for Comfort Link are also included this year.
Our Constellation Companies and other diversified businesses expect to expand
their businesses. This will include our new power marketing business. It also
may include expansion in the energy, financial investments, real estate, and
senior-living facility businesses. Such expansion could mean more investments in
and acquisition of new projects. Our Constellation Companies and other
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 Constellation Companies and other diversified
businesses plan to raise the cash needed to meet capital requirements in the
future through these same methods.
Investment Requirements
The investment requirements of our diversified businesses include:
(bullet) for the Constellation Companies, investments in financial limited
partnerships and funding for the development and acquisition of
projects, as well as loans made to project partnerships, and
(bullet) for BGE Energy Projects & Services, funding for construction of
district energy projects of Comfort Link.
Investment requirements for 1997 through 1999 include estimates of funding for
existing and new projects and for our new power marketing business. We
continuously review and modify those estimates. Actual investment
requirements could vary a great deal from the estimates on page 12 because
they would be subject to several variables, including:
(bullet) the type and number of projects selected for development,
(bullet) the effect of market conditions on those projects,
(bullet) opportunities for growth in the power marketing business,
(bullet) the ability to obtain financing, and
(bullet) the availability of cash from operations.
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 as discussed in Note 12 on page 32.
If Constellation can get a reasonable value for its real estate, it could obtain
additional cash by selling real estate projects. For more information, see the
discussion of the real estate business and market on page 11. Constellation's
ability to sell or liquidate assets will depend on market conditions, and we
cannot give assurances that these sales or liquidations could be made.
In addition, Constellation has a $75 million revolving credit agreement and
Comfort Link has a $50 million revolving credit agreement to provide additional
cash for short-term financial needs.
Baltimore Gas and Electric Company and Subsidiaries
13
<PAGE>
Report of Management
The management of the Company is responsible for the information and
representations in the Company's financial statements. The Company prepares the
financial statements in accordance with generally accepted accounting principles
based upon available facts and circumstances and management's best estimates and
judgments of known conditions.
The Company maintains an accounting system and related system of internal
controls designed to provide reasonable assurance that the financial records
are accurate and that the Company's assets are protected. The Company's
staff of internal auditors, which reports directly to the Chairman of the Board,
conducts periodic reviews to maintain the effectiveness of internal control
procedures. Coopers & Lybrand L.L.P., independent accountants, audit the
financial statements and express their opinion about them. They perform their
audit in accordance with generally accepted auditing standards.
The Audit Committee of the Board of Directors, which consists of four outside
Directors, meets periodically with Management, internal auditors, and Coopers &
Lybrand L.L.P. to review the activities of each in discharging their
responsibilities. The internal audit staff and Coopers & Lybrand L.L.P. have
free access to the Audit Committee.
/s/ Christian H. Poindexter /s/ Charles W. Shivery
___________________________ _________________________
Christian H. Poindexter Charles W. Shivery
Chairman of the Board Chief Financial Officer
and Chief Executive Officer
Report of Independent Accountants
To the Shareholders of
Baltimore Gas and Electric Company
We have audited the accompanying consolidated balance sheets and statements of
capitalization of Baltimore Gas and Electric Company and Subsidiaries as of
December 31, 1996 and 1995, and the related consolidated statements of income,
cash flows, common shareholders' equity, and income taxes for each of the three
years in the period ended December 31, 1996. These financial statements are the
responsibility of the Company's Management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
Management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of Baltimore Gas and
Electric Company and Subsidiaries as of December 31, 1996 and 1995, and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 1996 in conformity with generally
accepted accounting principles.
/s/ Coopers & Lybrand L.L.P.
______________________________
Coopers & Lybrand L.L.P.
Baltimore, Maryland
January 17, 1997
14
<PAGE>
Consolidated Statements of Income
<TABLE>
<CAPTION>
Year Ended December 31, 1996 1995 1994
- ---------------------------------------------------------------------------------------------------------------------------
(In thousands, except per share amounts)
<S> <C>
Revenues
Electric $2,208,744 $2,229,774 $2,126,581
Gas 517,292 400,504 421,249
Diversified businesses 427,211 304,521 235,155
-------------------------------------------------
Total revenues 3,153,247 2,934,799 2,782,985
-------------------------------------------------
Expenses Other Than Interest and Income Taxes
Electric fuel and purchased energy 547,414 578,801 542,314
Disallowed replacement energy costs (see Note 12) 95,369 -- --
Gas purchased for resale 284,443 198,069 224,590
Operations 526,424 550,811 552,817
Maintenance 174,141 168,269 164,892
Diversified businesses - selling, general, and administrative 311,053 220,573 167,430
Depreciation and amortization 330,191 317,417 295,950
Taxes other than income taxes 214,747 205,167 199,733
-------------------------------------------------
Total expenses other than interest and income taxes 2,483,782 2,239,107 2,147,726
-------------------------------------------------
Income from Operations 669,465 695,692 635,259
-------------------------------------------------
Other Income
Allowance for equity funds used during construction 6,508 14,162 21,746
Equity in earnings of Safe Harbor Water Power Corporation 4,596 4,559 4,349
Net other income and (deductions) (4,974) (9,902) 6,270
-------------------------------------------------
Total other income 6,130 8,819 32,365
-------------------------------------------------
Income Before Interest and Income Taxes 675,595 704,511 667,624
-------------------------------------------------
Interest Expense
Interest charges 217,622 219,689 214,347
Capitalized interest (15,664) (15,050) (12,427)
Allowance for borrowed funds used during construction (3,520) (7,662) (11,766)
-------------------------------------------------
Net interest expense 198,438 196,977 190,154
-------------------------------------------------
Income Before Income Taxes 477,157 507,534 477,470
Income Taxes 166,333 169,527 153,853
-------------------------------------------------
Net Income 310,824 338,007 323,617
Preferred and Preference Stock Dividends 38,536 40,578 39,922
-------------------------------------------------
Earnings Applicable to Common Stock $ 272,288 $ 297,429 $ 283,695
=================================================
Average Shares of Common Stock Outstanding 147,560 147,527 147,100
Earnings Per Share of Common Stock $1.85 $2.02 $1.93
=================================================
</TABLE>
See Notes to Consolidated Financial Statements.
Baltimore Gas and Electric Company and Subsidiaries
15
<PAGE>
Consolidated Balance Sheets
<TABLE>
<CAPTION>
At December 31, 1996 1995
- ----------------------------------------------------------------------------------------------------------------
(In thousands)
<S> <C>
Assets
Current Assets
Cash and cash equivalents $ 66,708 $ 23,443
Accounts receivable (net of allowance for uncollectibles
of $18,028 and $16,390, respectively) 419,479 400,005
Trading securities 68,794 47,990
Fuel stocks 87,073 59,614
Materials and supplies 147,729 145,900
Prepaid taxes other than income taxes 64,763 60,508
Deferred income taxes 2,943 36,831
Other 44,709 31,487
--------------------------------
Total current assets 902,198 805,778
--------------------------------
Investments and Other Assets
Real estate projects 525,765 479,344
Power generation projects 379,130 358,629
Financial investments 204,443 205,841
Nuclear decommissioning trust fund 116,368 85,811
Net pension asset 84,510 60,077
Safe Harbor Water Power Corporation 34,363 34,327
Senior living facilities 36,415 16,045
Other 92,171 71,894
--------------------------------
Total investments and other assets 1,473,165 1,311,968
--------------------------------
Utility Plant
Plant in service
Electric 6,514,950 6,360,624
Gas 776,973 692,693
Common 523,485 522,450
--------------------------------
Total plant in service 7,815,408 7,575,767
Accumulated depreciation (2,613,355) (2,481,801)
--------------------------------
Net plant in service 5,202,053 5,093,966
Construction work in progress 221,857 247,296
Nuclear fuel (net of amortization) 132,937 130,782
Plant held for future use 25,503 25,552
--------------------------------
Net utility plant 5,582,350 5,497,596
--------------------------------
Deferred Charges
Regulatory assets (net) 512,279 637,915
Other 80,978 63,406
--------------------------------
Total deferred charges 593,257 701,321
--------------------------------
Total Assets $8,550,970 $8,316,663
================================
</TABLE>
See Notes to Consolidated Financial Statements.
Baltimore Gas and Electric Company and Subsidiaries
16
<PAGE>
Consolidated Balance Sheets
<TABLE>
<CAPTION>
At December 31, 1996 1995
- --------------------------------------------------------------------------------------------------------------------
(In thousands)
<S> <C>
Liabilities and Capitalization
Current Liabilities
Short-term borrowings $ 333,185 $ 279,305
Current portions of long-term debt and preference stock 280,772 146,969
Accounts payable 172,889 177,092
Customer deposits 27,993 26,857
Accrued taxes 6,473 8,244
Accrued interest 57,440 56,670
Dividends declared 66,950 67,198
Accrued vacation costs 34,351 33,403
Other 37,046 39,417
-----------------------------------
Total current liabilities 1,017,099 835,155
-----------------------------------
Deferred Credits and Other Liabilities
Deferred income taxes 1,300,174 1,311,530
Postretirement and postemployment benefits 169,253 148,594
Decommissioning of federal uranium enrichment facilities 38,599 43,695
Other 65,463 55,568
-----------------------------------
Total deferred credits and other liabilities 1,573,489 1,559,387
-----------------------------------
Capitalization
Long-term debt 2,758,769 2,598,254
Preferred stock -- 59,185
Redeemable preference stock 134,500 242,000
Preference stock not subject to mandatory redemption 210,000 210,000
Common shareholders' equity 2,857,113 2,812,682
-----------------------------------
Total capitalization 5,960,382 5,922,121
-----------------------------------
Commitments, Guarantees, and Contingencies - See Note 12
Total Liabilities and Capitalization $8,550,970 $8,316,663
===================================
</TABLE>
See Notes to Consolidated Financial Statements.
Baltimore Gas and Electric Company and Subsidiaries
17
<PAGE>
Consolidated Statements of Cash Flows
<TABLE>
<CAPTION>
Year Ended December 31, 1996 1995 1994
- ---------------------------------------------------------------------------------------------------------------------------
(In thousands)
<S> <C>
Cash Flows From Operating Activities
Net income $310,824 $338,007 $323,617
Adjustments to reconcile to net cash provided by operating activities
Depreciation and amortization 383,155 378,977 351,064
Deferred income taxes 26,009 103,494 79,278
Investment tax credit adjustments (7,655) (8,088) (8,192)
Deferred fuel costs 528 5,565 11,461
Deferred energy conservation revenues 28,500 1,283 18,769
Disallowed replacement energy costs 95,369 -- --
Accrued pension and postemployment benefits (13,792) (7,641) (41,113)
Allowance for equity funds used during construction (6,508) (14,162) (21,746)
Equity in earnings of affiliates and joint ventures (net) (48,305) (21,259) (20,225)
Changes in current assets other than sale of accounts receivable (88,035) (107,392) (10,536)
Changes in current liabilities, other than short-term borrowings (4,905) (7,293) (24,447)
Other 26,762 6,661 (5,699)
----------------------------------------------
Net cash provided by operating activities 701,947 668,152 652,231
----------------------------------------------
Cash Flows From Financing Activities
Proceeds from issuance of
Short-term borrowings (net) 53,880 215,605 63,700
Long-term debt 383,182 184,422 207,169
Preference stock -- 59,329 --
Common stock 3,729 318 33,869
Proceeds from sale of receivables 10,000 2,000 70,000
Reacquisition of long-term debt (158,551) (315,105) (240,853)
Reacquisition of preferred and preference stock (112,559) (73,000) (4,406)
Common stock dividends paid (233,109) (227,192) (220,152)
Preferred and preference stock dividends paid (37,050) (40,087) (39,950)
Other (1,172) 13 (437)
----------------------------------------------
Net cash used in financing activities (91,650) (193,697) (131,060)
----------------------------------------------
Cash Flows From Investing Activities
Utility construction expenditures (including AFC) (360,485) (366,037) (488,976)
Allowance for equity funds used during construction 6,508 14,162 21,746
Nuclear fuel expenditures (46,761) (46,330) (42,089)
Deferred nuclear expenditures -- -- (8,393)
Deferred energy conservation expenditures (31,383) (45,503) (40,440)
Contributions to nuclear decommissioning trust fund (25,483) (9,780) (9,780)
Purchases of marketable equity securities (32,664) (18,447) (52,099)
Sales of marketable equity securities 39,657 49,788 40,585
Other financial investments 7,068 9,423 2,469
Real estate projects (55,344) (15,599) 14,926
Power generation systems (5,332) (34,408) (1,116)
Other (62,813) (26,871) (3,650)
----------------------------------------------
Net cash used in investing activities (567,032) (489,602) (566,817)
----------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents 43,265 (15,147) (45,646)
Cash and Cash Equivalents at Beginning of Year 23,443 38,590 84,236
----------------------------------------------
Cash and Cash Equivalents at End of Year $ 66,708 $ 23,443 $ 38,590
==============================================
Other Cash Flow Information
Cash paid during the year for:
Interest (net of amounts capitalized) $182,431 $195,308 $184,441
Income taxes $160,132 $ 99,623 $ 83,143
</TABLE>
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
18
<PAGE>
Consolidated Statements
of Common Shareholders' Equity
<TABLE>
<CAPTION>
Unrealized
Gain (Loss)
on Available Pension
Common Stock Retained For Sale Liability Total
Years Ended December 31, 1996, 1995, and 1994 Shares Amount Earnings Securities Adjustment Amount
- ---------------------------------------------------------------------------------------------------------------------------------
(In thousands)
<S> <C>
Balance at December 31, 1993 146,034 $1,391,464 $1,251,140 $ -- $(22,093) $2,620,511
Net income 323,617 323,617
Dividends declared
Preferred and preference stock (39,922) (39,922)
Common stock ($1.51 per share) (222,180) (222,180)
Common stock issued 1,493 33,869 33,869
Other 45 45
Net unrealized loss on securities (5,609) (5,609)
Deferred taxes on net unrealized loss on securities 1,963 1,963
Pension liability adjustment 8,573 8,573
Deferred taxes on pension liability adjustment (3,001) (3,001)
------------------------------------------------------------------------
Balance at December 31, 1994 147,527 1,425,378 1,312,655 (3,646) (16,521) 2,717,866
Net income 338,007 338,007
Dividends declared
Preferred and preference stock (40,578) (40,578)
Common stock ($1.55 per share) (228,667) (228,667)
Common stock issued 318 318
Other 109 109
Net unrealized gain on securities 14,010 14,010
Deferred taxes on net unrealized gain on securities (4,904) (4,904)
Pension liability adjustment 25,417 25,417
Deferred taxes on pension liability adjustment (8,896) (8,896)
------------------------------------------------------------------------
Balance at December 31, 1995 147,527 1,425,805 1,381,417 5,460 -- 2,812,682
Net income 310,824 310,824
Dividends declared
Preferred and preference stock (38,536) (38,536)
Common stock ($1.59 per share) (234,640) (234,640)
Common stock issued 140 3,729 3,729
Other 408 408
Net unrealized gain on securities 4,071 4,071
Deferred taxes on net unrealized gain on securities (1,425) (1,425)
------------------------------------------------------------------------
Balance at December 31, 1996 147,667 $1,429,942 $1,419,065 $8,106 $ -- $2,857,113
========================================================================
</TABLE>
See Notes to Consolidated Financial Statements.
Baltimore Gas and Electric Company and Subsidiaries
19
<PAGE>
Consolidated Statements of Capitalization
<TABLE>
<CAPTION>
At December 31, 1996 1995
- ---------------------------------------------------------------------------------------------------------------------------
(In thousands)
<S> <C>
Long-Term Debt
First Refunding Mortgage Bonds of BGE
5-1/8% Series, due April 15, 1996 $ -- $ 26,187
6-1/8% Series, due August 1, 1997 24,935 24,935
Floating rate series, due April 15, 1999 125,000 125,000
8.40% Series, due October 15, 1999 91,137 91,200
5-1/2% Series, due July 15, 2000 124,990 125,000
8-3/8% Series, due August 15, 2001 122,377 122,427
7-1/8% Series, due January 1, 2002 22,737 39,698
7-1/4% Series, due July 1, 2002 124,484 124,609
5-1/2% Installment Series, due July 15, 2002 10,440 11,045
6-1/2% Series, due February 15, 2003 124,822 124,882
6-1/8% Series, due July 1, 2003 124,855 124,925
5-1/2% Series, due April 15, 2004 124,995 124,995
Remarketed floating rate series, due September 1, 2006 125,000 --
7-1/2% Series, due January 15, 2007 123,652 123,667
6-5/8% Series, due March 15, 2008 124,960 124,985
7-1/2% Series, due March 1, 2023 124,973 124,973
7-1/2% Series, due April 15, 2023 100,000 100,000
----------------------------------
Total First Refunding Mortgage Bonds of BGE 1,619,357 1,538,528
----------------------------------
Other long-term debt of BGE
Term bank loan due March 29, 2001 50,000 50,000
Medium-term notes, Series A -- 10,500
Medium-term notes, Series B 100,000 100,000
Medium-term notes, Series C 183,000 200,000
Medium-term notes, Series D 138,000 28,000
Pollution control loan, due July 1, 2011 36,000 36,000
Port facilities loan, due June 1, 2013 48,000 48,000
Adjustable rate pollution control loan, due July 1, 2014 20,000 20,000
5.55% Pollution control revenue refunding loan, due July 15, 2014 47,000 47,000
Economic development loan, due December 1, 2018 35,000 35,000
6.00% Pollution control revenue refunding loan, due April 1, 2024 75,000 75,000
----------------------------------
Total other long-term debt of BGE 732,000 649,500
----------------------------------
Long-term debt of Constellation Companies
Revolving credit agreement
Variable rates based on LIBOR, due December 9, 1999 65,000 1,000
Mortgage and construction loans and other collateralized notes
8.00%, due July 31, 2001 141 --
8.00%, due October 30, 2003 1,500 --
Variable rates, due through 2009 128,571 110,018
7.50%, due October 9, 2005 9,846 9,989
7.357%, due March 15, 2009 5,763 5,896
9.65%, due February 1, 2028 9,746 --
Unsecured notes 387,160 420,000
----------------------------------
Total long-term debt of Constellation Companies 607,727 546,903
----------------------------------
Long-term debt of other diversified businesses
Loans under revolving credit agreements 12,000 --
----------------------------------
Unamortized discount and premium (14,543) (15,708)
Current portion of long-term debt (197,772) (120,969)
----------------------------------
Total long-term debt $2,758,769 $2,598,254
----------------------------------
</TABLE>
continued on page 21
See Notes to Consolidated Financial Statements.
Baltimore Gas and Electric Company and Subsidiaries
20
<PAGE>
Consolidated Statements of Capitalization
<TABLE>
<CAPTION>
At December 31, 1996 1995
- ---------------------------------------------------------------------------------------------------------------------------
(In thousands)
<S> <C>
Preferred Stock
Cumulative, $100 par value, 1,000,000 shares authorized
Series B, 4 1/2%, 222,921 shares redeemed at $110 per share on May 28, 1996 $ -- $ 22,292
Series C, 4%, 68,928 shares redeemed at $105 per share on May 28, 1996 -- 6,893
Series D, 5.40%, 300,000 shares redeemed at $101 per share on May 28, 1996 -- 30,000
----------------------------------
Total preferred stock -- 59,185
----------------------------------
Preference Stock
Cumulative, $100 par value, 6,500,000 shares authorized
Redeemable preference stock
7.50%, 1986 Series, 395,000 and 425,000 shares outstanding. Callable
at $102.50 per share prior to October 1, 2001 and at lesser amounts thereafter 39,500 42,500
6.75%, 1987 Series, 440,000 and 455,000 shares outstanding. Callable at
$104.50 per share prior to April 1, 1997 and at lesser amounts thereafter 44,000 45,500
7.80%, 1989 Series, 500,000 shares outstanding 50,000 50,000
8.25%, 1989 Series, 100,000 and 300,000 shares outstanding 10,000 30,000
8.625%, 1990 Series, 390,000 and 650,000 shares outstanding 39,000 65,000
7.85%, 1991 Series, 350,000 shares outstanding 35,000 35,000
Current portion of redeemable preference stock (83,000) (26,000)
----------------------------------
Total redeemable preference stock 134,500 242,000
----------------------------------
Preference stock not subject to mandatory redemption
7.78%, 1973 Series, 200,000 shares outstanding, callable at $101 per share 20,000 20,000
7.125%, 1993 Series, 400,000 shares outstanding, not callable prior to July 1, 2003 40,000 40,000
6.97%, 1993 Series, 500,000 shares outstanding, not callable prior to October 1, 2003 50,000 50,000
6.70%, 1993 Series, 400,000 shares outstanding, not callable prior to January 1, 2004 40,000 40,000
6.99%, 1995 Series, 600,000 shares outstanding, not callable prior to October 1, 2005 60,000 60,000
----------------------------------
Total preference stock not subject to mandatory redemption 210,000 210,000
----------------------------------
Common Shareholders' Equity
Common stock without par value, 175,000,000 shares authorized; 147,667,114 and
147,527,114 shares issued and outstanding at December 31, 1996 and 1995,
respectively. (At December 31, 1996, 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.) 1,429,942 1,425,805
Retained earnings 1,419,065 1,381,417
Unrealized gain (loss) on available-for-sale securities 8,106 5,460
----------------------------------
Total common shareholders' equity 2,857,113 2,812,682
----------------------------------
Total Capitalization $5,960,382 $5,922,121
==================================
</TABLE>
See Notes to Consolidated Financial Statements.
Baltimore Gas and Electric Company and Subsidiaries
21
<PAGE>
Consolidated Statements of Income Taxes
<TABLE>
<CAPTION>
Year Ended December 31, 1996 1995 1994
- ----------------------------------------------------------------------------------------------------------------------------------
(Dollar amounts in thousands)
<S> <C>
Income Taxes
Current $147,979 $ 74,121 $ 82,767
-------------------------------------------------
Deferred
Change in tax effect of temporary differences 22,516 118,300 88,896
Change in income taxes recoverable through future rates 4,918 (1,006) (8,580)
Deferred taxes credited (charged) to shareholders' equity (1,425) (13,800) (1,038)
-------------------------------------------------
Deferred taxes charged to expense 26,009 103,494 79,278
Investment tax credit adjustments (7,655) (8,088) (8,192)
-------------------------------------------------
Income taxes per Consolidated Statements of Income $166,333 $169,527 $153,853
=================================================
Reconciliation of Income Taxes Computed at Statutory
Federal Rate to Total Income Taxes
Income before income taxes $477,157 $507,534 $477,470
Statutory federal income tax rate 35% 35% 35%
-------------------------------------------------
Income taxes computed at statutory federal rate 167,005 177,637 167,115
Increases (decreases) in income taxes due to
Depreciation differences not normalized on regulated activities 12,669 10,953 9,791
Allowance for equity funds used during construction (2,278) (4,957) (7,611)
Amortization of deferred investment tax credits (7,655) (8,088) (8,164)
Tax credits flowed through to income (520) (521) (1,754)
Amortization of deferred tax rate differential on regulated activities (1,958) (2,013) (1,885)
Other (930) (3,484) (3,639)
-------------------------------------------------
Total income taxes $166,333 $169,527 $153,853
=================================================
Effective federal income tax rate 34.9% 33.4% 32.2%
</TABLE>
<TABLE>
<CAPTION>
At December 31, 1996 1995
- -------------------------------------------------------------------------------------------------------------------
(Dollar amounts in thousands)
<S> <C>
Deferred Income Taxes
Deferred tax liabilities
Accelerated depreciation $ 920,631 $ 878,470
Allowance for funds used during construction 209,183 210,928
Income taxes recoverable through future rates 92,584 94,305
Deferred termination and postemployment costs 45,624 49,591
Deferred fuel costs 7,957 39,559
Leveraged leases 27,581 29,842
Percentage repair allowance 38,354 38,295
Energy conservation expenditures 26,622 28,121
Other 175,587 151,231
----------------------------------
Total deferred tax liabilities 1,544,123 1,520,342
----------------------------------
Deferred tax assets
Alternative minimum tax -- 32,626
Accrued pension and postemployment benefit costs 40,570 31,707
Deferred investment tax credits 46,889 49,512
Capitalized interest and overhead 42,509 39,439
Contributions in aid of construction 35,710 34,404
Nuclear decommissioning liability 18,750 16,708
Other 62,464 41,247
----------------------------------
Total deferred tax assets 246,892 245,643
----------------------------------
Deferred tax liability, net $1,297,231 $1,274,699
==================================
</TABLE>
See Notes to Consolidated Financial Statements.
Baltimore Gas and Electric Company and Subsidiaries
22
<PAGE>
Notes to Consolidated Financial Statements
Note 1. Significant Accounting Policies
Nature of the Business
Baltimore Gas and Electric Company (BGE) and Subsidiaries (collectively, the
Company) is primarily an electric and gas utility serving a territory which
encompasses Baltimore City and all or part of ten Central Maryland counties. The
Company is also engaged in diversified businesses as described further in Note
3.
Principles of Consolidation
The consolidated financial statements include the accounts of BGE and all
subsidiaries in which BGE owns directly or indirectly a majority of the voting
stock. Intercompany balances and transactions are eliminated in consolidation.
Under this policy, the accounts of Constellation Holdings, Inc. (CHI) and
Subsidiaries (collectively, the Constellation Companies), BGE Home Products &
Services, Inc. and Subsidiary (collectively, HP&S), BGE Energy Projects &
Services, Inc. and Subsidiaries (collectively, EP&S), and Constellation Energy
Source, Inc. (formerly named BNG, Inc.) are consolidated in the financial
statements, and Safe Harbor Water Power Corporation is reported under the equity
method. Corporate joint ventures, partnerships, and affiliated companies (which
include power generation projects) in which a 20% to 50% voting interest is held
are accounted for under the equity method, unless control is evident, in which
case the entity is consolidated. Investments in which less than a 20% voting
interest is held are accounted for under the cost method, unless significant
influence is exercised over the entity, in which case the investment is
accounted for under the equity method.
Regulation of Utility Operations
BGE's utility operations are subject to regulation by the Mary-land Public
Service Commission (Maryland Commission). The accounting policies and practices
used in the determination of service rates are also generally used for financial
reporting purposes in accordance with generally accepted accounting principles
for regulated industries. See Note 5.
Utility Revenues
BGE recognizes utility revenues as service is rendered to customers.
Fuel and Purchased Energy Costs
The cost of fuel used in generating electricity, net of revenues from
interchange sales, is recovered through a zero-based electric fuel rate subject
to approval by the Maryland Commission. The difference between actual fuel costs
and fuel revenues is deferred on the Consolidated Balance Sheets to be recovered
from or refunded to customers in future periods. The electric fuel rate formula
is based upon the latest twenty-four-month generation mix and the latest
three-month average fuel cost for each generating unit. The fuel rate does not
change unless the calculated rate is more than 5% above or below the rate then
in effect.
During 1989 through 1991 BGE experienced extended outages at its Calvert Cliffs
Nuclear Power Plant. The replacement energy costs associated with these outages
are estimated to be $458 million. The extended outages have been the subject of
ongoing fuel rate proceedings before the Maryland Commission for several years
(see Note 12).
In December 1996, BGE entered into a settlement agreement with the Maryland
People's Counsel and the Maryland Commission Staff proposing that customers will
not fund a total of $118 million of electric replacement energy costs associated
with these extended outages. BGE recorded a reserve for $35 million of these
costs in 1990. In 1996, BGE increased the reserve by $83 million and wrote off
$5.6 million of accrued carrying charges related to the deferred fuel balances.
These increases in the reserve reduced 1996 after-tax earnings by $57.6
million, or 39 cents per share. In addition, the Maryland Commission issued
a rate order in May 1996 disallowing certain fuel costs which were previously
deferred by BGE. Accordingly, BGE wrote-off the deferred fuel costs in 1996.
The write-off of these costs reduced after-tax earnings by $4.5 million,
or 3 cents per share.
Prior to October 1996, the cost of gas sold was recovered through gas adjustment
clauses subject to approval by the Maryland Commission. Under these clauses, the
difference between actual fuel costs and fuel revenues is deferred on the
balance sheet and recovered from or refunded to customers in future periods.
Effective October 1996, the Maryland Commission approved a modification of these
clauses to provide a Market Based Rates (MBR) incentive mechanism. Under the MBR
mechanism, differences between a market index and BGE's actual cost of gas are
shared equally between BGE's customers and shareholders.
Risk Management
Beginning in 1996, BGE engages in commodity hedging activities to minimize the
risk of market fluctuations associated with the price of gas under the MBR
mechanism. The objective of hedging is to manage BGE's price risk under the MBR
mechanism. Under internal guidelines, speculative positions are prohibited.
BGE enters into basis swap agreements which help minimize commodity price risk
by fixing the basis or differential that exists between a delivery location
index and the commodity futures prices. Net amounts receivable or payable under
the swaps are deferred and recognized as a component of gas costs when realized.
At December 31, 1996, there were unsettled swap agreements representing a
notional quantity of 12.3 million decatherms of natural gas purchases through
March 1997.
Income Taxes
The deferred tax liability represents the tax effect of temporary differences
between the financial-statement and tax bases of assets and liabilities. It is
measured using presently enacted tax rates. The portion of BGE's deferred tax
liability applicable to utility operations which has not been reflected in
current service rates represents income taxes recoverable through future rates.
That portion has been recorded as a regulatory asset on the Consolidated Balance
Sheets. Deferred income tax expense represents the net change in the deferred
tax liability and regulatory asset during the year, exclusive of amounts charged
or credited to common shareholders' equity.
Current tax expense consists solely of regular tax less applicable tax credits.
In certain prior years, tax expense included an alternative minimum tax (AMT)
that can be carried forward indefinitely as tax credits to future years in which
the regular tax liability exceeds the AMT liability. Current income tax for the
years ended December 31, 1996 and 1995 reflect full utilization of AMT credits
carried forward of $30 million and $40 million, respectively. The deferred
income taxes provided in earlier years on the AMT liability were reversed as the
credits were utilized.
The investment tax credit (ITC) associated with BGE's regulated utility
operations has been deferred on the Consolidated Balance Sheets (see Note 5) and
is amortized to income ratably over the lives of the subject property. ITC and
other tax credits associated with nonregulated diversified businesses other than
leveraged leases are flowed through to income.
BGE's utility revenue from system sales is subject to the Maryland public
service company franchise tax in lieu of a state income tax. The franchise tax
is included in taxes other than income taxes in the Consolidated Statements of
Income.
Baltimore Gas and Electric Company and Subsidiaries
23
<PAGE>
Inventory Valuation
Fuel stocks and materials and supplies are generally stated at average cost.
Impairment of Long-Lived Assets
Long-lived assets subject to the requirements of Statement of Financial
Accounting Standards No. 121, Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to Be Disposed Of, are evaluated for impairment
through a review of undiscounted expected future cash flows. If the sum of the
undiscounted expected future cash flows is less than the carrying amount of the
asset, an impairment loss is recognized.
Real Estate Projects
Real estate projects consist of the Constellation Companies' investments in
rental and operating properties and properties under development. Rental and
operating properties are held for investment. Properties under development are
held for future development and subsequent sale. Costs incurred in the
acquisition and active development of such properties are capitalized. Rental
and operating properties and properties under development are stated at cost
unless the amount invested exceeds the amounts expected to be recovered through
operations and sales. In these cases, the projects are written down to the
amount estimated to be recoverable.
Investments and Other Assets
Investments in debt and equity securities subject to the requirements of
Statement of Financial Accounting Standards No. 115, Accounting for Certain
Investments in Debt and Equity Securities, are reported at fair value. Certain
of Constellation Companies' marketable equity securities and financial
partnerships are classified as trading securities. Unrealized gains and losses
on these securities are included in diversified businesses revenues. The
investments comprising the nuclear decommissioning trust fund and certain
marketable equity securities of CHI are classified as available-for-sale.
Unrealized gains and losses on these securities, as well as CHI's portion of
unrealized gains and losses on securities of equity-method investees, are
recorded in shareholders' equity. The Company utilizes specific identification
to determine the cost of these securities in computing realized gains or losses.
Utility Plant, Depreciation and Amortization, and Decommissioning
Utility plant is stated at original cost, which includes material, labor, and,
where applicable, construction overhead costs and an allowance for funds used
during construction. Additions to utility plant and replacements of units of
property are capitalized to utility plant accounts. Utility plant retired or
otherwise disposed of is charged to accumulated depreciation. Maintenance and
repairs of property and replacements of items of property determined to be less
than a unit of property are charged to maintenance expense.
Depreciation is generally computed using composite straight-line rates applied
to the average investment in classes of depreciable property. Vehicles are
depreciated based on their estimated useful lives. As a result of the Maryland
Commission's November 1995 gas rate Order, BGE revised its gas utility plant
depreciation rates to reflect the results of a detailed depreciation
study. The revised rates resulted in an increase in depreciation accruals of
approximately $2.4 million annually.
Depreciation expense for 1995 and 1994 includes the write-off of certain costs
at BGE's Perryman site. Initially, BGE had planned to build two combined cycle
generating units at its Perryman site with each unit consisting of two
combustion turbines. However, due to significant changes in the environment in
which utilities operate, BGE decided in 1994 not to construct the second
combined cycle generating unit and wrote off the construction work in progress
costs associated with that unit. This write-off reduced after-tax earnings
during 1994 by $11.0 million or 7 cents per share. As a result of the Maryland
Commission's August 1995 Order requiring all new generation capacity needs to
be competitively bid and BGE's September 1995 announcement that it will merge
with Potomac Electric Power Company, BGE determined that it will not build
the second combustion turbine for the first combined cycle unit. Therefore,
during the third quarter of 1995, BGE wrote off the remaining construction work
in progress costs associated with the first combined cycle unit. This write-off
reduced after-tax earnings during 1995 by $9.7 million, or 7 cents 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.
BGE owns an undivided interest in the Keystone and Conemaugh electric generating
plants located in western Pennsylvania, as well as in the transmission line
which transports the plants' output to the joint owners' service territories.
BGE's ownership interest in these plants is 20.99% and 10.56%, respectively, and
represents a net investment of $153 million and $150 million as of December 31,
1996 and 1995, respectively. Financing and accounting for these properties are
the same as for wholly owned utility plant.
Nuclear fuel expenditures are amortized as a component of actual fuel costs
based on the energy produced over the life of the fuel. Fees for the future
disposal of spent nuclear fuel are paid quarterly to the Department of Energy
and are accrued based on the kilowatt-hours of electricity sold. Nuclear fuel
expenses are subject to recovery through the electric fuel rate.
Nuclear decommissioning costs are accrued by and recovered through a sinking
fund methodology. In a 1995 order, the Maryland Commission authorized BGE to
record decommissioning expense based on a facility-specific cost estimate in
order to 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, to decommission the radioactive portion of the plant. The total
decommissioning reserve of $163.8 million and $136.7 million at December 31,
1996 and 1995, respectively, is included in accumulated depreciation in the
Consolidated Balance Sheets.
In accordance with Nuclear Regulatory Commission (NRC) regulations, BGE has
established an external decommissioning trust to which a portion of accrued
decommissioning costs have been contributed. The NRC requires utilities to
provide financial assurance that they will accumulate sufficient funds to pay
for the cost of nuclear decommissioning based upon either a generic NRC formula
or a facility-specific decommissioning cost estimate. BGE is using the
facility-specific cost estimate for funding these costs and providing the
requisite financial assurance.
Allowance for Funds Used During Construction and Capitalized Interest
The allowance for funds used during construction (AFC) is an accounting
procedure which capitalizes the cost of funds used to finance utility
construction projects as part of utility plant on the Consolidated Balance
Sheets, crediting the cost as a noncash item on the Consolidated Statements of
Income. The cost of borrowed and equity funds is segregated between interest
expense and other income, respectively. BGE recovers the capitalized AFC and a
return thereon after the related utility plant is placed in service and included
in depreciable assets and rate base.
Prior to November 20, 1995, the Company accrued AFC at a pre-tax rate of 9.40%.
Effective November 20, 1995, a rate order of the Maryland Commission reduced the
pre-tax gas-plant and common-plant AFC rates to 9.04% and 9.36%, respectively.
AFC is compounded annually.
The Constellation Companies capitalize interest on qualifying real estate and
power generation development projects.
Baltimore Gas and Electric Company and Subsidiaries
24
<PAGE>
Long-Term Debt
The discount or premium and expense of issuance associated with long-term debt
are deferred and amortized over the original lives of the respective debt
issues. Gains and losses on the reacquisition of debt are amortized over the
remaining original lives of the issuances.
Cash Flows
For the purpose of reporting cash flows, highly liquid investments purchased
with a maturity of three months or less are considered to be cash equivalents.
Use of Accounting Estimates
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period. These
estimates involve judgments with respect to, among other things, various future
economic factors which are difficult to predict and are beyond the control of
the Company. Therefore, actual amounts could differ from these estimates.
Accounting Standards Issued
The Financial Accounting Standards Board has issued Statement of Financial
Accounting Standards No. 125, regarding accounting for transfers and servicing
of financial assets and extinguishments of liabilities, effective January 1,
1997. The American Institute of Certified Public Accountants has issued
Statement of Position No. 96-1, regarding accounting for environmental
remediation liabilities, effective January 1, 1997. Adoption of these statements
is not expected to have a material impact on the Company's financial statements.
- --------------------------------------------------------------------------------
Note 2. Segment Information
<TABLE>
<CAPTION>
Construction Identifiable
Nonaffiliated Affiliated Total Income from Depreciation/ Expenditures Assets at
Revenues Revenues Revenues Operations Amortization (Including AFC) December 31
- ---------------------------------------------------------------------------------------------------------------------------------
(In thousands)
<S> <C>
1996
Electric $2,208,744 $ 283 $2,209,027 $497,986 $279,345 $262,542 $6,226,291
Gas 517,292 -- 517,292 68,848 37,790 97,943 810,084
Diversified businesses 427,211 6,782 433,993 102,631 13,056 -- 1,400,553
Other identifiable assets -- -- -- -- -- -- 114,042
Intercompany eliminations -- (7,065) (7,065) -- -- -- --
------------------------------------ -------- -------- -------- ----------
Total $3,153,247 $ -- $3,153,247 $669,465 $330,191 $360,485 $8,550,970
==================================== ======== ======== ======== ==========
1995
Electric $2,229,774 $ 1,337 $2,231,111 $574,299 $276,285 $288,509 $6,195,722
Gas 400,504 -- 400,504 48,104 29,637 77,528 748,462
Diversified businesses 304,521 6,609 311,130 73,289 11,495 -- 1,266,049
Other identifiable assets -- -- -- -- -- -- 106,430
Intercompany eliminations -- (7,946) (7,946) -- -- -- --
------------------------------------ -------- -------- -------- ----------
Total $2,934,799 $ -- $2,934,799 $695,692 $317,417 $366,037 $8,316,663
==================================== ======== ======== ======== ==========
1994
Electric $2,126,581 $ 840 $2,127,421 $539,739 $252,273 $412,885 $5,981,634
Gas 421,249 -- 421,249 27,801 32,478 76,091 726,759
Diversified businesses 235,155 8,245 243,400 67,719 11,199 -- 1,200,551
Other identifiable assets -- -- -- -- -- -- 128,558
Intercompany eliminations -- (9,085) (9,085) -- -- -- --
------------------------------------ -------- -------- -------- ----------
Total $2,782,985 $ -- $2,782,985 $635,259 $295,950 $488,976 $8,037,502
==================================== ======== ======== ======== ==========
</TABLE>
- --------------------------------------------------------------------------------
Note 3. Subsidiary Information
Diversified businesses consist of the operations of the Constellation Companies,
HP&S, EP&S, and Constellation Energy Source, Inc. (formerly named BNG, Inc.).
The Constellation Companies include Constellation Holdings, Inc., a wholly owned
subsidiary which holds all of the stock of three other subsidiaries,
Constellation Power, Inc. (formerly named Constellation Energy, Inc.),
Constellation Investments, Inc., and Constellation Real Estate Group, Inc. These
companies are engaged in development, ownership, and operation of power
generation projects; financial investments; and development, ownership, and
management of real estate and senior-living facilities, respectively.
HP&S is a wholly owned subsidiary which engages predominantly in the sales and
service of electric and gas appliances, home improvements, and sales and service
of heating and air conditioning systems, primarily in Central Maryland.
EP&S is a wholly owned subsidiary which provides a broad range of customized
energy services. These energy services include: power quality services, customer
electrical system improvements, lighting and mechanical engineering and
installation services, campus and multi-building energy systems, energy
consulting and financial contracts, district energy systems through Comfort
Link (a partnership with the Poole and Kent Company), and, beginning in late
1996, private electric and gas distribution systems.
Constellation Energy Source, Inc. (formerly named BNG, Inc.) is a wholly owned
subsidiary which engages in natural gas brokering.
BGE's investment in Safe Harbor Water Power Corporation, a producer of
hydroelectric power, represents two-thirds of Safe Harbor's total capital stock,
including one-half of the voting stock, and a two-thirds interest in its
retained earnings.
The following is condensed financial information for the Constellation
Companies. The condensed financial information does not reflect the elimination
of intercompany balances or transactions which are eliminated in the Company's
consolidated financial statements.
Baltimore Gas and Electric Company and Subsidiaries
25
<PAGE>
The 1996 operating results reflect 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. This gain was offset by a $7.0
million after-tax write-off of the investment in two geothermal wholesale power
generating projects, a $3.0 million after-tax write-off of development costs of
a proposed coal-fired power project that will not be built, and a $6.2 million
after-tax write-off of a portion of an investment in a solar power project in
which the Constellation Companies have a minority ownership interest and which
is expected to be restructured with the lender.
<TABLE>
<CAPTION>
1996 1995 1994
- --------------------------------------------------------------------------------------------------------------------------
(In thousands, except per share amounts)
<S> <C>
Income Statements
Revenues
Real estate projects $ 80,793 $ 108,414 $ 106,915
Power generation systems 93,134 57,734 41,301
Financial investments 38,916 25,201 12,126
---------------------------------------------------
Total revenues 212,843 191,349 160,342
Expenses other than interest and income taxes 113,247 114,479 107,267
---------------------------------------------------
Income from operations 99,596 76,870 53,075
Minority interest (355) (2,348) --
Interest expense (44,991) (46,673) (45,782)
Capitalized interest 14,645 13,582 10,776
Income tax benefit (expense) (26,578) (14,355) (4,305)
---------------------------------------------------
Net income $ 42,317 $ 27,076 $ 13,764
===================================================
Contribution to the Company's earnings per share of common stock $ .29 $ .18 $ .09
===================================================
Balance Sheets
Current assets $ 115,689 $ 98,526 $ 92,814
Noncurrent assets 1,189,726 1,102,528 1,055,056
---------------------------------------------------
Total assets $1,305,415 $1,201,054 $1,147,870
---------------------------------------------------
Current liabilities $ 134,025 $ 70,393 $ 70,670
Noncurrent liabilities 775,237 778,505 758,626
Shareholder's equity 396,153 352,156 318,574
---------------------------------------------------
Total liabilities and shareholder's equity $1,305,415 $1,201,054 $1,147,870
===================================================
</TABLE>
- --------------------------------------------------------------------------------
Note 4. Real Estate Projects and Financial Investments
Real Estate Projects
Real estate projects consist of the following investments held by the
Constellation Companies:
At December 31, 1996 1995
- -----------------------------------------------------------
(In thousands)
Properties under development $286,200 $270,678
Rental and operating properties
(net of accumulated
depreciation) 237,725 207,666
Other real estate ventures 1,840 1,000
-----------------------
Total real estate projects $525,765 $479,344
=======================
Financial Investments
Financial investments consist of the following investments held by the
Constellation Companies:
At December 31, 1996 1995
- ---------------------------------------------------------
(In thousands)
Insurance companies $ 76,822 $ 77,792
Marketable equity securities 46,231 41,475
Financial limited partnerships 48,115 51,023
Leveraged leases 33,275 35,551
-----------------------
Total financial investments $204,443 $205,841
=======================
Available-For-Sale Investments
The Constellation Companies' marketable equity securities shown above and BGE's
investments comprising the nuclear decommissioning trust fund are classified as
available-for-sale. The fair values, gross unrealized gains and losses, and
amortized cost bases for available-for-sale securities, exclusive of $1.9
million of unrealized net gains on securities of equity-method investees, are as
follows:
Amortized Unrealized Unrealized Fair
At December 31, 1996 Cost Basis Gains Losses Value
- -------------------------------------------------------------------
(In thousands)
Marketable equity $ 39,363 $6,918 $ (50) $ 46,231
securities
U.S. government
agency 18,167 263 -- 18,430
State municipal
bonds 73,571 2,202 (125) 75,648
-----------------------------------------
Total $131,101 $9,383 $(175) $140,309
=========================================
Amortized Unrealized Unrealized Fair
At December 31, 1995 Cost Basis Gains Losses Value
- -------------------------------------------------------------------
(In thousands)
Marketable equity
securities $ 38,520 $2,998 $ (43) $ 41,475
U.S. government
agency 14,177 141 -- 14,318
State municipal
bonds 50,411 2,056 (74) 52,393
------------------------------------------
Total $103,108 $5,195 $(117) $108,186
==========================================
Baltimore Gas and Electric Company and Subsidiaries
26
<PAGE>
Gross and net realized gains and losses on the Constellation Companies'
available-for-sale securities were as follows:
1996 1995 1994
- -------------------------------------------------------------
(In thousands)
Gross realized gains $4,280 $5,470 $ 1,108
Gross realized losses (210) (2,446) (3,150)
-------------------------------
Net realized gains (losses) $4,070 $3,024 $(2,042)
===============================
Contractual Maturities
The contractual maturities of debt securities are as follows:
Amount
- ----------------------------------------------------------
(In thousands)
Less than 1 year $ 1,000
1-5 years 10,065
5-10 years 71,405
More than 10 years 6,000
-------
Total contractual maturities of debt securities $88,470
=======
- --------------------------------------------------------------------------------
Note 5. Regulatory Assets (net)
As discussed in Note 1, BGE's utility operations are subject to regulation by
the Maryland Commission. Except for differences in the timing of the recognition
of certain utility expenses and credits, the ratemaking process utilized by the
Maryland Commission generally is based upon the same accounting principles
applied by nonregulated entities. Under the Maryland Commission's ratemaking
process, these utility expenses and credits are deferred on the Consolidated
Balance Sheets as regulatory assets and liabilities and are recognized in income
as the related amounts are included in service rates and recovered from or
refunded to customers in utility revenues. The following table sets forth
BGE's regulatory assets and liabilities:
At December 31, 1996 1995
- ------------------------------------------------------------------
(In thousands)
Income taxes recoverable through
future rates $264,525 $269,442
Deferred postemployment benefit costs 89,217 81,616
Deferred nuclear expenditures 82,101 86,519
Deferred environmental costs 47,657 38,371
Deferred energy conservation
expenditures 46,696 73,297
Deferred cost of decommissioning
federal uranium enrichment facilities 46,015 51,104
Deferred termination benefit costs 41,137 60,073
Deferred fuel costs 22,734 113,026
Deferred investment tax credits (133,970) (141,463)
Other 6,167 5,930
--------------------
Total regulatory assets (net) $512,279 $637,915
====================
Income taxes recoverable through future rates represent principally the tax
effect of depreciation differences not normalized and the allowance for equity
funds used during construction, offset by unamortized deferred tax rate
differentials and deferred taxes on deferred ITC. These amounts are amortized as
the related temporary differences reverse. See Note 1 for a further discussion
of income taxes.
Deferred postemployment benefit costs represent the excess of such costs
recognized in accordance with Statements of Financial Accounting Standards No.
106 and No. 112 over the amounts reflected in utility rates. These costs will be
amortized over a 15-year period beginning in 1998 (see Note 6).
Deferred nuclear expenditures represent the net unamortized balance of certain
operations and maintenance costs which are being amortized over the remaining
life of the Calvert Cliffs Nuclear Power Plant in accordance with orders of the
Maryland Commission. These expenditures consist of costs incurred from 1979
through 1982 for inspecting and repairing seismic pipe supports, expenditures
incurred from 1989 through 1994 associated with nonrecurring phases of certain
nuclear operations projects, and expenditures incurred during 1990 for
investigating leaks in the pressurizer heater sleeves.
Deferred environmental costs represent the estimated costs of investigating
contamination and performing certain remediation activities at contaminated
Company-owned sites (see Note 12). In November 1995, the Maryland Commission
issued a rate order in the Company's gas base rate proceeding which authorized
the Company to amortize over a 10-year period $21.6 million of these costs, the
amount which had been incurred through October 1995.
Deferred energy conservation expenditures represent the net unamortized balance
of certain operations costs which are being amortized over five years in
accordance with orders of the Maryland Commission. These expenditures consist of
labor, materials, and indirect costs associated with the conservation programs
approved by the Maryland Commission.
Deferred cost of decommissioning federal uranium enrichment facilities
represents the unamortized portion of BGE's required contributions to a fund for
decommissioning and decontaminating the Department of Energy's (DOE) uranium
enrichment facilities. The Energy Policy Act of 1992 requires domestic utilities
to make such contributions, which are generally payable over a 15-year period
with escalation for inflation and are based upon the amount of uranium enriched
by DOE for each utility. These costs are being amortized over the contribution
period as a cost of fuel.
Deferred termination benefit costs represent the net unamortized balance of the
cost of certain termination benefits (see Note 7) applicable to BGE's regulated
operations. These costs are being amortized over a five-year period in
accordance with rate actions of the Maryland Commission.
Deferred fuel costs represent the difference between actual fuel costs and the
fuel rate revenues under BGE's fuel clauses (see Note 1). Deferred fuel costs
are reduced as they are collected from customers.
The underrecovered costs deferred under the fuel clauses were as follows:
At December 31, 1996 1995
- --------------------------------------------------------------------
(In thousands)
Electric deferred fuel costs
Costs deferred $113,172 $130,399
Reserve for disallowed replacement
energy costs (see Note 12) (118,000) (35,000)
--------------------
Net electric deferred fuel costs (4,828) 95,399
Gas deferred fuel costs 27,562 17,627
--------------------
Total deferred fuel costs $ 22,734 $113,026
====================
Deferred investment tax credits (ITC) represents ITC associated with BGE's
regulated utility operations as discussed in Note 1. Deferred ITC are not
deducted from rate base in accordance with federal income tax normalization
requirements.
The foregoing regulatory assets and liabilities are recorded on BGE's
Consolidated Balance Sheets in accordance with Statement of Financial Accounting
Standards (SFAS) No. 71. If BGE were required to terminate application of SFAS
No. 71 for all of its regulated operations, all such amounts deferred would be
recognized in the Consolidated Statements of Income at that time, resulting in a
charge to earnings, net of applicable income taxes.
Baltimore Gas and Electric Company and Subsidiaries
27
<PAGE>
Note 6. Pension and Postemployment Benefits
Pension Benefits
The Company sponsors several noncontributory defined benefit pension plans, the
largest of which (the Pension Plan) covers substantially all BGE employees and
certain employees of BGE's subsidiaries. The other plans, which are not material
in amount, provide supplemental benefits to certain non-employee directors and
key employees. Benefits under the plans are generally based on age, years of
service, and compensation levels.
Prior service cost associated with retroactive plan amendments is amortized on a
straight-line basis over the average remaining service period of active
employees. The Company's funding policy is to contribute at least the
minimum amount required under Internal Revenue Service regulations using the
projected unit credit cost method. Plan assets at December 31, 1996 consisted
primarily of marketable equity and fixed income securities, and group annuity
contracts.
The following tables set forth the combined funded status of the plans and the
composition of total net pension cost. Net pension cost shown below does not
include the cost of termination benefits described in Note 7.
<TABLE>
<CAPTION>
At December 31, 1996 1995
- ------------------------------------------------------------------------------------------------------------------------
(In thousands)
<S> <C>
Vested benefit obligation $695,634 $688,084
Nonvested benefit obligation 17,974 15,668
----------------------------------
Accumulated benefit obligation 713,608 703,752
Projected benefits related to increase in future compensation levels 132,673 122,539
----------------------------------
Projected benefit obligation 846,281 826,291
Plan assets at fair value (792,541) (744,645)
----------------------------------
Projected benefit obligation less plan assets 53,740 81,646
Unrecognized prior service cost (21,890) (24,357)
Unrecognized net loss (117,157) (118,361)
Unamortized net asset from adoption of FASB Statement No. 87 797 995
----------------------------------
Accrued pension (asset) liability $ (84,510) $ (60,077)
==================================
</TABLE>
<TABLE>
<CAPTION>
Year Ended December 31, 1996 1995 1994
- ---------------------------------------------------------------------------------------------------------------------------
(In thousands)
<S> <C>
Components of net pension cost
Service cost-benefits earned during the period $16,089 $11,407 $15,015
Interest cost on projected benefit obligation 59,948 58,433 58,723
Actual return on plan assets (57,671) (150,510) 7,932
Net amortization and deferral 2,115 94,674 (60,071)
------------------------------------------------
Total net pension cost 20,481 14,004 21,599
Amount capitalized as construction cost (2,442) (1,422) (2,578)
------------------------------------------------
Amount charged to expense $18,039 $12,582 $19,021
================================================
</TABLE>
The Company also sponsors a defined contribution savings plan covering all
eligible BGE employees and certain employees of BGE's subsidiaries. Under this
plan, the Company makes contributions on behalf of participants. Company
contributions to this plan totaled $9.4 million, $8.5 million, and $8.7 million
in 1996, 1995, and 1994, respectively.
Postretirement Benefits
The Company sponsors defined benefit postretirement health care and life
insurance plans which cover substantially all BGE employees and certain
employees of its subsidiaries. Benefits under the plans are generally based on
age, years of service, and pension benefit levels. The postretirement benefit
(PRB) plans are unfunded. Substantially all of the health care plans are
contributory, and participant contributions for employees who retire after June
30, 1992 are based on age and years of service. Retiree contributions increase
commensurate with the expected increase in medical costs. The postretirement
life insurance plan is noncontributory. The transition obligation resulting from
the adoption of Statement of Financial Accounting Standards No. 106 effective
January 1, 1993 is being amortized over a 20-year period.
In April 1993, the Maryland Commission issued a rate order authorizing BGE to
recognize in operating expense one-half of the annual increase in PRB costs
applicable to regulated operations as a result of the adoption of Statement No.
106 and to defer the remainder of the annual increase in these costs for
inclusion in BGE's next base rate proceeding. In accordance with the April 1993
Order, all amounts to be deferred prior to completion of BGE's next base rate
proceeding will be amortized over a 15-year period beginning in 1998.
In November 1995, the Maryland Commission issued a rate order in BGE's gas base
rate proceeding providing for full recognition in operating expense of PRB and
other postemployment benefits (discussed below) costs attributable to gas
operations, and affirming its previous decision on amortization of deferred PRB
costs. This phase-in approach meets the guidelines established by the Emerging
Issues Task Force of the Financial Accounting Standards Board for deferring PRB
costs as a regulatory asset. Accrual-basis PRB costs applicable to nonregulated
operations are charged to expense.
Baltimore Gas and Electric Company and Subsidiaries
28
<PAGE>
The following table sets forth the components of the accumulated PRB obligation
and a reconciliation of these amounts to the accrued PRB liability.
<TABLE>
<CAPTION>
At December 31, 1996 1995
- ---------------------------------------------------------------------------------------------------------------------------
Life Life
Health Care Insurance Health Care Insurance
(In thousands)
<S> <C>
Accumulated postretirement benefit obligation:
Retirees $163,904 $45,485 $157,804 $44,769
Active employees 82,373 19,269 84,724 18,599
-------------------------------------------------------------
Total accumulated postretirement benefit obligation 246,277 64,754 242,528 63,368
Unrecognized transition obligation (141,089) (40,960) (149,907) (43,521)
Unrecognized net loss (7,368) (5,690) (12,767) (5,764)
-------------------------------------------------------------
Accrued postretirement benefit liability $ 97,820 $18,104 $ 79,854 $14,083
=============================================================
</TABLE>
The following table sets forth the composition of net PRB cost. Such cost does
not include the cost of termination benefits described in Note 7.
Year ended December 31, 1996 1995
- --------------------------------------------------------------------------------
(In thousands)
Net postretirement benefit cost:
Service cost--benefits earned during
the period $ 5,559 $ 3,918
Interest cost on accumulated post
retirement benefit obligation 21,918 21,203
Amortization of transition obligation 11,378 11,378
Net amortization and deferral 174 (86)
-------------------
Total net postretirement benefit cost 39,029 36,413
Amount capitalized as construction cost (6,224) (5,299)
Amount deferred (7,455) (8,025)
-------------------
Amount charged to expense $25,350 $23,089
===================
Other Postemployment Benefits
The Company provides health and life insurance benefits to employees of BGE and
certain employees of its subsidiaries who are determined to be disabled under
BGE's Disability Insurance Plan. The Company also provides pay continuation
payments for employees determined to be disabled before November 1995. Such
payments for employees determined to be disabled after that date are paid by an
insurance company, and the cost of such insurance is paid by employees. The
liability for these benefits totaled $51 million and $52 million as of December
31, 1996 and 1995, respectively. The portion of the liability attributable to
regulated activities as of December 31, 1993 was deferred.
Consistent with the Maryland Commission's November 1995 order, the amounts
deferred will be amortized over a 15-year period beginning in 1998.
Assumptions
The pension, postretirement, and other postemployment benefit liabilities were
determined using the following assumptions.
At December 31, 1996 1995
- --------------------------------------------------------------------------------
Assumptions:
Discount rate
Pension and postretirement benefits 7.5% 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
The health care inflation rates for 1996 are assumed to be 9.5% for
Medicare-eligible retirees and 8.9% for retirees not covered by Medicare. The
health care inflation rates for 1997 are assumed to be 7.5% for
Medicare-eligible retirees and 10.0% for retirees not covered by Medicare. After
1997, both rates are assumed to decrease by 0.5% annually to an ultimate rate of
5.5% in the years 2001 and 2006, respectively. A one percentage point increase
in the health care inflation rate from the assumed rates would increase the
accumulated postretirement benefit obligation by approximately $41 million as of
December 31, 1996 and would increase the aggregate of the service cost and
interest cost components of postretirement benefit cost by approximately $4
million annually.
- --------------------------------------------------------------------------------
Note 7. Termination Benefits
BGE offered a Voluntary Special Early Retirement Program (the 1992 VSERP) to
eligible employees who retired during the period February 1, 1992 through April
1, 1992. In April 1993, the Maryland Commission authorized BGE to amortize
the $6.6 million cost of termination benefits associated with the 1992 VSERP,
which consisted principally of an enhanced pension benefit, over a five-year
period for ratemaking purposes.
BGE offered a second Voluntary Special Early Retirement Program (the 1993 VSERP)
to eligible employees who retired as of February 1, 1994. The one-time cost of
the 1993 VSERP consisted of enhanced pension and postretirement benefits. In
addition to the 1993 VSERP, further employee reductions have been accomplished
through the elimination of certain positions, and various programs have been
offered to employees impacted by the eliminations. The $88.3 million portion of
1993 VSERP attributable to regulated activities was deferred and is being
amortized over a five-year period for ratemaking purposes, beginning in February
1994, consistent with previous rate actions of the Maryland Commission.
Baltimore Gas and Electric Company and Subsidiaries
29
<PAGE>
Note 8. Short-Term Borrowings
Short-term borrowings include bank loans, commercial paper notes, and bank lines
of credit. The Company pays commitment fees in support of lines of credit.
Borrowings under the lines are at the banks' prime rates, base interest rates,
or at various money market rates.
Short-term borrowings were as follows:
At December 31, 1996 1995
- -------------------------------------------------------------------
(In thousands)
BGE's bank loans $ 8,785 $ 3,845
BGE's commercial paper notes 324,400 275,300
Constellation Companies' lines of credit -- 160
--------------------
Total short-term borrowings $333,185 $279,305
====================
The weighted average interest rates for short-term borrowings were as follows:
Year ended December 31, 1996 1995
- -------------------------------------------------------------------
BGE
Bank loans 4.93% 4.74%
Commercial Paper Notes 5.53 5.92
Constellation Companies
Lines of Credit -- --
Unused lines of credit supporting commercial paper notes at December 31, 1996
and 1995 were $203 million and $238 million, respectively. These amounts are
exclusive of $150 million of revolving credit agreements undrawn at year-end
(see Note 9).
- --------------------------------------------------------------------------------
Note 9. Long-Term Debt
First Refunding Mortgage Bonds of BGE
Substantially all of the principal properties and franchises owned by BGE, as
well as the capital stock of Constellation Holdings, Inc., Safe Harbor Water
Power Corporation, HP&S, EP&S, and Constellation Energy Source, Inc. (formerly
named BNG, Inc.), are subject to the lien of the mortgage under which BGE's
outstanding First Refunding Mortgage Bonds have been issued.
On August 1 of each year, BGE is required to pay to the mortgage trustee an
annual sinking fund payment equal to 1% of the largest principal amount of
Mortgage Bonds outstanding under the mortgage during the preceding twelve
months. Such funds are to be used, as provided in the mortgage, for the purchase
and retirement by the trustee of Mortgage Bonds of any series other than the
5 1/2% Installment Series of 2002, the 8.40% Series of 1999, the 5 1/2% Series
of 2000, the 8 3/8% Series of 2001, the 7 1/4% Series of 2002, the 6 1/2%
Series of 2003, the 6 1/8% Series of 2003, the 5 1/2% Series of 2004, the
7 1/2% Series of 2007, and the 6 5/8% Series of 2008.
The principal amounts of the 5 1/2% Installment Series Mortgage Bonds payable
each year are as follows:
Year
- --------------------------------------------------------------------------------
(In thousands)
1997 $ 605
1998 and 1999 690
2000 and 2001 865
2002 6,725
The Remarketed Floating Rate Series Due September 1, 2006 First Refunding
Mortgage Bonds include a provision that allows the bondholders the option to
tender their bonds back to BGE on an annual basis. BGE is required to repurchase
and retire at par any bonds tendered that are not remarketed or purchased by the
remarketing agent. In addition, BGE has the option to call the bonds annually at
par on each remarketing date.
Other Long-Term Debt of BGE
BGE maintains revolving credit agreements that expire at various times from 1997
through 1999. Under the terms of the agreements, BGE may, at its option, obtain
loans at various interest rates. A commitment fee is paid on the daily average
of the unborrowed portion of the commitment. At December 31, 1996, BGE had no
borrowings under these revolving credit agreements and had available $150
million of unused capacity under these agreements.
Under the terms of the bank loan which matures on March 29, 2001, the bank has a
one-time option to cancel the loan on December 29, 1997. Until that date, the
interest rate on the loan is 5.22%. If the bank does not cancel the loan on
December 29, 1997, the interest rate for the remaining term will reset to 6.11%.
Following is information regarding BGE's Medium-term Notes outstanding at
December 31, 1996:
Weighted-Average
Series Interest Rate Maturity Dates
- --------------------------------------------------------------------------------
B 8.43% 1998-2006
C 7.09% 1997-2003
D 6.60% 1998-2006
Long-Term Debt of Constellation Companies
The Constellation Companies have a $75 million unsecured revolving credit
agreement which matures December 9, 1999 and is used to provide liquidity for
general corporate purposes. A commitment fee is paid on the daily average of the
unborrowed portion of the commitment. At December 31, 1996, the Constellation
Companies had $65 million outstanding under this agreement.
The Constellation Companies' mortgage and construction loans and other
collateralized notes have varying terms. The 8.00% mortgage note requires
monthly principal and interest payments through July 31, 2001. The 8.00%
construction loan requires no monthly principal and interest payments during
construction and is due October 30, 2003. The variable rate mortgage notes
require periodic payment of principal and interest with various maturities from
June 1997 through July 2009. The 7.50% mortgage note requires monthly principal
and interest payments through October 9, 2005. The 7.357% mortgage note requires
quarterly principal and interest payments through March 15, 2009. The 9.65%
mortgage note requires monthly principal and interest payments through February
1, 2028.
The unsecured notes outstanding as of December 31, 1996 mature in accordance
with the following schedule:
Amount
- --------------------------------------------------------------------------------
(In thousands)
8.93%, due August 28, 1997 $ 52,000
6.65%, due September 9, 1997 15,000
8.23%, due October 15, 1997 30,000
7.05%, due April 22, 1998 25,000
7.06%, due September 9, 1998 20,000
8.48%, due October 15, 1998 75,000
7.30%, due April 22, 1999 90,000
8.73%, due October 15, 1999 15,000
7.55%, due April 22, 2000 35,000
7.43%, due September 9, 2000 30,000
8.00%, due December 31, 2000 160
--------
Total unsecured notes $387,160
========
Baltimore Gas and Electric Company and Subsidiaries
30
<PAGE>
Long-Term Debt of Other Diversified Businesses
Long-term debt of other diversified businesses includes a $50 million unsecured
revolving credit agreement of Comfort Link which matures September 26, 2001.
Loans may be obtained at various rates for terms up to nine months. A facility
fee is paid on the total amount of the commitment. At December 31, 1996,
$12 million was outstanding under this agreement.
Weighted Average Interest Rates for Variable Rate Debt
The weighted average interest rates for variable rate debt were as follows:
Year ended December 31, 1996 1995
- --------------------------------------------------------------------------------
BGE
Floating rate series mortgage bonds 5.87% 6.30%
Remarketed floating rate series
mortgage bonds 5.63 --
Pollution control loan 3.49 3.79
Port facilities loan 3.59 4.06
Adjustable rate pollution control loan 3.90 3.75
Economic development loan 3.57 4.01
Constellation Companies
Loans under credit agreements 6.08 6.74
Mortgage and construction loans
and other collateralized notes 8.33 8.99
Other Diversified Businesses
Loans under credit agreements 6.13 --
Aggregate Maturities
The combined aggregate maturities and sinking fund requirements for all of the
Company's long-term borrowings for each of the next five years are as follows:
Diversified
Year BGE Businesses
- --------------------------------------------------------------------------------
(In thousands)
1997 $ 89,848 $107,924
1998 93,578 165,370
1999 247,347 186,339
2000 253,658 97,803
2001 247,183 31,897
As of December 31, 1996, BGE had $195 million of debt with provisions that allow
lenders the option to request BGE to repay the debt at certain times prior to
maturity. In the event such options are exercised, BGE intends to refinance such
debt on a long-term basis through the issuance of medium term notes or using
revolving credit agreements.
- --------------------------------------------------------------------------------
Note 10. Redeemable Preference Stock
The 7.80%, 1989 Series is subject to mandatory redemption in full at par on July
1, 1997. The following series are subject to an annual mandatory redemption of
the number of shares shown below at par beginning in the year shown below. At
BGE's option, an additional number of shares, not to exceed the same number as
are mandatory, may be redeemed at par in any year, commencing in the same year
in which the mandatory redemption begins. The 8.25%, 1989 Series, the 8.625%,
1990 Series, and the 7.85%, 1991 Series listed below are not redeemable except
through operation of a sinking fund.
Beginning
Series Shares Year
- --------------------------------------------------------------------------------
7.50%, 1986 Series 15,000 1992
6.75%, 1987 Series 15,000 1993
8.25%, 1989 Series 100,000 1995
8.625%, 1990 Series 130,000 1996
7.85%, 1991 Series 70,000 1997
The combined aggregate redemption requirements at December 31, 1996 for all
series of redeemable preference stock are as follows:
Year
- --------------------------------------------------------------------------------
(In thousands)
1997 $ 83,000
1998 23,000
1999 23,000
2000 10,000
2001 10,000
Thereafter 68,500
--------
Total aggregate redemption requirements $217,500
========
With regard to payment of dividends or assets available in the event of
liquidation, all issues of preference stock, whether subject to mandatory
redemption or not, rank equally; and all preference stock ranks prior to common
stock.
Baltimore Gas and Electric Company and Subsidiaries
31
<PAGE>
Note 11. Leases
The Company, as lessee, contracts for certain facilities and equipment under
lease agreements with various expiration dates and renewal options. Consistent
with the regulatory treatment, lease payments for utility operations are charged
to expense. Lease expense, which is comprised primarily of operating leases,
totaled $11.6 million, $12.2 million, and $12.7 million for the years ended
1996, 1995, and 1994, respectively.
The future minimum lease payments at December 31, 1996 for long-term
noncancelable operating leases are as follows:
Year
- --------------------------------------------------------------------------------
(In thousands)
1997 $ 4,899
1998 4,095
1999 2,072
2000 1,893
2001 1,450
Thereafter 2,725
-------
Total minimum lease payments $17,134
=======
Certain of the Constellation Companies, as lessor, have entered into operating
leases for office and retail space. These leases expire over periods ranging
from 1 to 19 years, with options to renew. The net book value of property under
operating leases was $177.3 million at December 31, 1996. The future minimum
rentals to be received under operating leases in effect at December 31, 1996 are
as follows:
Year
- --------------------------------------------------------------------------------
(In thousands)
1997 $ 15,433
1998 14,073
1999 13,146
2000 12,671
2001 11,704
Thereafter 61,735
--------
Total minimum rentals $128,762
========
- --------------------------------------------------------------------------------
Note 12. Commitments, Guarantees, and Contingencies
Commitments
BGE has made substantial commitments in connection with its construction program
for 1997 and subsequent years. In addition, BGE has entered into three long-term
contracts for the purchase of electric generating capacity and energy. The
contracts expire in 2001, 2013, and 2023. Total payments under these contracts
were $64.1, $68.4, and $69.4 million during 1996, 1995, and 1994, respectively.
At December 31, 1996, the estimated future payments for capacity and energy that
BGE is obligated to buy under these contracts are as follows:
Year
- --------------------------------------------------------------------------------
(In thousands)
1997 $ 61,669
1998 78,075
1999 91,938
2000 92,039
2001 62,978
Thereafter 805,110
----------
Total estimated future payments for
capacity and energy under long-term contracts $1,191,809
==========
Certain of the Constellation Companies have committed to contribute additional
capital and to make additional loans to certain affiliates, joint ventures, and
partnerships in which they have an interest. As of December 31, 1996, the total
amount of investment requirements committed to by the Constellation Companies is
$56 million.
In December, 1994, BGE and HP&S entered into agreements with a financial
institution whereby BGE and HP&S can sell on an ongoing basis up to an aggregate
of $40 million and $50 million, respectively, of an undivided interest in a
designated pool of customer receivables. Under the terms of the agreements, BGE
and HP&S have limited recourse on the receivables and have recorded a reserve
for credit losses. At December 31, 1996, BGE and HP&S had sold $35 million and
$47 million of receivables, respectively, under these agreements.
Guarantees
BGE has agreed to guarantee two-thirds of certain indebtedness of Safe Harbor
Water Power Corporation. The total amount of indebtedness that can be guaranteed
is $50 million, of which $33 million represents BGE's potential share of the
guarantee. As of December 31, 1996, outstanding indebtedness of Safe Harbor
Water Power Corporation was $32 million, of which $21 million is guaranteed by
BGE. BGE has also agreed to guarantee up to $20 million of obligations and
indebtedness of Constellation Energy Source, Inc. (formerly named BNG, Inc.) As
of December 31, 1996, there were no outstanding obligations under this
guarantee. BGE assesses that the risk of material loss on the loans guaranteed
is minimal.
As of December 31, 1996, the total outstanding loans and letters of credit of
certain power generation and real estate projects guaranteed by the
Constellation Companies were $54 million. Also, the Constellation Companies have
agreed to guarantee certain other borrowings of various power generation and
real estate projects. The Company has assessed that the risk of material loss on
the loans guaranteed and performance guarantees is minimal.
Pending Merger With Potomac Electric Power Company
BGE, Potomac Electric Power Company (PEPCO), and Constellation Energy
Corporation (formerly named "RH Acquisition Corp.") (CEC), have entered into an
Agreement and Plan of Merger, dated as of September 22, 1995 (the Merger
Agreement). CEC was formed to accomplish the merger and its outstanding capital
stock is owned 50% by BGE and 50% by PEPCO. The Merger Agreement provides for
a strategic business combination that will be accomplished by merging both BGE
and PEPCO into CEC (the Merger). The Merger, which was unanimously approved
by the Boards of Directors of BGE and PEPCO and approved by the shareholders
of both companies, is expected to close during 1997 after all other conditions
to the consummation of the Merger, including obtaining applicable regulatory
approvals (described below), are met or waived. In connection with the Merger,
BGE common shareholders will receive one share of CEC common stock for each
BGE share and PEPCO common shareholders will receive 0.997 of a share of CEC
common stock for each PEPCO share.
Baltimore Gas and Electric Company and Subsidiaries
32
<PAGE>
Preliminary estimates by the managements of PEPCO and BGE indicate that the
synergies resulting from the combination of their utility operations could
generate net cost savings of up to $1.3 billion over a period of 10 years
following the Merger. These estimates indicate that about two-thirds of the
savings will come from reduced labor costs, with the remaining savings split
between nonfuel purchasing and corporate and administrative programs. These
savings are net of costs to achieve, presently estimated to be approximately
$150 million, and are expected to be allocated among shareholders and customers.
This allocation will depend upon the results of regulatory proceedings in the
various jurisdictions in which BGE and PEPCO operate their utility businesses
(see discussion of the issues raised in regulatory proceedings regarding the
allocation and other matters). The analyses employed in order to develop
estimates of the potential savings as a result of the Merger were necessarily
based upon various assumptions which involve judgments with respect to, among
other things, future national and regional economic and competitive conditions,
inflation rates, regulatory treatment, weather conditions, financial market
conditions, interest rates, future business decisions and other uncertainties,
all of which are difficult to predict and many of which are beyond the control
of BGE and PEPCO. Accordingly, while BGE believes that such assumptions are
reasonable for purposes of the development of estimates of potential savings,
there can be no assurance that such assumption will approximate actual
experience or that all such savings will be realized.
Major regulatory proceedings, together with an indication of the current status
of the proceeding, which must be concluded in order to proceed with the merger,
are listed below. The Merger Agreement provides that a condition to closing is
that no such approvals shall impose terms and conditions that would have, or
would be reasonably likely to have, a material adverse effect on the business,
operations, properties, assets, condition (financial or otherwise), prospects,
or results of operations of the new company.
(bullet) Federal Energy Regulatory Commission (FERC) - Hearings have been
completed and we are waiting for a decision. The hearings explored the
merged company's generation market power, including the appropriate geographic
markets, and to consider appropriate remedies if the merged company is found
to possess generation market power. Testimony of FERC staff included the
suggestion that a significant portion of generation (approximately 2400-3600
megawatts) be divested or transmission capability be upgraded or both due to
the perceived market power of the merged company in both the wholesale and
retail markets.
(bullet) Maryland Public Service Commission (Maryland Commission) - Hearings
have been completed and we are waiting for a decision. Since the Report on Form
10-Q for the third quarter 1996 was filed, rebuttal and surrebuttal testimony
has been filed. Office of People's Counsel (the advocates for residential
customers) recommended that the Maryland Commission not approve the Merger
until the Applicants demonstrate that Maryland customers will not be harmed by
potential restrictions on competition due to the market power of the new
company. If, however, the Maryland Commission decides to approve the Merger,
People's Counsel continues to recommend rate decreases. Due to the use of a
different test period, the amounts are somewhat different than reported in
the second quarter Report on Form 10-Q. Based on a test period proposed by
People's Counsel in recent testimony, they recommend a pre-merger rate
reduction of approximately $108.3 million ($84.7 million to BGE customers
and $23.6 million to PEPCO customers) with Merger savings being reflected
in further reduced rates of approximately $65 million ($45 million to BGE
customers and $20 million to PEPCO customers) contemporaneously with the date
of the Merger. A number of other recommendations are also included in
People's Counsel testimony. The Maryland Energy Administration (MEA)
continues to recommend that the Maryland Commission adopt an alternative
regulatory plan and also asks that rates be examined. Maryland Commission
Staff testimony also utilizes the new test period. Based on the new test period
Maryland Commission Staff recommends an immediate decrease of $63.6 million
(BGE's rates reduced by $54.3 million and PEPCO's by $9.3 million) at the
time of the Merger. Maryland Commission Staff's surrebuttal testimony also
recommends that CEC be required to make a rate filing 15 months after the
Merger becomes effective.
(bullet) District of Columbia Public Service Commission - Hearings began
February 18, 1997. Testimony was filed by the parties in September 1996. The
D.C. Office of People's Counsel (the advocates for residential customers)
opposes the Merger based on its contention that BGE and PEPCO have not proved
that the Merger is in the public interest. Testimony of the D.C. People's
Counsel also provides that should the Merger be approved, an immediate rate
reduction of $44.2 million be imposed at the time of the Merger, followed by
a 5-year moratorium on rate increases. Further, testimony of D.C. People's
Counsel advocates divestiture of all nonutility affiliate companies, exclusion
of BGE's Calvert Cliffs Nuclear Plant from production plant assigned to D.C.,
and a 5-year $23.37 million per year economic development program. GSA, a major
D.C. customer, requests that any approval should be coupled with an imposition
of retail competition access for ratepayers such as GSA, a 25-year
amortization of costs to achieve the Merger, and elimination of Calvert Cliffs
from the generating mix. In addition to these matters, D.C. People's Counsel, an
intervenor, Washington Gas Light Company, and the D.C. Corporation Counsel have
questioned the interpretation by BGE and PEPCO that a D.C. statute known as
the Antimerger Law is inapplicable to this transaction. Should such statute
be deemed to be applicable, authorization of the Merger by Congress would be
required. Allegations also were made that BGE and PEPCO should have received
Congressional approval for their owning 50% of the shell company, CEC, prior to
consummation of the Merger.
The reasons for the Merger, the terms and conditions contained in the Merger
Agreement, the regulatory approvals required prior to closing the Merger, and
other matters concerning the Merger, PEPCO, and CEC are discussed in more detail
in the Registration Statement on Form S-4 (Registration No. 33-64799).
Environmental Matters
The Clean Air Act of 1990 (the Act) contains two titles designed to reduce
emissions of sulfur dioxide and nitrogen oxide (NOx) from electric generating
stations. Title IV contains provisions for compliance in two separate phases.
Phase I of Title IV became effective January 1, 1995, and Phase II of Title IV
must be implemented by 2000. BGE met the requirements of Phase I by installing
flue gas desulfurization systems and fuel switching and through unit
retirements. BGE is currently examining what actions will be required in order
to comply with Phase II of the Act. However, BGE anticipates that compliance
will be attained by some combination of fuel switching, flue gas
desulfurization, unit retirements, or allowance trading.
At this time, plans for complying with NOx control requirements under Title I of
the Act are less certain because all implementation regulations have not yet
been finalized by the government. It is expected that by the year 1999 these
regulations will require additional NOx controls for ozone attainment at BGE's
generating plants and at other BGE facilities. The controls will result in
additional expenditures that are difficult to predict prior to the issuance of
such regulations. Based on existing and proposed ozone nonattainment
regulations, BGE currently estimates that the NOx controls at BGE's generating
plants will cost approximately $90 million. BGE is currently unable to predict
the cost of compliance with the additional requirements at other BGE facilities.
Baltimore Gas and Electric Company and Subsidiaries
33
<PAGE>
BGE has been notified by the Environmental Protection Agency and several state
agencies that it is being considered a potentially responsible party (PRP) with
respect to the cleanup of certain environmentally contaminated sites owned and
operated by third parties. Cleanup costs for these sites cannot be estimated,
except that BGE's 15.79% share of the possible cleanup costs at one of these
sites, Metal Bank of America, a metal reclaimer in Philadelphia, could exceed
amounts recognized by up to approximately $7 million based on the highest
estimate of costs in the range of reasonably possible alternatives. Although the
cleanup costs for certain of the remaining sites could be significant, BGE
believes that the resolution of these matters will not have a material effect on
its financial position or results of operations.
Also, BGE is coordinating investigation of several former gas manufacturing
plant sites, including exploration of corrective action options to remove coal
tar. In late December 1996, the Maryland Department of the Environment and BGE
signed a consent order that requires BGE to implement remedial action plans
addressing contamination at and related to the Spring Gardens site. The specific
remedial actions for this site will be developed in the future. BGE has
recognized estimated environmental costs at all former gas manufacturing plant
sites (based on remedial action options) which are considered probable totaling
$50 million in nominal dollars. These costs, net of accumulated amortization,
have been deferred as a regulatory asset (see Note 5). Accounting rules also
require BGE to disclose additional costs deemed by BGE to be less likely than
probable costs, but still "reasonably possible" of being incurred at these
sites. Because of the results of recent studies at these sites, it is reasonably
possible that these additional costs could exceed the amount 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
An accident or an extended outage at either unit of the Calvert Cliffs Nuclear
Power Plant could have a substantial adverse effect on BGE. The primary
contingencies resulting from an incident at the Calvert Cliffs plant would
involve the physical damage to the plant, the recoverability of replacement
power costs, and BGE's liability to third parties for property damage and bodily
injury. BGE maintains various insurance policies for these contingencies. The
costs that could result from a major accident or an extended outage at either of
the Calvert Cliffs units could exceed the coverage limits.
In addition, in the event of an incident at any commercial nuclear power plant
in the country, BGE could be assessed for a portion of any third party claims
associated with the incident. Under the provisions of the Price Anderson Act,
the limit for third party claims from a nuclear incident is $8.92 billion. If
third party claims relating to such an incident exceed $200 million (the amount
of primary insurance), BGE's share of the total liability for third party claims
could be up to $159 million per incident, that would be payable at a rate of $20
million per year.
BGE and other operators of commercial nuclear power plants in the United States
are required to purchase insurance to cover claims of certain nuclear workers.
Other non-governmental commercial nuclear facilities may also purchase such
insurance. Coverage of up to $400 million is provided for claims against BGE or
others insured by these policies for radiation injuries. If certain claims were
made under these policies, BGE and all policyholders could be assessed, with
BGE's share being up to $6.02 million in any one year.
For physical damage to Calvert Cliffs, BGE has $2.75 billion of property
insurance from industry mutual insurance companies. If an outage at Calvert
Cliffs is caused by an insured physical damage loss and lasts more than 21
weeks, BGE has up to $473.2 million per unit of insurance, provided by an
industry mutual insurance company, for replacement power costs. This amount can
be reduced by up to $94.6 million per unit if an outage to both units at Calvert
Cliffs is caused by a singular insured physical damage loss. If accidents at any
insured plants cause a shortfall of funds at the industry mutuals, BGE and all
policyholders could be assessed, with BGE's share being up to $35.1 million.
Recoverability of Electric Fuel Costs
By statute, actual electric fuel costs are recoverable so long as the Maryland
Commission finds that BGE demonstrates that, among other things, it has
maintained the productive capacity of its generating plants at a reasonable
level. The Maryland Commission and Maryland's highest appellate court have
interpreted this as permitting a subjective evaluation of each unplanned outage
at BGE's generating plants to determine whether or not BGE had implemented all
reasonable and cost-effective maintenance and operating control procedures
appropriate for preventing the outage. Effective January 1, 1987, the Maryland
Commission authorized the establishment of a Generating Unit Performance Program
(GUPP) to measure, annually, utility compliance with maintaining the productive
capacity of generating plants at reasonable levels by establishing a system-wide
generating performance target and individual performance targets for each base
load generating unit. In fuel rate hearings, actual generating performance after
adjustment for planned outages will be compared to the system-wide target and,
if met, should signify that BGE has complied with the requirements of Maryland
law. Failure to meet the system-wide target will result in review of each unit's
adjusted actual generating performance versus its performance target in
determining compliance with the law and the basis for possibly imposing a
penalty on BGE. Parties to fuel rate hearings may still question the prudence of
BGE's actions or inactions with respect to any given generating plant outage,
which could result in the disallowance of replacement energy costs by the
Maryland Commission.
Since the two units at BGE's Calvert Cliffs Nuclear Power Plant utilize BGE's
lowest cost fuel, replacement energy costs associated with outages at these
units can be significant. BGE cannot estimate the amount of replacement energy
costs that could be challenged or disallowed in future fuel rate proceedings,
but such amounts could be material.
In October 1988, BGE filed its first fuel rate application for a change in its
electric fuel rate under GUPP. The resultant case before the Maryland Commission
covers BGE's operating performance in calendar year 1987, and BGE's filing
demonstrated that it met the system-wide and individual nuclear plant
performance targets for 1987. In November 1989, testimony was filed on behalf of
the Maryland People's Counsel (People's Counsel) alleging that seven outages at
the Calvert Cliffs plant in 1987 were due to management imprudence and that the
replacement energy costs associated with those outages should be disallowed by
the Commission. Total replacement energy costs associated with the 1987 outages
were approximately $33 million. On January 23, 1995, the Hearing Examiner issued
his decision in the 1987 fuel rate proceeding and found that the Company had met
the GUPP standard which establishes a presumption that BGE had operated the
plant at a reasonably productive capacity level. However, the Order found that
the presumption of reasonableness would be overcome by a showing of
mismanagement and that such a showing was made with respect to the environmental
qualifications outage time. The Hearing Examiner had mitigated the disallowance
of replacement energy costs due to the fact the GUPP standard was met. The
Hearing Examiner's Order was appealed to the Maryland Commission by both BGE and
People's Counsel. The Maryland Commission upheld the Hearing Examiner's findings
with respect to the environmental
Baltimore Gas and Electric Company and Subsidiaries
34
<PAGE>
qualification related outage time, but disagreed with certain methodologies
applied by the Hearing Examiner. The impact of the Maryland Commission's
decision on the Company's 1996 earnings was approximately $4.5 million,
the amount previously estimated by the Company. People's Counsel has filed a
motion for rehearing.
In May 1989, BGE filed its fuel rate case in which 1988 performance was
examined. BGE met the system-wide and nuclear plant performance targets in 1988.
People's Counsel alleged that BGE imprudently managed several outages at Calvert
Cliffs, and BGE estimates that the total replacement energy costs associated
with these 1988 outages were approximately $2 million. On November 14, 1991, a
Hearing Examiner at the Maryland Commission issued a proposed Order, which
became final on December 17, 1991 and concluded that no disallowance was
warranted. The Hearing Examiner found that BGE maintained the productive
capacity of the Plant at a reasonable level, noting that it produced a near
record amount of power and exceeded the GUPP standard. Based on this record, the
Order concluded there was sufficient cause to excuse any avoidable failures to
maintain productive capacity at higher levels.
During 1989, 1990, and 1991, BGE experienced extended outages at its Calvert
Cliffs Nuclear Power Plant. In the Spring of 1989, a leak was discovered around
the Unit 2 pressurizer heater sleeves during a refueling outage. BGE shut down
Unit 1 as a precautionary measure on May 6, 1989, to inspect for similar leaks
and none were found. However, Unit 1 was out of service for the remainder of
1989 and 285 days of 1990 to undergo maintenance and modification work to
enhance the reliability of various safety systems, to repair equipment, and to
perform required periodic surveillance tests. Unit 2, which returned to service
May 4, 1991, remained out of service for the remainder of 1989, 1990, and the
first part of 1991 to repair the pressurizer, perform maintenance and
modification work, and complete the refueling. The replacement energy costs
associated with these extended outages for both units at Calvert Cliffs,
concluding with the return to service of Unit 2, are estimated to be $458
million.
In a December 1990 Order issued by the Maryland Commission in a BGE base rate
proceeding, the Maryland Commission found that certain operations and
maintenance expenses incurred at Calvert Cliffs during the test year should not
be recovered from ratepayers. The Maryland Commission found that this work,
which was performed during the 1989-1990 Unit 1 outage and fell within the test
year, was avoidable and caused by BGE actions which were deficient. The Maryland
Commission noted in the Order that its review and findings on these issues
pertain to the reasonableness of BGE's test year operations and maintenance
expenses for purposes of setting base rates and not to the responsibility for
replacement energy costs associated with the outages at Calvert Cliffs. The
Maryland Commission stated that its decision in the base rate case will have no
res judicata (binding) effect in the fuel rate proceeding examining the
1989-1991 outages. The work characterized as avoidable significantly increased
the duration of the Unit 1 outage. Despite the Maryland Commission's statement
regarding no binding effect, BGE recognizes that the views expressed by the
Maryland Commission made the full recovery of all of the replacement energy
costs associated with the Unit 1 outage doubtful. Therefore, in December 1990,
BGE recorded a provision of $35 million against the possible disallowance of
such costs.
In December 1996, BGE entered into a settlement agreement with People's Counsel
and the Maryland Commission Staff proposing a resolution to these fuel rate
proceedings. BGE agreed that ratepayers will not fund a total of $118 million of
electric replacement energy costs associated with the extended outages. This
represents $83 million in addition to the $35 million reserve for possible
disallowance of replacement energy costs recorded in 1990. Therefore, in
December 1996, BGE increased the provision for the disallowance of such costs by
$83 million. Additionally, in 1996, BGE wrote off $5.6 million of accrued
carrying charges related to the deferred fuel balances. The remainder of the
replacement energy costs associated with the extended outage has already been
recovered from customers through the fuel rate.
California Power Purchase Agreements
The Constellation Companies have ownership interests in 16 projects that sell
electricity in California under "Interim Standard Offer No. 4" power purchase
agreements. Under these agreements, the projects supply electricity to utilities
at a fixed rate for capacity and energy the first 10 years of the agreements,
and a fixed rate for capacity plus a variable rate for energy based on the
utilities' avoided cost for the remaining term of the agreements. Avoided
cost generally is the cost of a utility's lowest-cost next-available source
of generation to service the demands on its system.
From 1996 through 2000, the 10-year periods for fixed energy rates expire for
these projects and they will begin supplying electricity at variable rates. At
current avoided cost levels, the Constellation Companies would experience
reduced earnings or incur losses associated with these projects when they
begin supplying electricity at variable rates. Eight projects begin supplying
electricity at variable rates in 1997 and 1998. The projects that make the
highest revenues will begin supplying electricity at variable rates in 1999 and
2000. As a result, we do not expect the Constellation Companies to experience
significantly lower earnings or losses on these projects before 2000.
Constellation is pursuing alternatives for these power generation projects
including repowering the projects to reduce operating costs, changing fuels to
reduce operating costs, renegotiating the power purchase agreements to improve
the terms, restructuring financings to improve the financing terms, and selling
its ownership interests in the projects. The Company cannot estimate the
financial impact of the switch from fixed to variable rates on the Constellation
Companies or on BGE, but the impact could be material.
Constellation Real Estate
Management will consider market demand, interest rates, the availability of
financing, and the strength of the economy in general when making decisions
about real estate investments. We believe until the economy shows sustained
growth and there is more demand for new development, real estate values will not
improve much. 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. Competing
demands for our financial resources, changes in the utility industry, and the
proposed merger with Potomac Electric Power Company, are factors we will
consider when we evaluate all diversified business strategies so we use capital
and other resources effectively. Depending on market conditions in the future,
we could also have losses on any future sales.
Applicable accounting rules would require a writedown of a real estate
investment to market value 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.
Baltimore Gas and Electric Company and Subsidiaries
35
<PAGE>
Note 13. Fair Value of Financial Instruments
The following table presents the carrying amounts and fair values of financial
instruments included in the Consolidated Balance Sheets.
<TABLE>
<CAPTION>
At December 31, 1996 1995
- -----------------------------------------------------------------------------------------------------------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
(In thousands)
<S> <C>
Cash and cash equivalents $ 66,708 $ 66,708 $ 23,443 $ 23,443
Net accounts receivable 419,479 419,479 400,005 400,005
Other current assets 74,964 74,964 54,070 54,070
Investments and other assets for which it is:
Practicable to estimate fair value 184,487 185,679 149,645 150,170
Not practicable to estimate fair value 62,162 -- 73,042 --
Short-term borrowings 333,185 333,185 279,305 279,305
Current portions of long-term debt and preference stock 280,772 280,772 146,969 146,969
Accounts payable 172,889 172,889 177,092 177,092
Other current liabilities 194,065 194,065 193,992 193,992
Long-term debt 2,758,769 2,767,721 2,598,254 2,694,858
Redeemable preference stock 134,500 141,621 242,000 254,809
</TABLE>
Financial instruments included in other current assets include trading
securities and miscellaneous loans receivable of the Constellation Companies.
Financial instruments included in other current liabilities represent total
current liabilities from the Consolidated Balance Sheets excluding short-term
borrowings, current portions of long-term debt and preference stock, accounts
payable, and accrued vacation costs. The carrying amount of current assets and
current liabilities approximates fair value because of the short maturity of
these instruments.
Investments and other assets include investments in common and preferred
securities, which are classified as financial investments in the Consolidated
Balance Sheets, and the nuclear decommissioning trust fund. The fair value of
investments and other assets is based on quoted market prices where available.
It was not practicable to estimate the fair value of the Constellation
Companies' investments in several financial partnerships which invest in
nonpublic debt and equity securities, investments in several partnerships which
own solar powered energy production facilities, and in an investment in a
company involved in the development of international power projects because the
timing and magnitude of cash flows from these investments are difficult to
predict. These investments are carried at their original cost in the
Consolidated Balance Sheets.
The investments in financial partnerships totaled $48 million and $50 million at
December 31, 1996 and 1995, respectively, representing ownership interests up to
10%. The aggregate assets of these partnerships totaled $6.1 billion at December
31, 1995. The investments in solar powered energy production facility
partnerships totaled $11 million and $22 million at December 31, 1996 and 1995,
respectively, representing ownership interests up to 12%. The aggregate assets
of these partnerships totaled $35 million at December 31, 1995.
The fair value of fixed-rate long-term debt and redeemable preference stock is
estimated using quoted market prices where available or by discounting remaining
cash flows at the current market rate. The carrying amount of variable-rate
long-term debt approximates fair value.
BGE and the Constellation Companies have loan guarantees on outstanding
indebtedness totaling $21 million and $47 million, respectively, at December 31,
1996 and $22 million and $35 million, respectively, at December 31, 1995 for
which it is not practicable to determine fair value. It is not anticipated that
these loan guarantees will need to be funded.
Baltimore Gas and Electric Company and Subsidiaries
36
<PAGE>
Note 14. Quarterly Financial Data (Unaudited)
The following data are unaudited but, in the opinion of Management, include all
adjustments necessary for a fair presentation. BGE's utility business is
seasonal in nature with the peak sales periods generally occurring during the
summer and winter months. Accordingly, comparisons among quarters of a year may
not be indicative of overall trends and changes in operations.
<TABLE>
<CAPTION>
Quarter Ended
------------------------------------------------------------- Year Ended
March 31 June 30 September 30 December 31 December 31
- -------------------------------------------------------------------------------------------------------------------------
(In thousands, except per-share amounts)
<S> <C>
1996
Revenues $861,330 $731,707 $825,960 $734,250 $3,153,247
Income from operations 201,315 148,637 275,667 43,846 669,465
Net income 100,781 64,553 146,482 (992) 310,824
Earnings applicable to common stock 91,118 52,448 137,862 (9,140) 272,288
Earnings per share of common stock 0.62 0.36 .93 (.06) 1.85
=============================================================================
1995
Revenues $717,806 $642,500 $848,781 $725,712 $2,934,799
Income from operations 148,222 120,920 299,744 126,806 695,692
Net income 70,854 50,889 163,335 52,929 338,007
Earnings applicable to common stock 60,902 40,937 153,104 42,486 297,429
Earnings per share of common stock 0.41 0.28 1.04 0.29 2.02
=============================================================================
</TABLE>
1996
Results for the second quarter reflect:
(bullet) the $4.5 million after-tax write-off of disallowed replacement energy
costs (see Note 1).
(bullet) the $14.6 million after-tax gain on the sale by a Constellation
partnership of a power purchase agreement (see Note 3).
(bullet) the $7.0 million and $3.0 million after-tax write-offs by the
Constellation Companies of the investment in two geothermal wholesale
power generating plants and the development costs of a proposed
coal-fired power project, respectively (see Note 3).
Results for the third quarter reflect the $6.2 million after-tax write-off by
the Constellation Companies of a portion of a solar power project investment
(see Note 3).
Results for the fourth quarter reflect the $57.6 million after-tax write-off of
disallowed replacement energy costs (see Note 1).
1995
Results for the third quarter reflect the $9.7 million after-tax write-off of
certain Perryman costs (see Note 1).
Baltimore Gas and Electric Company and Subsidiaries
37
<PAGE>
ITEM 7. Financial Statements and Exhibits
(c) Exhibit No. 2* Registration Statement on Form S-4 of Constellation
Energy Corporation, as amended, which became
effective February 9, 1996, Registration No.
33-64799.
Exhibit No. 12 Computation of Ratio of Earnings to Fixed Charges
and Computation of Ratio of Earnings to Combined
Fixed Charges and Preferred and Preference Dividend
Requirements.
Exhibit No. 23 Consent of Coopers & Lybrand L.L.P., Independent
Certified Public Accountants.
Exhibit No. 27 Financial Data Schedule.
*Incorporated by Reference.
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
BALTIMORE GAS AND ELECTRIC COMPANY
(Registrant)
Date March 7, 1997 /s/ D. A. Brune
--------------- -----------------------------------
D. A. Brune, Vice President
on behalf of the Registrant and
as Principal Financial Officer
38
<PAGE>
EXHIBIT INDEX
Exhibit
Number
2* Registration Statement on Form S-4 of Constellation
Energy Corporation, as amended, which became effective
February 9, 1996, Registration No. 33-64799.
12 Computation of Ratio of Earnings to Fixed Charges and
Computation of Ratio of Earnings to Combined Fixed
Charges and Preferred and Preference Dividend
Requirements.
23 Consent of Coopers & Lybrand L.L.P., Independent
Certified Public Accountants.
27 Financial Data Schedule.
*Incorporated by Reference.
39
EXHIBIT 12
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND
COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND
PREFERRED AND PREFERENCE DIVIDEND REQUIREMENTS
<TABLE>
<CAPTION>
12 Months Ended
-------------------------------------------------------
December December December December December
1996 1995 1994 1993 1992
-------------------------------------------------------
(In Thousands of Dollars)
<S> <C>
Net Income $310,824 $338,007 $323,617 $309,866 $264,347
Taxes on Income 169,202 172,388 156,702 140,833 105,994
-------- -------- -------- -------- --------
Adjusted Net Income $480,026 $510,395 $480,319 $450,699 $370,341
-------- -------- -------- -------- --------
Fixed Charges:
Interest and Amortization of Debt Discount
and Expense and Premium on all Indebtedness $203,923 $206,666 $204,206 $199,415 $200,848
Capitalized Interest 15,664 15,050 12,427 16,167 13,800
Interest Factor in Rentals 1,548 2,099 2,010 2,144 2,033
-------- -------- -------- -------- --------
Total Fixed Charges $221,135 $223,815 $218,643 $217,726 $216,681
-------- -------- -------- -------- --------
Preferred and Preference
Dividend Requirements: (1)
Preferred and Preference Dividends $ 38,536 $ 40,578 $ 39,922 $ 41,839 $ 42,247
Income Tax Required 20,849 20,434 19,074 18,763 16,729
-------- -------- -------- -------- --------
Total Preferred and Preference
Dividend Requirements $ 59,385 $ 61,012 $ 58,996 $ 60,602 $ 58,976
-------- -------- -------- -------- --------
Total Fixed Charges and Preferred
and Preference Dividend Requirements $280,520 $284,827 $277,639 $278,328 $275,657
======== ======== ======== ======== ========
Earnings (2) $685,497 $719,160 $686,535 $652,258 $573,222
======== ======== ======== ======== ========
Ratio of Earnings to Fixed Charges 3.10 3.21 3.14 3.00 2.65
Ratio of Earnings to Combined Fixed
Charges and Preferred and Preference
Dividend Requirements 2.44 2.52 2.47 2.34 2.08
</TABLE>
(1) Preferred and preference dividend requirements consist of an amount equal
to the pre-tax earnings that would be required to meet dividend
requirements on preferred stock and preference stock.
(2) Earnings are deemed to consist of net income that includes earnings of
BGE's consolidated subsidiaries, equity in the net income of BGE's
unconsolidated subsidiary, income taxes (including deferred income taxes
and investment tax credit adjustments), and fixed charges other than
capitalized interest.
EXHIBIT 23
CONSENT OF INDEPENDENT ACCOUNTANTS
We consent to the incorporation by reference in the Prospectuses prepared in
accordance with the requirements of Forms S-3 (File Nos. 333-19263, 33-61297,
33-57658, 33-49801, 33-33559 and 33-45260), Form S-4 (File No. 33-64799), and
Forms S-8 (File Nos. 33-56084 and 33-59545) of our report dated January 17,
1997, on our audits of the consolidated financial statements of Baltimore
Gas and Electric Company and Subsidiaries (the "Company"), as of December 31,
1996 and 1995 and for the years ended December 31, 1996, 1995 and 1994, included
in this Form 8-K dated March 7, 1997 of the Company.
/s/ Coopers & Lybrand L.L.P.
COOPERS & LYBRAND L.L.P.
March 7, 1997
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from BGE's
December 31, 1996 Interim Consolidated Income Statement, Balance Sheet and
Statement of Cash Flows and is qualified in its entirety by reference to such
statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> JAN-01-1996
<PERIOD-END> DEC-31-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 5,582,350
<OTHER-PROPERTY-AND-INVEST> 1,473,165
<TOTAL-CURRENT-ASSETS> 902,198
<TOTAL-DEFERRED-CHARGES> 593,257
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 8,550,970
<COMMON> 1,429,942
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 1,419,065
<TOTAL-COMMON-STOCKHOLDERS-EQ> 2,857,113
134,500
210,000
<LONG-TERM-DEBT-NET> 2,758,769
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 333,185
<LONG-TERM-DEBT-CURRENT-PORT> 197,772
83,000
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,976,631
<TOT-CAPITALIZATION-AND-LIAB> 8,550,970
<GROSS-OPERATING-REVENUE> 3,153,247
<INCOME-TAX-EXPENSE> 166,333
<OTHER-OPERATING-EXPENSES> 2,483,782
<TOTAL-OPERATING-EXPENSES> 2,650,115
<OPERATING-INCOME-LOSS> 503,132
<OTHER-INCOME-NET> 6,130
<INCOME-BEFORE-INTEREST-EXPEN> 509,262
<TOTAL-INTEREST-EXPENSE> 198,438
<NET-INCOME> 310,824
38,536
<EARNINGS-AVAILABLE-FOR-COMM> 272,288
<COMMON-STOCK-DIVIDENDS> 233,109
<TOTAL-INTEREST-ON-BONDS> 217,622
<CASH-FLOW-OPERATIONS> 701,947
<EPS-PRIMARY> 1.85
<EPS-DILUTED> 1.85
</TABLE>
