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 5, 2001
Commission IRS Employer
File Number Exact name of registrant as specified in its charter Identification No.
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1-12869 CONSTELLATION ENERGY GROUP, INC. 52-1964611
Maryland
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(State or other jurisdiction of incorporation for each registrant)
250 W. Pratt Street, Baltimore, Maryland 21201
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(Address of principal executive offices) (Zip Code)
Registrants' telephone number, including area code: (410) 234-5000
Not Applicable
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(Former name or former address, if changed since last report)
ITEM 5. Other Events
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The following financial information for the Company for the year ended December
31, 2000 is set forth in this Form 8-K:
Selected Financial Data
Management's Discussion and Analysis of Financial Condition and Results of
Operations
Forward Looking Statements
Report of Management
Report of Independent Accountants
Financial Statements
Consolidated Statements of Income
Consolidated Statements of Comprehensive 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
ITEM 7. Financial Statements and Exhibits
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(c) Exhibit No. 12(a) Constellation Energy Group, Inc. Computation
of Ratio of Earnings to Fixed Charges.
Exhibit No. 23 Consent of PricewaterhouseCoopers LLP,
Independent Accountants.
SIGNATURES
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 hereunto duly authorized.
CONSTELLATION ENERGY GROUP, INC.
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(Registrant)
March 5, 2001 /s/ David A. Brune
Date: ________________________ ____________________________________________
David A. Brune, Vice President on behalf of
the Registrant and as Principal Financial
Officer of Registrant
3
SELECTED FINANCIAL DATA
2000 1999 1998 1997 1996
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(Dollar amounts in millions, except per share amounts)
Summary of Operations
Total Revenues $ 3,878.5 $3,786.2 $3,386.4 $3,307.6 $3,153.2
Total Expenses 3,038.3 3,026.3 2,647.9 2,584.0 2,483.7
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Income From Operations 840.2 759.9 738.5 723.6 669.5
Other Income (Expense) 6.6 7.9 5.7 (52.8) 6.1
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Income Before Fixed Charges and Income Taxes 846.8 767.8 744.2 670.8 675.6
Fixed Charges 271.4 255.0 260.6 258.7 237.0
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Income Before Income Taxes 575.4 512.8 483.6 412.1 438.6
Income Taxes 230.1 186.4 177.7 158.0 166.3
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Income Before Extraordinary Item 345.3 326.4 305.9 254.1 272.3
Extraordinary Loss, Net of Income Taxes -- (66.3) -- -- --
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Net Income $ 345.3 $ 260.1 $ 305.9 $ 254.1 $ 272.3
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Earnings Per Share of Common Stock and
Earnings Per Share of Common Stock--
Assuming Dilution Before Extraordinary Item $ 2.30 $ 2.18 $ 2.06 $ 1.72 $ 1.85
Extraordinary Loss, Net of Income Taxes -- (.44) -- -- --
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Earnings Per Share of Common Stock and
Earnings Per Share of Common Stock--
Assuming Dilution $ 2.30 $ 1.74 $ 2.06 $ 1.72 $ 1.85
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Dividends Declared Per Share of Common Stock $ 1.68 $ 1.68 $ 1.67 $ 1.63 $ 1.59
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Summary of Financial Condition
Total Assets $12,384.6 $9,683.8 $9,434.1 $8,900.0 $8,678.2
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Capitalization
Long-term debt $ 3,159.3 $2,575.4 $3,128.1 $2,988.9 $2,758.8
Redeemable preference stock -- -- -- 90.0 134.5
Preference stock not subject to mandatory
redemption 190.0 190.0 190.0 210.0 210.0
Common shareholders' equity 3,153.0 2,993.0 2,981.5 2,870.4 2,854.7
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Total Capitalization $ 6,502.3 $5,758.4 $6,299.6 $6,159.3 $5,958.0
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Financial Statistics at Year End
Ratio of Earnings to Fixed Charges 2.78 2.87 2.60 2.35 2.44
Book Value Per Share of Common Stock $ 20.95 $ 20.01 $ 19.98 $ 19.44 $ 19.33
Number of Common Shareholders (In Thousands) 60.1 66.1 69.9 73.7 77.6
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
INTRODUCTION
On April 30, 1999, Constellation Energy(R) Group, Inc. (Constellation Energy)
became the holding company for Baltimore Gas and Electric Company (BGE(R)) and
Constellation(R) Enterprises, Inc. Constellation Enterprises was previously
owned by BGE.
References in this report to "we" and "our" are to Constellation Energy and
its subsidiaries, collectively. Reference in this report to the "utility
business" is to BGE.
Constellation Energy's subsidiaries primarily include a domestic merchant
energy business focused mostly on power marketing and merchant generation in
North America, and BGE.
We realigned our organization in response to the deregulation of electric
generation in Maryland. In the first quarter of 2000, we combined our wholesale
power marketing operation with our domestic plant development and operation
activities to form a domestic merchant energy business. At the same time, we
revised our operating segments to reflect those realignments as presented in
Note 2.
On July 1, 2000, as a result of the deregulation of electric generation, BGE
transferred its generating assets and related liabilities at book value to new
nonregulated subsidiaries -- Calvert Cliffs Nuclear Power Plant, Inc. and
Constellation Power Source Generation, Inc. We discuss the deregulation of
electric generation in the Current Issues--Electric Competition section.
Effective July 1, 2000, we formed a nonregulated holding company,
Constellation Power Source Holdings, Inc., that includes:
. the wholesale power marketing and risk management activities of
Constellation Power Source,(TM) Inc.,
. the domestic power projects of Constellation Investments,(TM) Inc. and
Constellation Power,(TM) Inc., and subsidiaries, and
. the generating assets of Constellation Power Source Generation, Inc.
As a result of these changes, our domestic merchant energy business includes
the operations of Constellation Power Source Holdings, the nuclear generation of
Calvert Cliffs Nuclear Power Plant, Inc., and the nuclear consulting services of
Constellation Nuclear,(TM) LLC.
Also, effective July 1, 2000, the financial results of the electric generation
portion of our business are included in the domestic merchant energy business.
Prior to that date, the financial results of electric generation were included
in BGE's regulated electric business.
BGE remains a regulated electric and gas public utility distribution company
with a service territory in the City of Baltimore and all or part of ten
counties in Central Maryland.
Our other nonregulated businesses include the:
. Latin American power projects of Constellation Power, and subsidiaries,
. energy products and services of Constellation Energy Source,(TM) Inc.,
. home products, commercial building systems, and residential and commercial
electric and gas retail marketing of BGE Home Products & Services,(TM) Inc.
and subsidiaries,
. general partnership, in which BGE is a partner, of District Chilled Water
General Partnership (ComfortLink(R)) that provides cooling services for
commercial customers in Baltimore,
. financial investments of Constellation Investments, and
. real estate holdings and senior-living facilities of Constellation Real
Estate Group,(TM) Inc.
As discussed further in the Strategy section, on October 23, 2000, we
announced initiatives to separate our domestic merchant energy business from our
remaining businesses. These remaining businesses include BGE and the other
nonregulated businesses described above.
In this discussion and analysis, we explain the general financial condition
and the results of operations for Constellation Energy including:
. what factors affect our businesses,
. what our earnings and costs were in 2000 and 1999,
. why our earnings and costs changed from the year before,
. where our earnings come from,
. how all of this affects our overall financial condition,
. what our expenditures for capital projects were for 1998 through 2000, and
what we expect them to be through 2003, and
. where we expect to get cash for future capital expenditures.
As you read this discussion and analysis, refer to our Consolidated Statements
of Income, which present the results of our operations for 2000, 1999, and 1998.
We analyze and explain the differences between periods by operating segment. Our
analysis is important in making decisions about your investments in
Constellation Energy.
Also, this discussion and analysis is based on the operation of the electric
generation portion of our utility business under rate regulation through June
30, 2000. Our regulated electric business changed as we transferred our electric
generation assets and related liabilities to our domestic merchant energy
business and we entered into retail customer choice for electric generation
effective July 1, 2000. In addition, we announced our intention to separate our
domestic merchant energy business from our remaining businesses. Accordingly,
the results of operations and financial condition described in this discussion
and analysis are not necessarily indicative of future performance.
STRATEGY
Customer choice significantly impacts our business. In response to customer
choice, we regularly evaluate our strategies with two goals in mind: to improve
our competitive position, and to anticipate and adapt to regulatory change.
Prior to July 1, 2000, the majority of our earnings were from BGE. Going
forward, prior to separating into two companies, we expect to derive almost two-
thirds of our earnings from our domestic merchant energy business.
While BGE continues to be regulated and to deliver electricity and natural gas
through its core distribution business, our primary growth strategies center on
the nonregulated domestic merchant energy business with the objective of
providing new sources of earnings growth.
On October 23, 2000, we announced three initiatives to advance our growth
strategies. The first initiative is that we entered into an agreement (the
"Agreement") with an affiliate of The Goldman Sachs Group, Inc. ("Goldman
Sachs"). Under the terms of the Agreement, Goldman Sachs will acquire up to a
17.5% equity interest in our domestic merchant energy business, which will be
consolidated under a single holding company ("Holdco"). Goldman Sachs will also
acquire a ten-year warrant for up to 13% of Holdco's common stock (subject to
certain adjustments). The warrant is exercisable six months after Holdco's
common stock becomes publicly available. The amount of common stock which
Goldman Sachs may receive upon exercise will be equal to the excess of the
market price of Holdco's common stock at the time of exercise over the exercise
price of $60 per share for all the stock subject to the warrant, divided by the
market price. Holdco may at its option pay Goldman Sachs such excess in cash.
Goldman Sachs is acquiring its interest and the warrant in exchange for $250
million in cash (subject to adjustment in certain instances) and certain assets
related to our power marketing operation. At closing, Goldman Sachs' existing
services agreement with our power marketing operation will terminate.
The second initiative is a plan to separate our domestic merchant energy
business from our remaining businesses as discussed in the introduction. The
separation will create two stand-alone, publicly traded energy companies. One
will be a merchant energy business engaged in wholesale power marketing and
generation under the name "Constellation Energy Group" after the separation. The
other will be a regional retail energy delivery and energy services company, BGE
Corp., which will include BGE, our other nonregulated businesses, and our
investment in Orion Power Holdings, Inc. ("Orion").
As a result of the separation, shareholders will continue to own all of
Constellation Energy's current businesses through their ownership of the new
Constellation Energy Group and BGE Corp.
The third initiative is a change in our common stock dividend policy effective
April 2001. In a move closely aligned with our separation plan, effective April
2001, our annual dividend is expected to be set at $.48 per share. After the
separation, BGE Corp. expects to pay initial annual dividends of $.48 per share.
Constellation Energy Group, as a growing merchant energy company, initially
expects to reinvest its earnings in order to fund its growth plans and not to
pay a dividend.
The closing of the transaction with Goldman Sachs and the separation are
subject to customary closing conditions and contingent upon obtaining regulatory
approvals and a Private Letter Ruling from the Internal Revenue Service
regarding certain tax matters. The transaction and separation are expected to be
completed by mid to late 2001.
We discuss these strategic initiatives further in our Report on Form 8-K and
exhibits filed with the Securities and Exchange Commission (SEC)on October 23,
2000.
Currently, our domestic merchant energy business controls over 9,000 megawatts
of generation. In December 2000, we announced that a subsidiary of Constellation
Nuclear will purchase 1,550 megawatts of the 1,757 megawatts total generating
capacity of the Nine Mile Point nuclear power plant located in Scriba, New York.
The total purchase price, including fuel, is $815 million. We discuss the
planned acquisition of the Nine Mile Point power plant in more detail in Note
10.
We also plan to construct generating facilities representing 1,100 megawatts
of natural gas-fired peaking capacity in the Mid-Atlantic and Mid-West regions
by the summer of 2001. An additional 6,700 megawatts of natural gas-fired
peaking and combined cycle production facilities in the Mid-West and South
regions are scheduled for completion in 2002 and beyond. By 2005, our domestic
merchant energy business expects to control approximately 30,000 megawatts
through the construction or purchase of additional nuclear and non-nuclear
generation assets and through contractual arrangements.
We decided to exit the Latin American portion of our operation as a result of
our concentration on domestic merchant energy. Currently, we are actively
seeking a buyer for the Latin American portion of our business and are working
toward completing our exit strategy in 2001.
We also might consider one or more of the following strategies:
. the complete or partial separation of our transmission and distribution
functions,
. mergers or acquisitions of utility or non-utility businesses, and
. sale of generation assets or one or more businesses.
CURRENT ISSUES
With the shift toward customer choice, competition, and the growth of our
domestic merchant energy business, various factors will affect our financial
results in the future. These factors include, but are not limited to, operating
our generation assets in a deregulated market without the benefit of a fuel rate
adjustment clause, the timing and implications of deregulation in other regions
where our domestic merchant energy business will operate, the loss of revenues
due to customers choosing alternative suppliers, higher volatility of earnings
and cash flows, and increased financial requirements of our domestic merchant
energy business. Please refer to the Forward Looking Statements section for
additional factors.
In this section, we discuss in more detail several issues that affect our
businesses.
Electric Competition
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We are facing electric competition on various fronts, including:
. the construction of generating units to meet increased demand for
electricity,
. the sale of electricity in wholesale power markets,
. competing with alternative energy suppliers, and
. electric sales to retail customers.
Maryland
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On April 8, 1999, Maryland enacted the Electric Customer Choice and Competition
Act of 1999 (the "Act") and accompanying tax legislation that significantly
restructured Maryland's electric utility industry and modified the industry's
tax structure.
In the Restructuring Order discussed below, the Maryland Public Service
Commission (Maryland PSC) addressed the major provisions of the Act. The
accompanying tax legislation is discussed in detail in Note 4.
On November 10, 1999, the Maryland PSC issued a Restructuring Order that
resolved the major issues surrounding electric restructuring, accelerated the
timetable for customer choice, and addressed the major provisions of the Act.
The Restructuring Order also resolved the electric restructuring proceeding
(transition costs, customer price protections, and unbundled rates for electric
services) and a petition filed in September 1998 by the Office of People's
Counsel (OPC) to lower our electric base rates. The major provisions of the
Restructuring Order are discussed in Note 4.
We believe that the Restructuring Order provided sufficient details of the
transition plan to competition for BGE's electric generation business to require
BGE to discontinue the application of Statement of Financial Accounting
Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of
Regulation for that portion of its business. Accordingly, in the fourth quarter
of 1999, we adopted the provisions of SFAS No. 101, Regulated Enterprises--
Accounting for the Discontinuation of FASB Statement No. 71 and Emerging Issues
Task Force Consensus (EITF) No. 97-4, Deregulation of the Pricing of
Electricity--Issues Related to the Application of FASB Statements No. 71 and 101
for BGE's electric generation business. BGE's transmission and distribution
business continues to meet the requirements of SFAS No. 71 as that business
remains regulated. We describe the effect of applying these accounting
requirements in Note 4.
Please refer to Note 10 for a discussion regarding appeals of the
Restructuring Order.
As a result of the deregulation of electric generation, the following occurred
effective July 1, 2000:
. All customers, except a few commercial and industrial companies that have
signed contracts with BGE, can choose their electric energy supplier. BGE
will provide a standard offer service for customers that do not select an
alternative supplier. In either case, BGE will continue to deliver
electricity to all customers in areas traditionally served by BGE.
. BGE reduced residential base rates by approximately 6.5%, on average about
$54 million a year. These rates will not change before July 2006.
. BGE transferred, at book value, its nuclear generating assets, its nuclear
decommissioning trust fund, and related liabilities to Calvert Cliffs
Nuclear Power Plant, Inc. In addition, BGE transferred, at book value, its
fossil generating assets and related liabilities and its partial ownership
interest in two coal plants and a hydroelectric plant located in
Pennsylvania to Constellation Power Source Generation. In total, these
generating assets represent about 6,240 megawatts of generation capacity
with a total net book value at June 30, 2000 of approximately $2.4 billion.
. BGE assigned approximately $47 million to Calvert Cliffs Nuclear Power
Plant, Inc. and $231 million to Constellation Power Source Generation of
tax-exempt debt related to the transferred assets. Also, Constellation Power
Source Generation issued approximately $366 million in unsecured promissory
notes to BGE. Repayments of the notes by Constellation Power Source
Generation will be used exclusively to service the current maturities of
certain BGE long-term debt.
. BGE transferred equity associated with the generating assets to Calvert
Cliffs Nuclear Power Plant, Inc. and Constellation Power Source Generation.
. The fossil fuel and nuclear fuel inventories, materials and supplies, and
certain purchased power contracts of BGE were also assumed by these
subsidiaries.
Effective July 1, 2000, BGE provides standard offer service to customers at
fixed rates over various time periods during the transition period for those
customers that do not choose an alternate supplier. In addition, the electric
fuel rate was discontinued effective July 1, 2000. Constellation Power Source
provides BGE with the energy and capacity required to meet its standard offer
service obligations for the first three years of the transition period.
Thereafter, BGE will competitively bid the energy and capacity.
Constellation Power Source obtains the energy and capacity to supply BGE's
standard offer service obligations from affiliates that own Calvert Cliffs
Nuclear Power Plant (Calvert Cliffs) and BGE's former fossil plants,
supplemented with energy and capacity purchased from the wholesale market as
necessary.
Other States
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Our domestic merchant energy business is focused on expanding its business
through marketing energy products to wholesale customers and acquiring control
of additional generating facilities. This business will focus on states with
strong growth in energy demand and that provide opportunities through ongoing
deregulation and the creation of competitive markets. Delays in, or the ultimate
form of, deregulation of electric generation in various states may affect our
domestic merchant energy business strategy.
Our domestic merchant energy business has $297.9 million invested in power
projects that sell 142 megawatts of electricity in California under power
purchase agreements as discussed in the California Power Purchase Agreements
section. The counterparties to the agreements are two California investor-owned
utilities that recently were downgraded by rating agencies to below investment
grade. Due to various factors, including extreme weather and shortage of
generation, these utilities are paying more for power than they can recover from
their customers under the deregulation plan in California. The governor and
legislature of California have undertaken emergency actions to provide financial
support that could help stabilize the financial condition of the two utilities.
At December 31, 2000, credit exposure under these agreements was not material
to our financial results. However, if the ultimate resolution of the events in
California prevents collection of unpaid balances under power purchase
agreements on some or all of our projects, a material impact could result.
Additionally, if the events in California result in a modification or
termination of these agreements that reduces future cash flows, we would have to
evaluate whether our investments in the power projects that are parties to the
agreements are impaired. An impairment of these investments could have a
material impact on our financial results. Our domestic merchant energy business
does not have any other direct agreements with these utilities. However, we may
be impacted if one or more of our other counterparties is significantly affected
by the events in California, or by the operation of the California Power
Exchange.
Gas Competition
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Currently, no regulation exists for the wholesale price of natural gas as a
commodity, and the regulation of interstate transmission at the federal level
has been reduced. All BGE gas customers have the option to purchase gas from
other suppliers.
Regulation by the Maryland PSC
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In addition to electric restructuring which was discussed earlier, regulation by
the Maryland PSC influences BGE's businesses.
Under traditional rate regulation that continues after July 1, 2000 for BGE's
electric transmission and distribution, and gas businesses, the Maryland PSC
determines the rates we can charge our customers. Prior to July 1, 2000, BGE's
regulated electric rates consisted primarily of a "base rate" and a "fuel rate."
Effective July 1, 2000, BGE discontinued its electric fuel rate and unbundled
its rates to show separate components for delivery service, competitive
transition charges, standard offer services (generation), transmission,
universal service, and taxes. The rates for BGE's regulated gas business
continue to consist of a "base rate" and a "fuel rate."
Base Rate
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The base rate is the rate the Maryland PSC allows BGE to charge its customers
for the cost of providing them service, plus a profit. BGE has both an electric
base rate and a gas base rate. Higher electric base rates apply during the
summer when the demand for electricity is higher. Gas base rates are not
affected by seasonal changes.
BGE may ask the Maryland PSC to increase base rates from time to time. The
Maryland PSC historically has allowed BGE to increase base rates to recover
increased utility fixed asset costs, 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. Other parties may petition the Maryland PSC to decrease base
rates.
On November 17, 1999, BGE filed an application with the Maryland PSC to
increase its gas base rates. On June 19, 2000, the Maryland PSC authorized a
$6.4 million annual increase in our gas base rates effective June 22, 2000. As a
result of the Restructuring Order, BGE's residential electric base rates are
frozen until 2006.
Electric delivery service rates are frozen for a four-year period for
commercial and industrial customers. The generation and transmission components
of rates are frozen for different time periods depending on the service options
selected by those customers.
Fuel Rate
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Through June 30, 2000, we charged our electric customers separately for the fuel
we used to generate electricity (nuclear fuel, coal, gas, or oil) and for the
net cost of purchases and sales of electricity. We charged the actual cost of
these items to the customer with no profit to us. If these fuel costs went up,
the Maryland PSC permitted us to increase the fuel rate.
Under the Restructuring Order, BGE's electric fuel rate was frozen until July
1, 2000, at which time the fuel rate clause was discontinued. We deferred the
difference between our actual costs of fuel and energy and what we collected
from customers under the fuel rate through June 30, 2000.
In September 2000, the Maryland PSC approved the collection of the $54.6
million accumulated difference between our actual costs of fuel and energy and
the amounts collected from customers that were deferred under the electric fuel
rate clause through June 30, 2000. We are collecting this accumulated difference
from customers over the twelve-month period beginning October 2000. Effective
July 1, 2000, our earnings are affected by the changes in the cost of fuel and
energy.
We charge our gas customers separately for the natural gas they purchase from
us. The price we charge for the natural gas is based on a market based rates
incentive mechanism approved by the Maryland PSC. We discuss market based rates
in more detail in the Gas Cost Adjustments section and in Note 1.
FERC Regulation--Regional Transmission Organizations
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In December 1999, the Federal Energy Regulatory Commission (FERC) issued Order
2000, amending its regulations under the Federal Power Act to advance the
formation of Regional Transmission Organizations (RTOs). The regulations require
that each public utility that owns, operates, or controls facilities for the
transmission of electric energy in interstate commerce make certain filings with
respect to forming and participating in a RTO. FERC also identified the minimum
characteristics and functions that a transmission entity must satisfy in order
to be considered a RTO.
According to the Order, a public utility that is a member of an existing
transmission entity that has been approved by FERC as in conformance with the
Independent System Operator (ISO) principles set forth in the FERC Order No.
888, such as BGE, through its membership in PJM (Pennsylvania-New Jersey-
Maryland) Interconnection, was required to make a filing no later than January
15, 2001. PJM and the joint transmission owners, including BGE, made the filing
on October 11, 2000. That filing explained the extent to which PJM met the
minimum characteristics and functions of a RTO and explained its plans to
conform to these characteristics and functions.
As a member of PJM, an existing ISO, BGE does not expect to be materially
impacted by the Order. However, we are appealing two requirements of the Order
whereby:
. we would have to go through PJM to make a filing with FERC to change our
transmission rates, and
. we would have to transfer operational control of our transmission facilities
to PJM (or any other RTO we may wish to join).
Weather
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Domestic Merchant Energy Business
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Weather conditions in the different regions of North America influence the
financial results of our domestic merchant energy business. Typically, demand
for electricity and its price are higher in the summer and the winter, when
weather is more extreme. However, all regions of North America typically do not
experience extreme weather conditions at the same time. Since the majority of
our generating plants currently are located in PJM, our financial results are
affected, to a greater extent, by weather conditions in this area. However, by
2005, we expect to control approximately 30,000 megawatts of generation
throughout various regions of North America.
Current weather conditions also can affect the forward market price of energy
commodity and derivative contracts used by our power marketing operation that
are accounted for on a mark-to-market basis. To the extent that our power
marketing operation purchases and sells such contracts, our financial results
could be influenced by the impact that weather conditions have on the market
price of such contracts.
BGE
- ---
Weather affects the demand for electricity and gas for our regulated businesses.
Very hot summers and very cold winters increase demand. Mild weather reduces
demand. Residential sales for our regulated businesses are impacted more by
weather than commercial and industrial sales, which are mostly affected by
business needs for electricity and gas.
However, the Maryland PSC allows us to record a monthly adjustment to our
regulated gas business revenues to eliminate the effect of abnormal weather
patterns. We discuss this further in the Weather Normalization section.
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 average daily
actual temperature exceeds the 65 degree baseline. Heating degree days result
when the average daily actual temperature is less than the baseline.
During the cooling season, hotter weather is measured by more cooling degree
days and results in greater demand for electricity to operate cooling systems.
During the heating season, colder weather is measured by more heating degree
days and results in greater demand for electricity and gas to operate heating
systems.
We show the number of cooling and heating degree days in 2000 and 1999, the
percentage change in the number of degree days from the prior year, and the
number of degree days in a "normal" year as represented by the 30-year average
in the following table.
30-year
2000 1999 Average
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Cooling degree days 736 845 840
Percentage change from
prior year (12.9)% (7.7)%
Heating degree days 4,936 4,585 4,771
Percentage change from
prior year 7.7% 11.3%
Other Factors
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Other factors, aside from weather, impact the demand for electricity and gas in
our regulated businesses. These factors include the "number of customers" and
"usage per customer" during a given period. We use these terms later in our
discussions of regulated electric and gas operations. In those sections, we
discuss how these and other factors affected electric and gas sales during the
periods presented.
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.
Under the Restructuring Order, BGE's electric customers can become delivery
service customers only and can purchase their electricity from other sources. We
will collect a delivery service charge to recover the fixed costs for the
service we provide. The remaining electric customers will receive standard offer
service from BGE at the fixed rates provided by the Restructuring Order. Usage
per customer refers to all other items impacting customer sales that cannot be
measured separately. 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.
Environmental and Legal Matters
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You will find details of our environmental and legal matters in Note 10 and in
our most recent Annual Report on Form 10-K. Some of the information is about
costs that may be material to our financial results.
Accounting Standards Issued
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We discuss recently issued accounting standards in Note 1.
RESULTS OF OPERATIONS
In this section, we discuss our earnings and the factors affecting them. We
begin with a general overview, then separately discuss earnings for our
operating segments. Changes in fixed charges and income taxes are discussed in
the aggregate for all segments in the Consolidated Nonoperating Income and
Expenses section.
Overview
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Total Earnings Per Share of Common Stock
2000* 1999 1998
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Earnings before nonrecurring
charges included in operations:
Domestic merchant energy $1.48 $ .44 $ .36
Regulated electric .71 1.81 1.75
Regulated gas .20 .22 .18
Other nonregulated .04 .01 (.09)
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Total earnings per share before
nonrecurring charges included
in operations: 2.43 2.48 2.20
Nonrecurring charges included
in operations (see Note 2):
Deregulation transition
cost (.10) -- --
TVSERP (.03) -- --
Hurricane Floyd -- (.03) --
Write-downs of power
projects -- (.12) --
Write-off of energy
services investment -- -- (.04)
Write-down of financial
investment -- (.11) --
Write-down of real estate
and senior-living
investments -- (.04) (.10)
- ------------------------------------------------------------------------
Total earnings per share before
extraordinary item 2.30 2.18 2.06
Extraordinary loss (see Note 4) -- (.44) --
- ------------------------------------------------------------------------
Total earnings per share $2.30 $1.74 $2.06
========================================================================
*Earnings for the years presented reflect a significant shift from the regulated
electric business to the domestic merchant energy business as a result of the
transfer of BGE's electric generation assets to nonregulated subsidiaries on
July 1, 2000 in accordance with the Restructuring Order. We discuss the
Restructuring Order in more detail in Note 4.
2000
- ----
Our 2000 total earnings increased $85.2 million, or $.56 per share, compared to
1999 mostly because we recorded an extraordinary charge of $66.3 million, or
$.44 per share, associated with the deregulation of the electric generation
portion of our business in 1999. In addition, we recorded several nonrecurring
charges in 1999 that had a negative impact in that year as discussed below. In
2000, we recorded the following nonrecurring charges in operations:
. $15.0 million after-tax, or $.10 per share, deregulation transition cost in
June 2000 to a third party incurred by our power marketing operation to
provide BGE's standard offer service requirements, and
. $4.2 million after-tax, or $.03 per share, expense during the first and
second quarters of 2000 for BGE employees that elected to participate in a
Targeted Voluntary Special Early Retirement Program (TVSERP).
Earnings before nonrecurring charges included in operations decreased $7.3
million, or $.05 per share, mostly because we recognized $29.9 million, or $18.1
million after-tax, of the 6.5% annual residential rate reduction that was
effective July 1, 2000 and we had higher interest costs in 2000 compared to
1999. We also recognized $5.7 million after-tax, or $.04 per share, for
contributions to the universal service fund relating to the deregulation of
electric generation. These decreases were offset partially by higher earnings in
our domestic merchant energy and our other nonregulated businesses.
In 2000, earnings from our domestic merchant energy business before
nonrecurring charges increased compared to 1999 because of higher earnings in
both our power marketing and domestic generation operations.
In 2000, earnings from our other nonregulated businesses increased mostly
because of higher earnings in our financial investments operation.
1999
- ----
Our 1999 total earnings decreased $45.8 million, or $.32 per share, compared to
1998. Our total earnings decreased mostly because we recorded an extraordinary
charge associated with the deregulation of the electric generation portion of
our business. We discuss the extraordinary charge in Note 4. Our 1999 total
earnings also include the following nonrecurring items included in our
operations:
. Our regulated electric business recorded $4.9 million after-tax, or $.03 per
share, of expenses related to Hurricane Floyd.
. Our domestic generation operation recorded write-downs of certain power
projects for $14.2 million after-tax, or $.09 per share, and our Latin
American operation recorded a $4.5 million after-tax, or $.03 per share,
write-down of a power project.
. Our financial investments operation recorded a $16.0 million after-tax, or
$.11 per share, write-down of a financial investment.
. Our real estate and senior-living facilities operation recorded a $5.8
million after-tax, or $.04 per share, write-down of certain senior-living
facilities.
These decreases were offset partially by higher earnings from regulated
utility, domestic merchant energy, and other nonregulated business operations
excluding nonrecurring charges.
In 1999, regulated utility earnings before the extraordinary charge increased
compared to 1998 mostly because we had higher electricity and gas system sales
that year, and we settled a capacity contract with PECO Energy Company in 1998
that had a negative impact on earnings in that year. This increase was offset
partially by higher depreciation and amortization expense mostly due to the
$75.0 million amortization of the regulatory asset recorded in 1999 for the
reduction of our generation plant under the Restructuring Order, which reduced
1999 earnings by $48.8 million.
In 1999, earnings from our domestic merchant energy business before
nonrecurring charges increased compared to 1998 mostly because of higher
earnings from our power marketing operation.
In 1999, earnings from our other nonregulated businesses before nonrecurring
charges increased compared to 1998 mostly because of higher earnings from our
Latin American and real estate and senior-living facilities operations.
In the following sections, we discuss our earnings by business segment in
greater detail.
Domestic Merchant Energy Business
- ---------------------------------
Our domestic merchant energy business engages primarily in power marketing and
domestic power generation. As discussed in the Current Issues--Electric
Competition section, our domestic merchant energy business was significantly
impacted by the July 1, 2000 implementation of customer choice in Maryland. At
that time, BGE's generating assets became part of our nonregulated domestic
merchant energy business, and Constellation Power Source began selling to BGE
the energy and capacity required to meet its standard offer service obligations
for the first three years of the transition period.
Constellation Power Source obtains the energy and capacity to supply BGE's
standard offer service obligations from affiliates that own Calvert Cliffs and
BGE's former fossil plants, supplemented with energy and capacity purchased from
the wholesale market as necessary. Constellation Power Source also manages our
wholesale market price risk.
In addition, effective July 1, 2000, domestic merchant energy business
revenues include 90% of the competitive transition charges BGE collects from its
customers (CTC revenues) and the portion of BGE's revenues providing for nuclear
decommissioning costs.
Our earnings are exposed to various market risks as discussed in the Market
Risk section. For example, our earnings are exposed to the risks of the
competitive wholesale electricity market to the extent that our domestic
merchant energy business has to purchase energy and/or capacity to meet
obligations to supply power or meet other energy-related contractual
arrangements at prices which may approach or exceed the applicable fixed sales
price obligations. If the price of obtaining energy in the wholesale market
exceeds the fixed sales price, our earnings would be adversely affected. We also
are affected by operational risk, that is, the risk that a generating plant will
not be available to produce energy when the energy is required. Imbalances in
demand and supply can occur not only because of plant outages, but also because
of transmission constraints, or extreme temperatures (hot or cold) causing
demand to exceed available supply.
We cannot estimate the impact of the increased financial risks associated with
the competitive wholesale electricity market. However, these financial risks
could have a material impact on our financial results.
Earnings
2000 1999 1998
- --------------------------------------------------------------------------
(In millions, except per share amounts)
Revenues $992.0 $212.9 $147.3
Operating expenses 534.3 111.1 47.8
Depreciation and amortization 80.9 5.0 3.0
Taxes other than income taxes 24.1 -- --
- --------------------------------------------------------------------------
Income from operations $352.7 $ 96.8 $ 96.5
==========================================================================
Net income $206.8 $ 52.4 $ 53.1
==========================================================================
Total earnings per share before
nonrecurring charges
included in operations: $ 1.48 $ .44 $ .36
Deregulation transition cost (.10) -- --
Write-down of power projects -- (.09) --
- --------------------------------------------------------------------------
Earnings per share $ 1.38 $ .35 $ .36
==========================================================================
Above amounts include intercompany transactions eliminated in our Consolidated
Financial Statements. Note 2 provides a reconciliation of operating results by
segment to our Consolidated Financial Statements.
Revenues
- --------
Our 2000 domestic merchant energy revenues increased $779.1 million compared to
1999 mostly because of:
. a $581.0 million increase related to providing BGE the energy and capacity
required to meet its standard offer service obligation effective July 1,
2000,
. a $110.0 million increase related to CTC and decommissioning revenues
included in the domestic merchant energy business effective July 1, 2000,
and
. higher revenues from our power marketing and domestic generation operations.
Our 1999 domestic merchant energy revenues increased $65.6 million compared to
1998 mostly because of higher revenues from our power marketing operation offset
partially by lower revenues from our domestic generation operation.
We discuss the revenues for our power marketing and domestic generation
operations in the sections below.
Power Marketing
- ---------------
Power marketing revenues increased during 2000 compared to 1999 mostly because
of higher transaction volumes in the Mid-Atlantic, Texas, and West regions,
offset partially by lower margins.
Power marketing revenues increased during 1999 compared to 1998 mostly because
of higher transaction margins and volumes.
Constellation Power Source uses the mark-to-market method of accounting. We
discuss the mark-to-market method of accounting and Constellation Power Source's
activities in more detail in Note 1. As a result of the nature of its operations
and the use of mark-to-market accounting, Constellation Power Source's revenues
and earnings will fluctuate. We cannot predict these fluctuations, but the
effect on our revenues and earnings could be material. The primary factors that
cause these fluctuations are:
. the number and size of new transactions,
. the magnitude and volatility of changes in commodity prices and interest
rates, and
. the number and size of open commodity and derivative positions Constellation
Power Source holds or sells.
Constellation Power Source's management uses its best estimates to determine
the fair value of commodity and derivative positions it holds and sells. These
estimates consider various factors including closing exchange and over-the-
counter price quotations, time value, volatility factors, and credit exposure.
However, it is possible that future market prices could vary from those used in
recording assets and liabilities from power marketing and trading activities,
and such variations could be material. Assets and liabilities from energy
trading activities (as shown in our Consolidated Balance Sheets) increased
significantly at December 31, 2000 compared to December 31, 1999 because of
business growth during the period and increased market prices at the end of
2000.
Domestic Generation
- -------------------
Our domestic generation revenues increased during 2000 compared to 1999 mostly
because of three factors:
. Our domestic generation operation recognized $13.3 million on the
termination of an operating arrangement and the sale of certain
subsidiaries. In April 2000, Constellation Operating Services, Inc. (COSI),
a subsidiary of Constellation Power, Inc., ended its exclusive arrangement
with Orion to operate Orion's facilities. Orion purchased from COSI the four
subsidiary companies formed to operate power plants owned by Orion.
. In November 2000, our domestic generation operation recorded a $19.2 million
gain on the sale of approximately 3.2 million shares of Orion stock.
. In 1999, our domestic generation operation recorded a write-off of two
geothermal power projects as discussed below, which had a negative impact in
that year.
In 1999, our domestic generation revenues decreased compared to 1998 mostly
because of three factors:
. Our domestic generation operation wrote-off two geothermal power projects
that totaled $21.4 million. These write-offs occurred because the expected
future cash flows from the projects were less than the investment in the
projects. For the first project, this resulted from the inability to
restructure certain project agreements. For the second project, the water
temperature of the geothermal resource used by one of the plants for
production declined.
. In 1998, our domestic generation operation recorded a $17.2 million gain for
its share of earnings in a partnership. The partnership recognized a gain on
the sale of its ownership interest in a power purchase agreement.
. Revenues from our California power purchase agreements decreased as
discussed below.
California Power Purchase Agreements
- ------------------------------------
Our domestic generation operation has $297.9 million invested in 14 projects
that sell electricity in California under power purchase agreements called
"Interim Standard Offer No. 4" agreements.
Under these agreements, the electricity rates changed from fixed rates to
variable rates beginning in 1996. In 2000, the last four projects transitioned
to variable rates. In 1999 and prior years, the projects that transitioned to
variable rates had lower revenues under variable rates than they did under fixed
rates. In 2000, the prices received under these agreements were higher due to
increases in the variable-rate pricing terms. However, due to the uncertainties
in California, the recent increases in prices may not be indicative of future
prices. We discuss the developments in California in the Current Issues--
Electric Competition section.
We also describe these projects and the transition process in Note 3 and Note
10.
Operating Expenses
- ------------------
During 2000, domestic merchant energy operating expenses increased $423.2
million compared to 1999 mostly because of three factors:
. An increase of $191.6 million in fuel costs and $157.2 million in operations
and maintenance costs. These costs were associated with the generation
plants that were transferred from BGE effective July 1, 2000.
. A $24.0 million deregulation transition cost in June 2000 to a third party
incurred by our power marketing operation to provide BGE's standard offer
service requirements.
. An increase in power marketing operating expenses due to the growth of the
operation.
During 1999, domestic merchant energy operating expenses increased $63.3
million compared to 1998 mostly because of the growth in our power marketing
operation.
Depreciation and Amortization Expense
- -------------------------------------
In 2000, domestic merchant energy depreciation and amortization expense
increased $75.9 million compared to 1999 mostly because of $73.8 million of
expenses associated with the generation plants that were transferred from BGE
effective July 1, 2000.
In 1999, domestic merchant energy depreciation and amortization expense was
about the same compared to 1998.
Taxes Other than Income Taxes
- -----------------------------
In 2000, domestic merchant energy taxes other than income taxes increased $24.1
million compared to 1999 because of $23.8 million of taxes other than income
taxes associated with the generation plants that were transferred from BGE
effective July 1, 2000.
In 1999, domestic merchant energy taxes other than income taxes were the same
compared to 1998.
Regulated Electric Business
- ---------------------------
As previously discussed, our regulated electric business was significantly
impacted by the July 1, 2000 implementation of customer choice. These changes
include BGE's generating assets and related liabilities becoming part of our
nonregulated domestic merchant energy business on that date.
Earnings
2000 1999 1998
- ------------------------------------------------------------------------------
(In millions, except per share amounts)
Electric revenues $2,135.2 $2,260.0 $2,220.8
Electric fuel and
purchased energy 870.7 487.7 516.7
Operations and maintenance 454.2 629.6 630.5
Depreciation and amortization 319.9 376.4 313.0
Taxes other than income taxes 157.8 188.9 182.3
- ------------------------------------------------------------------------------
Income from operations $ 332.6 $ 577.4 $ 578.3
==============================================================================
Net income $ 102.3 $ 198.8 $ 259.6
==============================================================================
Total earnings per share
before nonrecurring charges
included in operations: $ .71 $ 1.81 $ 1.75
TVSERP (.03) -- --
Hurricane Floyd -- (.03) --
Extraordinary loss -- (.44) --
- ------------------------------------------------------------------------------
Earnings per share $ .68 $ 1.34 $ 1.75
==============================================================================
Above amounts include intercompany transactions eliminated in our Consolidated
Financial Statements. Note 2 provides a reconciliation of operating results by
segment to our Consolidated Financial Statements.
Electric Revenues
- -----------------
The changes in electric revenues in 2000 and 1999 compared to the respective
prior year were caused by:
2000 1999
- --------------------------------------------------------
(In millions)
Electric system sales volumes $ 40.9 $41.3
Rates (119.9) 4.5
Fuel rate surcharge 12.6 --
- --------------------------------------------------------
Total change in electric revenues
from electric system sales (66.4) 45.8
Interchange and other sales (58.3) (8.7)
Other (0.1) 2.1
- --------------------------------------------------------
Total change in electric revenues $(124.8) $39.2
========================================================
Electric System Sales Volumes
- -----------------------------
"Electric system sales volumes" are sales to customers in our service territory
at rates set by the Maryland PSC. These sales do not include interchange sales
and sales to others.
The percentage changes in our electric system sales volumes, by type of
customer, in 2000 and 1999 compared to the respective prior year were:
2000 1999
- ------------------------------------------
Residential 2.9% 3.5%
Commercial 3.5 2.6
Industrial 2.9 (5.1)
In 2000, we sold more electricity to residential customers compared to 1999
due to the colder winter weather, higher usage per customer, and an increased
number of customers, offset partially by mild summer weather. We sold more
electricity to commercial customers mostly due to higher usage per customer and
an increased number of customers. We sold more electricity to industrial
customers due to higher usage by Bethlehem Steel and an increased number of
customers, offset partially by lower usage by other industrial customers. Usage
was higher at Bethlehem Steel as a result of a 1999 shut down for a planned
upgrade to their facilities that temporarily reduced their electricity
consumption.
In 1999, we sold more electricity to residential customers due to higher usage
per customer, colder winter weather, and an increased number of customers
compared to 1998. This increase was offset partially by milder spring and early
summer weather. We sold more electricity to commercial customers mostly due to
higher usage per customer, an increased number of customers, and colder winter
weather. We sold less electricity to industrial customers mostly because usage
by Bethlehem Steel and other industrial customers decreased. This decrease was
offset partially by an increase in the number of industrial customers.
Rates
- -----
Prior to July 1, 2000, our rates primarily consisted of an electric base rate
and an electric fuel rate. Effective July 1, 2000, BGE discontinued its electric
fuel rate and unbundled its rates to show separate components for delivery
service, competitive transition charges, standard offer service (generation),
transmission, universal service, and taxes. BGE's rates also were frozen in
total except for the implementation of a residential base rate reduction
totaling approximately $54 million annually. In addition, 90% of the CTC
revenues BGE collects and the portion of its revenues providing for
decommissioning costs, are included in revenues of the domestic merchant energy
business effective July 1, 2000.
In 2000, rate revenues decreased compared to 1999 mostly because of the $29.9
million decrease caused by the 6.5% annual residential rate reduction, and the
$110.0 million transfer of revenues to the domestic merchant energy business
discussed above. This was offset partially by higher fuel rate revenues during
the first half of 2000.
In 1999, rate revenues increased compared to 1998 because of higher fuel rate
revenues. Fuel rate revenues increased mostly because we sold more electricity.
Fuel Rate Surcharge
- -------------------
In September 2000, the Maryland PSC approved the collection of the $54.6 million
accumulated difference between our actual costs of fuel and energy and the
amounts collected from customers that were deferred under the electric fuel rate
clause through June 30, 2000. We discuss this further in the Electric Fuel Rate
Clause section below.
Interchange and Other Sales
- ---------------------------
"Interchange and other sales" are sales in the PJM energy market and to others.
PJM is an ISO that operates a regional power pool with members that include many
wholesale market participants, as well as BGE, and other utility companies.
Prior to the implementation of customer choice, BGE sold energy to PJM members
and to others after it had satisfied the demand for electricity in its own
system.
Effective July 1, 2000, BGE no longer engages in interchange sales. These
activities are now included in our domestic merchant energy business which
resulted in a decrease in interchange and other sales for the second half of
2000 compared to 1999. In addition, BGE had lower interchange and other sales
during the first half of 2000 when increased demand for system sales reduced the
amount of energy BGE had available for off-system sales.
In 1999, interchange and other sales revenues decreased compared to 1998
mostly because higher demand for system sales reduced the amount of energy BGE
had available for off-system sales.
Electric Fuel and Purchased Energy Expenses
- -------------------------------------------
2000 1999 1998
- -----------------------------------------------------------------
(In millions)
Actual costs $868.0 $558.0 $525.7
Net recovery (deferral) of costs
under electric fuel rate clause 2.7 (70.3) (9.0)
- -----------------------------------------------------------------
Total electric fuel and purchased
energy expense $870.7 $487.7 $516.7
=================================================================
Actual Costs
- ------------
In 2000, our actual costs of fuel and purchased energy were higher compared to
1999 mostly because of the deregulation of our electric generation. As discussed
in the Current Issues--Electric Competition section, effective July 1, 2000, BGE
transferred its generating assets to, and began purchasing substantially all of
the energy and capacity required to provide electricity to standard offer
service customers from, the domestic merchant energy business. In 2000, the cost
of energy BGE purchased from our domestic merchant energy business was $581.0
million. The higher amount paid for purchased energy is offset by the absence of
$191.6 million in fuel costs, and lower operations and maintenance,
depreciation, taxes, and other costs at BGE as a result of no longer owning and
operating the transferred electric generation plants.
Prior to July 1, 2000, BGE's purchased fuel and energy costs only included
actual costs of fuel to generate electricity (nuclear fuel, coal, gas, or oil)
and electricity we bought from others.
In 1999, our actual costs of fuel to generate electricity and electricity we
bought from others were higher compared to 1998 mostly because the price of
electricity we bought from others was higher. The price of electricity changes
based on market conditions and contract terms. This increase was offset
partially by our settlement of a capacity contract with PECO in 1998.
Electric Fuel Rate Clause
- -------------------------
Prior to July 1, 2000, we deferred (included as an asset or liability on the
Consolidated Balance Sheets and excluded from the Consolidated Statements of
Income) the difference between our actual costs of fuel and energy and what we
collected from customers under the fuel rate in a given period. Effective July
1, 2000, the fuel rate clause was discontinued under the terms of the
Restructuring Order. In September 2000, the Maryland PSC approved the collection
of the $54.6 million accumulated difference between our actual costs of fuel
and energy and the amounts collected from customers that were deferred under the
electric fuel rate clause through June 30, 2000. We are collecting this
accumulated difference from customers over the twelve-month period beginning
October 2000.
In 2000, the net deferral of costs under the electric fuel rate clause
decreased compared to 1999 due to the discontinuation of the fuel rate clause
effective July 1, 2000.
In 1999, the net deferral of costs under the electric fuel rate clause
increased compared to 1998 because the 1999 deferral reflected higher purchased
power costs, especially during record-setting summer peak loads.
Electric Operations and Maintenance Expenses
- --------------------------------------------
In 2000, regulated electric operations and maintenance expenses decreased $175.4
million compared to 1999 mostly because effective July 1, 2000, $157.2 million
of costs were no longer incurred by this business segment. These costs were
associated with the electric generation assets that were transferred to the
domestic merchant energy business. In addition, 1999 operations and maintenance
expenses included costs for system restoration activities related to Hurricane
Floyd and a major winter ice storm, and costs associated with the preparation
for the year 2000 (Y2K). These costs had a negative impact in that year. These
decreases are offset partially by the $7.0 million of expense recognized in 2000
for electric business employees that elected to participate in the TVSERP.
In 1999, regulated electric operations and maintenance expenses were about the
same compared to 1998. In 1999, operations and maintenance expenses included the
costs for system restoration activities related to Hurricane Floyd and a major
winter ice storm. This was offset by lower employee benefit costs in 1999 and a
1998 $6.0 million write-off of contributions to a third party for a low-level
radiation waste facility that was never completed.
Electric Depreciation and Amortization Expense
- ----------------------------------------------
In 2000, regulated electric depreciation and amortization expense decreased
$56.5 million compared to 1999 mostly because of the absence of $73.8 million of
depreciation and amortization expense associated with the transfer of the
generation assets. This decrease was offset partially by more electric plant in
service (as our level of plant in service changes, the amount of depreciation
and amortization expense changes) and higher amortization associated with
regulatory assets.
In 1999, regulated electric depreciation and amortization expense increased
$63.4 million compared to 1998 mostly because of the $75.0 million amortization
of the regulatory asset for the reduction in generation plant provided for in
the Restructuring Order. This increase was offset partially by lower
amortization of deferred electric conservation expenditures due to the write-off
of a portion of these expenditures that will not be recovered under the
Restructuring Order. We discuss the accounting implications of the Restructuring
Order further in Note 4.
Electric Taxes Other Than Income Taxes
- --------------------------------------
In 2000, regulated electric taxes other than income taxes decreased $31.1
million compared to 1999. This was mostly due to two factors:
. regulated electric taxes other than income taxes reflect the absence of
$23.8 million of taxes other than income taxes associated with the
generation assets that were transferred to the domestic merchant energy
business effective July 1, 2000, and
. comprehensive changes to the tax laws.
The comprehensive tax law changes are discussed further in Note 4.
In 1999, regulated electric taxes other than income taxes increased slightly
due to higher property and franchise taxes associated with increased electric
revenues.
Regulated Gas Business
- ----------------------
Earnings
2000 1999 1998
- ----------------------------------------------------------------------
(In millions, except per share amounts)
Gas revenues $611.6 $488.1 $451.1
Gas purchased for resale 350.6 233.8 209.4
Operations and maintenance 100.6 97.7 97.7
Depreciation and amortization 46.2 44.9 45.4
Taxes other than income taxes 34.8 34.5 32.5
- ----------------------------------------------------------------------
Income from operations $ 79.4 $ 77.2 $ 66.1
======================================================================
Net income $ 30.6 $ 33.0 $ 26.1
======================================================================
Earnings per share $ .20 $ .22 $ .18
======================================================================
Above amounts include intercompany transactions eliminated in our Consolidated
Financial Statements. Note 2 provides a reconciliation of operating results by
segment to our Consolidated Financial Statements.
All BGE customers have the option to purchase gas from other suppliers. To
date, customer choice has not had a material effect on our, and BGE's, financial
results.
Gas Revenues
- ------------
The changes in gas revenues in 2000 and 1999 compared to the respective prior
year were caused by:
2000 1999
- -------------------------------------------------
(In millions)
Gas system sales volumes $ 34.5 $ 8.0
Base rates 2.7 2.2
Weather normalization (26.7) 4.5
Gas cost adjustments 54.7 19.8
- -------------------------------------------------
Total change in gas revenues
from gas system sales 65.2 34.5
Off-system sales 58.1 2.0
Other 0.2 0.5
- -------------------------------------------------
Total change in gas revenues $123.5 $37.0
=================================================
Gas System Sales Volumes
- ------------------------
The percentage changes in our gas system sales volumes, by type of customer, in
2000 and 1999 compared to the respective prior year were:
2000 1999
- ---------------------------------------------------
Residential 13.0% 9.2%
Commercial 12.8 12.7
Industrial (2.1) (4.8)
In 2000, we sold more gas to residential and commercial customers compared to
1999 due to higher usage per customer, colder weather, and an increased number
of customers. We sold less gas to industrial customers mostly because of lower
usage by Bethlehem Steel and other industrial customers, offset partially by an
increased number of customers.
In 1999, we sold more gas to residential customers mostly for two reasons:
colder winter weather and an increased number of customers. This was offset
partially by lower usage per customer. We sold more gas to commercial customers
mostly because of higher usage per customer, colder winter weather, and an
increased number of customers. We sold less gas to industrial customers mostly
because of lower usage by Bethlehem Steel and other industrial customers.
Base Rates
- ----------
In 2000, base rate revenues increased slightly compared to 1999 mostly because
the Maryland PSC authorized a $6.4 million annual increase in our base rates
effective June 22, 2000.
In 1999, base rate revenues increased compared to 1998 mostly because of the
$16.0 million annual increase in our base rates approved by the Maryland PSC
effective March 1, 1998.
Weather Normalization
- ---------------------
The Maryland PSC allows us to record a monthly adjustment to our gas revenues to
eliminate the effect of abnormal weather patterns on our gas system sales
volumes. This means our monthly gas revenues are based on weather that is
considered "normal" for the month and, therefore, are not affected by actual
weather conditions.
Gas Cost Adjustments
- --------------------
We charge our gas customers for the natural gas they purchase from us using gas
cost adjustment clauses set by the Maryland PSC as described in Note 1. However,
under market based rates, our actual cost of gas is compared to a market index
(a measure of the market price of gas in a given period). The difference between
our actual cost and the market index is shared equally between shareholders and
customers, and does not significantly impact earnings.
Delivery service customers, including Bethlehem Steel, are not subject to the
gas cost adjustment clauses because we are not selling gas to them. We charge
these customers fees to recover the fixed costs for the transportation service
we provide. These fees are the same as the base rate charged for gas sales and
are included in gas system sales volumes.
In 2000 and 1999, gas cost adjustment revenues increased compared to the
respective prior year mostly because we sold more gas at a higher price. In
2000, the revenue increase reflects the significant increase in natural gas
prices.
Off-System Sales
- ----------------
Off-system gas sales are low-margin direct sales of gas to wholesale suppliers
of natural gas outside our service territory. Off-system gas sales, which occur
after we have satisfied our customers' demand, are not subject to gas cost
adjustments. The Maryland PSC approved an arrangement for part of the margin
from off-system sales to benefit customers (through reduced costs) and the
remainder to be retained by BGE (which benefits shareholders).
In 2000, revenues from off-system gas sales increased compared to 1999 mostly
because we sold more gas off-system at significantly higher prices.
In 1999, revenues from off-system gas sales were about the same compared to
1998.
Gas Purchased For Resale Expenses
- ---------------------------------
Actual costs include the cost of gas purchased for resale to our customers and
for off-system sales. Actual costs do not include the cost of gas purchased by
delivery service customers.
In 2000, our gas costs increased compared to 1999 mostly because we bought
more gas for off-system sales and all of the gas purchased was at a higher price
due to the significant increase in natural gas prices during the year.
In 1999, actual gas costs increased compared to 1998 mostly because we sold
more gas.
Other Gas Operating Expenses
- ----------------------------
In 2000 and 1999, other gas operating expenses were about the same compared to
the respective prior year.
Other Nonregulated Businesses
- -----------------------------
Earnings
2000 1999 1998
- -------------------------------------------------------------------------
(In millions, except per share amounts)
Revenues $740.3 $858.1 $583.0
Operating expenses 638.0 821.5 569.4
Depreciation and amortization 23.0 23.5 13.9
Taxes other than income taxes 4.3 3.9 4.6
- -------------------------------------------------------------------------
Income (loss) from operations $ 75.0 $ 9.2 $ (4.9)
=========================================================================
Net income (loss) $ 5.6 $(24.1) $(32.9)
=========================================================================
Total earnings per share before
nonrecurring charges included
in operations: $ .04 $ .01 $ (.09)
Write-down of power project -- (.03) --
Write-down of financial
investment -- (.11) --
Write-down of real estate and
senior-living investments -- (.04) (.10)
Write-off of energy services
investment -- -- (.04)
- -------------------------------------------------------------------------
Earnings per share $ .04 $ (.17) $ (.23)
=========================================================================
Above amounts include intercompany transactions eliminated in our Consolidated
Financial Statements. Note 2 provides a reconciliation of operating results by
segment to our Consolidated Financial Statements.
In 2000, earnings from our other nonregulated businesses increased compared to
1999 mostly because of better market performance of certain of our financial
investments. In addition, in 1999, we wrote-down a financial investment, our
investment in a generating company in Bolivia, and certain senior-living
facilities, which had negative impacts in that year. These increases were offset
partially by lower earnings from our Latin American operation primarily due to
increased operating expenses in Guatemala.
In 1999, earnings from our other nonregulated businesses increased compared to
1998 mostly because of higher earnings from our Latin American and real estate
and senior-living facilities operations. This increase was offset partially by
lower earnings from our financial investments operation.
In 1999, earnings from our Latin American operation increased mostly because
of higher earnings from the electric distribution company in Panama compared to
1998. In October 1998, an investment group, in which subsidiaries of our Latin
American operation hold an 80% interest, purchased 51% of the Panamanian
company. This was offset partially by a $4.5 million after-tax write-down of our
investment in a generating company in Bolivia to reflect the current fair value
of this investment. This write-down was a result of our December 1999 decision
to exit the Latin American portion of our business as part of our strategy to
improve our competitive position.
In 1999, earnings from our real estate and senior-living facilities operation
increased compared to 1998 mostly because of:
. a $15.4 million after-tax write-down of its investment in Church Street
Station, an entertainment, dining, and retail complex in Orlando, Florida in
1998 that negatively impacted earnings that year, and
. an increase in earnings from its investment in Corporate Office Properties
Trust (COPT) in 1999. We discuss the investment in COPT in Note 3.
This increase was offset partially by a $5.8 million after-tax write-down of
certain senior-living facilities related to the proposed sale of these
facilities in 1999 as discussed below.
Additionally, in 1998, our energy products and services operation recorded a
$5.5 million after-tax write-off of an investment in, and certain of our product
inventory from, an automated electric distribution equipment company.
In 1999, our financial investments operation announced that it would exchange
its shares of common stock in Capital Re, an insurance company, for common stock
of ACE, another insurance company, as part of a business combination whereby ACE
would acquire all of the outstanding capital stock of Capital Re. As a result,
our financial investments operation wrote-down its $94.2 million investment in
Capital Re stock by $16.0 million after-tax to reflect the closing price of the
business combination. This write-down of Capital Re was offset partially by
better market performance of other financial investments in 1999 compared to
1998.
In 1999, our senior-living facilities operation entered into an agreement to
sell all but one of its senior-living facilities to Sunrise Assisted Living,
Inc. Under the terms of the agreement, Sunrise was to acquire twelve of our
existing senior-living facilities, three facilities under construction, and
several sites under development for $72.2 million in cash and $16.0 million in
debt assumption. We could not reach an agreement on financing issues that
subsequently arose, and the agreement was terminated in November 1999. As a
result, our senior-living facilities operation engaged a third-party management
company to manage its portfolio. However, our senior-living facilities operation
recorded a $5.8 million after-tax write-down related to the proposed sale.
Most of Constellation Real Estate Group's real estate and senior-living
projects are in the Baltimore-Washington corridor. The area has had a surplus of
available land in recent years and as a result these projects have been
economically hurt.
Constellation Real Estate's projects have continued to incur carrying costs
and depreciation over the years. Additionally, this operation has 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 and senior-living operations has not been enough to
make the monthly loan payments on some of these projects. Cash shortfalls have
been covered by cash obtained from the cash flows of, or additional borrowings
by, other nonregulated subsidiaries.
We consider market demand, interest rates, the availability of financing, and
the strength of the economy in general when making decisions about our real
estate and senior-living projects. If we were to decide to sell our projects, we
could have write-downs. In addition, if we were to sell our projects in the
current market, we would have losses which could be material, although the
amount of the losses is hard to predict. Depending on market conditions, we
could also have material losses on any future sales.
Our current real estate and senior-living strategy is to hold each project
until we can realize a reasonable value for it. Under accounting rules, we are
required to write down the value of a project 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.
Consolidated Nonoperating Income and Expenses
- --------------------------------------------
Fixed Charges
- -------------
In 2000, fixed charges increased $16.4 million compared to 1999 mostly because
we had more debt outstanding.
In 1999, fixed charges decreased $5.6 million compared to 1998 mostly because
we had less BGE preference stock outstanding.
Income Taxes
- ------------
In 2000, our total income taxes increased $43.7 million compared to 1999 mostly
because we had higher taxable income from our nonregulated businesses and an
increase in state and local taxes as a result of comprehensive changes to these
laws. This increase was offset partially by lower taxable income at BGE. We
discuss the comprehensive tax law changes in Note 4.
In 1999, income taxes increased $8.7 million compared to 1998 because we had
higher taxable income from both our regulated utility operations and our
nonregulated businesses.
FINANCIAL CONDITION
Cash Flows
2000 1999 1998
- ----------------------------------------------------------------------
(In millions)
Cash provided by (used in):
Operating activities $ 850.9 $ 679.0 $ 799.8
Investing activities (1,106.5) (615.1) (711.3)
Financing activities 345.6 (144.9) (77.4)
In 2000 and 1999, cash provided by operations changed compared to the
respective prior year mostly because of changes in working capital requirements.
In 2000, we used more cash for investing activities compared to 1999 mostly
due to substantial increases in our domestic merchant energy capital
expenditures to support our growth initiatives.
In 1999, we used less cash for investing activities compared to 1998 mostly
due to lower investments in Latin American power projects and in the real estate
and senior-living facilities operation. This was offset partially by a $97.7
million increase in the investment in Orion, an increase in our investment in
domestic power projects, and an increase in capital expenditures by our
regulated utility business.
In 2000, we had more cash from financing activities compared to 1999 mostly
because we issued more long-term debt and common stock. This was offset
partially by an increase in net maturities of short-term borrowings and we
repaid more long-term debt.
In 1999, we used more cash for financing activities compared to 1998 mostly
because we repaid more long-term debt and issued less long-term debt and common
stock. This was offset partially by a decrease in the redemption of BGE
preference stock and an increase in our net short-term borrowings.
Security Ratings
- ----------------
Independent credit-rating agencies rate Constellation Energy and BGE's fixed-
income securities. The ratings indicate the agencies' assessment of each
company's ability to pay interest, distributions, dividends, and principal on
these securities. These ratings affect how much it will cost each company to
sell these securities. The better the rating, the lower the cost of the
securities to each company when they sell them. Constellation Energy and BGE's
securities ratings at December 31, 2000 were:
Standard
& Poors Moody's
Rating Investors Fitch
Group Service IBCA
- ---------------------------------------------------------------------
Constellation Energy
- --------------------
Unsecured Debt A- A3 A-
BGE
- ---
Mortgage Bonds AA- A1 A+
Unsecured Debt A A2 A
Trust Originated Preferred
Securities and
Preference Stock A- "a2" A-
CAPITAL RESOURCES
Our business requires a great deal of capital. Our actual consolidated capital
requirements for the years 1998 through 2000, along with the estimated annual
amounts for the years 2001 through 2003, are shown in the table below.
We will continue to have cash requirements for:
. working capital needs including the payments of interest, distributions, and
dividends,
. capital expenditures, and
. the retirement of debt and redemption of preference stock.
Capital requirements for 2001 through 2003 include estimates of funding for
existing and anticipated projects. We continuously review and modify those
estimates. Actual requirements may vary from the estimates included in the table
below because of a number of factors including:
. regulation, legislation, and competition,
. BGE load requirements,
. environmental protection standards,
. the type and number of projects selected for development,
. the effect of market conditions on those projects,
. the cost and availability of capital, and
. the availability of cash from operations.
Our estimates are also subject to additional factors. Please see the Forward
Looking Statements section.
Effective July 1, 2000, all of BGE's generation assets were transferred to
nonregulated subsidiaries of Constellation Energy. The discussion and table for
capital requirements below include these generation assets as part of the
utility's regulated electric business through June 30, 2000. After that date,
the capital requirements are included in the domestic merchant energy business.
1998 1999 2000 2001 2002 2003
- -----------------------------------------------------------------------------------------------------------------
(In millions)
Nonregulated Capital Requirements:
Investment requirements:
Domestic merchant energy $ 318 $ 260 $ 801* $1,692 $ 928 $1,595
Other 7 18 29 50 79 105
- -----------------------------------------------------------------------------------------------------------------
Total investment requirements 325 278 830 1,742 1,007 1,700
Retirement of long-term debt 232 189 295 406** 215 200
- -----------------------------------------------------------------------------------------------------------------
Total nonregulated capital requirements 557 467 1,125 2,148 1,222 1,900
Utility Capital Requirements:
Capital expenditures:
Regulated electric
Generation (including nuclear fuel) 154 170 95 -- -- --
Transmission and distribution 161 173 170 174 171 173
- -----------------------------------------------------------------------------------------------------------------
Total regulated electric 315 343 265 174 171 173
Regulated gas 55 59 55 53 52 52
Common 35 34 30 32 26 20
- -----------------------------------------------------------------------------------------------------------------
Total capital expenditures 405 436 350 259 249 245
Retirement of long-term debt and redemption
of preference stock 222 342 402 394 320 286
- -----------------------------------------------------------------------------------------------------------------
Total utility capital requirements 627 778 752 653 569 531
- -----------------------------------------------------------------------------------------------------------------
Total capital requirements $1,184 $1,245 $1,877 $2,801 $1,791 $2,431
=================================================================================================================
*Effective July 1, 2000, includes $110.6 million for electric generation and
nuclear fuel formerly part of BGE's regulated electric business.
**Amount does not include $1.2 billion in Constellation Energy debt that would
be redeemed at or prior to business separation.
Capital Requirements
- --------------------
Domestic Merchant Energy Business
- ---------------------------------
Our domestic merchant energy business will require additional funding for
growing its power marketing operation and developing and acquiring power
projects.
Our domestic merchant energy business investment requirements include the
planned purchase of the Nine Mile Point nuclear power plant for $815 million,
including fuel, and the planned construction of 1,100 megawatts of peaking
capacity in the Mid-Atlantic and Mid-West regions by the summer of 2001. An
additional 6,700 megawatts of peaking and combined cycle production facilities
are scheduled for completion in 2002 and beyond in the Mid-West and South
regions. Longer range, our plans are to control approximately 30,000 megawatts
of generation capacity by 2005. For further information see the Strategy
section.
Electric Generation
- -------------------
Electric construction expenditures for our regulated electric business include
improvements to generating plants and costs for replacing the steam generators
at Calvert Cliffs through June 30, 2000. Thereafter, these expenditures are
reflected in our domestic merchant energy business.
In March 2000, we received the license extension from the Nuclear Regulatory
Commission (NRC) that extends our operating licenses at Calvert Cliffs to 2034
for Unit 1 and 2036 for Unit 2. If we do not replace the steam generators, we
will not be able to operate these units through our operating license periods.
We expect the steam generator replacement to occur during the 2002 refueling
outage for Unit 1 and during the 2003 refueling outage for Unit 2. We estimate
these Calvert Cliffs' costs to be:
. $ 63 million in 2001,
. $ 91 million in 2002, and
. $ 60 million in 2003.
Additionally, our estimates of future electric generation construction
expenditures include the costs of complying with Environmental Protection Agency
(EPA) and State of Maryland nitrogen oxides emissions (NOx) reduction
regulations as follows:
. $ 71 million in 2001, and
. $ 20 million in 2002.
We discuss the NOx regulations and timing of expenditures in Note 10.
Regulated Electric Transmission and Distribution and Gas
- --------------------------------------------------------
Regulated electric transmission and distribution and gas construction
expenditures primarily include new business construction needs and improvements
to existing facilities.
Funding for Capital Requirements
- --------------------------------
On October 23, 2000, we announced initiatives designed to advance our growth
strategies in the domestic merchant energy business and a change in our common
stock dividend policy effective April 2001, as discussed in the Strategy
section.
As part of these initiatives, we expect to redeem all of the outstanding debt
at Constellation Energy at or prior to the separation of our domestic merchant
energy business and remaining businesses. The redemption will occur through a
combination of open market purchases, tender offers, and redemption calls. We
expect to fund this redemption with short-term debt or other credit facilities,
and to refinance this debt longer term after the separation.
Domestic Merchant Energy Business
- ---------------------------------
Funding for the expansion of our domestic merchant energy business is expected
from internally generated funds, commercial paper, long-term debt, equity,
leases, and other financing instruments issued by Constellation Energy and its
subsidiaries. Specifically related to the Nine Mile Point acquisition, one-half
of the purchase price, or $407.5 million, is due at the closing of the
transaction and the remainder is being financed through the sellers in a note to
be repaid over five years with an interest rate of 11.0%. We expect to close the
transaction with funds from available sources at that time. Payments on the note
over the five years are expected to come from internally generated funds. Longer
term, we expect to fund our growth and operating objectives with a mixture of
debt and equity with an overall goal of maintaining an investment grade credit
profile.
When our domestic merchant energy business separates from our remaining
businesses, it initially expects to reinvest its earnings to fund its growth and
not to pay a dividend.
Constellation Energy has a commercial paper program where it can issue up to
$500 million in short-term notes to fund its nonregulated businesses. To support
its commercial paper program, Constellation Energy maintains two revolving
credit agreements totaling $565 million, of which one facility can also issue
letters of credit. In addition, Constellation Energy has access to interim lines
of credit as required from time to time to support its outstanding commercial
paper.
BGE
- ---
Funding for utility capital expenditures is expected from internally generated
funds, commercial paper issuances, available capacity under credit facilities,
the issuance of long-term debt, trust securities, or preference stock, and/or
from time to time equity contributions from Constellation Energy.
At December 31, 2000, FERC authorized BGE to issue up to $700 million of
short-term borrowings, including commercial paper. In addition, BGE maintains
$193 million in annual committed bank lines of credit and has $25 million in
bank revolving credit agreements to support the commercial paper
program. In addition, BGE has access to interim lines of credit as required from
time to time to support its outstanding commercial paper.
During the three years from 2001 through 2003, we expect our regulated utility
business to provide at least 110% of the cash needed to meet the capital
requirements for its operations, excluding cash needed to retire debt.
Other Nonregulated Businesses
- -----------------------------
BGE Home Products & Services may meet capital requirements through sales of
receivables. ComfortLink has a revolving credit agreement totaling $50 million
to provide liquidity for short-term financial needs.
If we can get a reasonable value for our real estate projects, senior-living
facilities, Latin American operation, and other investments, additional cash may
be obtained by selling them. Our ability to sell or liquidate assets will depend
on market conditions, and we cannot give assurances that these sales or
liquidations could be made. We discuss the real estate and senior-living
facilities operation and market conditions in the Other Nonregulated Businesses
section.
We discuss our short-term borrowings in Note 7 and long-term debt in Note 8.
MARKET RISK
We are exposed to market risk, including changes in interest rates, certain
commodity prices, equity prices, and foreign currency. To manage our market
risk, we may enter into various derivative instruments including swaps, forward
contracts, futures contracts, and options. Effective July 1, 2000, we are
subject to additional market risk associated with the purchase and sale of
energy as discussed in the Current Issues section. We discuss our market risk
further in Note 1. In this section, we discuss our current market risk and the
related use of derivative instruments.
Interest Rate Risk
- ------------------
We are exposed to changes in interest rates as a result of financing through our
issuance of variable-rate and fixed-rate debt. The following table provides
information about our obligations that are sensitive to interest rate changes:
Principal Payments and Interest Rate Detail by Contractual Maturity Date
Fair value at
2001 2002 2003 2004 2005 Thereafter Total Dec. 31, 2000
- -----------------------------------------------------------------------------------------------------------------------------
(Dollar amounts in millions)
Long-term debt
- --------------
Variable-rate debt $317.6 $208.0 $200.2 $ 7.6 $ 5.4 $ 593.0 $1,331.8 $1,243.3
Average interest rate 6.97% 7.30% 7.26% 8.42% 8.62% 5.99% 6.64%
Fixed-rate debt $482.5 $327.1 $286.3 $156.0 $347.6 $1,140.0 $2,739.5 $2,819.9
Average interest rate 7.08% 7.01% 6.50% 5.80% 7.72% 6.85% 6.92%
Commodity Price Risk
- --------------------
We are exposed to the impact of market fluctuations in the price and
transportation costs of electricity, natural gas, and other commodities.
Domestic Merchant Energy Business
- ---------------------------------
Our domestic merchant energy business is exposed to market risk from the power
marketing operation of Constellation Power Source and from our electric
generation operations. Constellation Power Source manages the commodity price
risk inherent in its power marketing activities on a portfolio basis, subject to
established trading and risk management policies. Commodity price risk arises
from the potential for changes in the value of energy commodities and related
derivatives due to: changes in commodity prices, volatility of commodity prices,
and fluctuations in interest rates. A number of factors associated with the
structure and operation of the electricity market significantly influence the
level and volatility of prices for energy commodities and related derivative
products. These factors include:
. seasonal changes in demand,
. hourly fluctuations in demand due to weather conditions,
. available supply resources,
. transportation availability and reliability within and between regions,
. procedures used to maintain the integrity of the physical electricity system
during extreme conditions, and
. changes in the nature and extent of federal and state regulations.
These factors can affect energy commodity and derivative prices in different
ways and to different degrees. These effects may vary throughout the country as
a result of regional differences in:
. weather conditions,
. market liquidity,
. capability and reliability of the physical electricity and gas systems, and
. the nature and extent of electricity deregulation.
Constellation Power Source uses various methods, including a value at risk
model, to measure its exposure to market risk. Value at risk is a statistical
model that attempts to predict risk of loss based on historical market price and
volatility data. Constellation Power Source calculates value at risk using a
variance/covariance technique that models option positions using a linear
approximation of their value. Additionally, Constellation Power Source estimates
variances and correlation using historical market movements over the most recent
rolling three-month period.
The value at risk amount represents the potential loss in the fair value of
assets and liabilities from trading activities over a one-day holding period
with a 99.6% confidence level. Using this confidence level, Constellation Power
Source would expect a one-day change in fair value greater than or equal to the
daily value at risk at least once per year. Constellation Power Source's value
at risk was $13.7 million as of December 31, 2000 compared to $7.2 million as of
December 31, 1999. The average, high, and low value at risk for the year ended
December 31, 2000 was $13.1 million, $24.3 million, and $6.3 million,
respectively.
Constellation Power Source's value at risk calculation includes all assets and
liabilities from its power marketing and trading activities, including energy
commodities and derivatives that do not require cash settlements. We believe
that this represents a more complete calculation of our value at risk.
Due to the inherent limitations of statistical measures such as value at risk,
the relative immaturity of the competitive market for electricity and related
derivatives, and the seasonality of changes in market prices, the value at risk
calculation may not reflect the full extent of our commodity price risk
exposure. Additionally, actual changes in the value of options may differ from
the value at risk calculated using a linear approximation inherent in our
calculation method. As a result, actual changes in the fair value of assets and
liabilities from power marketing and trading activities could differ from the
calculated value at risk, and such changes could have a material impact on our
financial results. Please refer to the Forward Looking Statements section.
We discuss Constellation Power Source's operation in the Domestic Merchant
Energy Business section and in Note 1.
Our domestic merchant energy business conducts electric generation operations
primarily through Constellation Power Source Generation, Calvert Cliffs, and
Constellation Power. Presently, the majority of the generating capacity
controlled by our domestic merchant energy business is used to provide standard
offer service to BGE. However, beginning in July 2002, we expect approximately
1,000 megawatts of industrial customer load will leave standard offer service.
The remainder of the standard offer service arrangement with BGE terminates on
June 30, 2003. Additionally, we plan to expand our generation operations as
discussed in the Strategy section.
As a result, our domestic merchant energy business has a substantial and
increasing amount of generating capacity that is subject to future changes in
wholesale electricity prices and has fuel requirements that are subject to
future changes in coal, natural gas, and oil prices. Additionally, if one or
more of our generating facilities is not able to produce electricity when
required due to operational factors, we may have to forego sales opportunities
or fulfill fixed price sale commitments through the operation of other more
costly generating facilities or through the purchase of energy in the wholesale
market at higher prices.
Constellation Power Source manages the commodity price risk of our electric
generation operations as part of its overall portfolio. Additionally, the
domestic merchant energy business may enter into fixed-price contracts to hedge
a portion of its exposure to future electricity and fuel commodity price risk.
Regulated Electric Business
- ---------------------------
The standard offer service arrangement between BGE and Constellation Power
Source ends June 30, 2003. Under the Restructuring Order, effective July 1,
2000, BGE's residential rates are frozen for a six-year period and its
commercial and industrial rates are frozen for four to six years. As a result,
BGE will be subject to commodity price risk beginning July 1, 2003 upon
termination of the existing standard offer arrangement. In accordance with the
Restructuring Order, BGE will competitively bid the standard offer service
supply for the remaining period of the rate freeze subsequent to June 30, 2003.
During the remaining period of BGE's rate freeze, BGE will be unable to pass
through to its customers any increase in the market price of electricity it must
purchase to meet the standard offer service load. Our regulated electric
business is evaluating various alternatives to minimize the market risk after
June 30, 2003.
Regulated Gas Business
- ----------------------
Our regulated gas business may enter into gas futures, options, and swaps to
hedge its price risk under our market based rate incentive mechanism and our
off-system gas sales program. We discuss this further in Note 1. At December 31,
2000 and 1999, our exposure to commodity price risk for our regulated gas
business was not material.
Credit Risk
- -----------
We are exposed to credit risk, primarily through Constellation Power Source.
Credit risk is the loss that may result from a counterparty's nonperformance.
Constellation Power Source uses credit policies to control its credit risk,
including utilizing an established credit approval process, monitoring
counterparty limits, employing credit mitigation measures such as margin,
collateral or prepayment arrangements, and using master netting agreements.
However, due to the possibility of extreme volatility in the prices of
electricity commodities and derivatives, the market value of contractual
positions with individual counterparties could exceed established credit limits
or collateral provided by those counterparties. If such a counterparty were then
to fail to perform its obligations under its contract (for example, fail to
deliver the electricity Constellation Power Source had contracted for),
Constellation Power Source could sustain a loss that could have a material
impact on our financial results.
Our domestic merchant energy business sells electricity to two California
investor-owned utilities under long-term power purchase agreements that recently
were downgraded by rating agencies to below investment grade. We discuss the
credit and other exposures under these agreements in the Current Issues section.
Equity Price Risk
- -----------------
We are exposed to price fluctuations in equity markets primarily through our
financial investments operation and our nuclear decommissioning trust fund. We
are required by the NRC to maintain a trust to fund the costs of decommissioning
Calvert Cliffs. We believe our exposure to fluctuations in equity prices will
not have a material impact on our financial results. We discuss our nuclear
decommissioning trust fund in more detail in Note 1. We also describe our
financial investments in more detail in Note 3.
Foreign Currency Risk
- ---------------------
We are exposed to foreign currency risk primarily through our Latin American
operation. Our Latin American operation has $255.9 million invested in
international power generation and distribution projects as of December 31,
2000. To manage our exposure to foreign currency risk, the majority of our
contracts are denominated in or indexed to the U.S. dollar. At December 31, 2000
and 1999, foreign currency risk was not material. We discuss our international
projects in the Other Nonregulated Businesses section.
FORWARD LOOKING STATEMENTS
We make statements in this report that are considered forward looking statements
within the meaning of the Securities Exchange Act of 1934. Sometimes these
statements will contain words such as "believes," "expects," "intends," "plans,"
and other similar words. These statements are not guarantees of our future
performance and are subject to risks, uncertainties and other important factors
that could cause our actual performance or achievements to be materially
different from those we project. These risks, uncertainties, and factors
include, but are not limited to:
. satisfaction of all the conditions precedent to the closing on the purchase
of the Nine Mile Point nuclear power plant, including obtaining all
regulatory approvals,
. obtaining all regulatory approvals necessary to close on the investment by
an affiliate of Goldman Sachs in our domestic merchant energy business and
complete the separation of our domestic merchant energy business from our
remaining businesses,
. satisfaction of all conditions precedent to the transaction with Goldman
Sachs,
. general economic, business, and regulatory conditions,
. the pace and nature of deregulation nationwide (including the status of the
California markets),
. energy supply and demand,
. competition,
. federal and state regulations,
. availability, terms, and use of capital,
. nuclear and environmental issues,
. weather,
. implications of the Restructuring Order issued by the Maryland PSC,
including the outcome of the appeal,
. commodity price risk,
. operating our generation assets in a deregulated market without the benefit
of a fuel rate adjustment clause,
. loss of revenue due to customers choosing alternative suppliers,
. higher volatility of earnings and cash flows,
. increased financial requirements of our nonregulated subsidiaries,
. inability to recover all costs associated with providing electric retail
customers service during the electric rate freeze period, and
. implications from the transfer of BGE's generation assets and related
liabilities to nonregulated subsidiaries of Constellation Energy, including
the outcome of the appeal of the Maryland PSC's Order regarding the transfer
of generation assets.
Given these uncertainties, you should not place undue reliance on these
forward looking statements. Please see the other sections of this report and our
other periodic reports filed with the SEC for more information on these factors.
These forward looking statements represent our estimates and assumptions only as
of the date of this report.
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 accounting principles generally accepted
in the United States of America 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.
PricewaterhouseCoopers LLP, independent accountants, audit the financial
statements and express their opinion on them. They perform their audit in
accordance with auditing standards generally accepted in the United States of
America.
The Audit Committee of the Board of Directors, which consists of four outside
Directors, meets periodically with management, internal auditors, and
PricewaterhouseCoopers LLP to review the activities of each in discharging their
responsibilities. The internal audit staff and PricewaterhouseCoopers LLP have
free access to the Audit Committee.
/s/ Christian H. Poindexter /s/ David A. Brune
- ------------------------------- ------------------
Christian H. Poindexter David A. Brune
Chairman of the Board Chief Financial Officer
and Chief Executive Officer
REPORT OF INDEPENDENT ACCOUNTANTS
To the Shareholders of Constellation Energy Group, Inc.
In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of income, comprehensive income, cash flows, common
shareholders' equity, capitalization and income taxes present fairly, in all
material respects, the financial position of Constellation Energy Group, Inc.
and Subsidiaries at December 31, 2000 and 1999, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2000 in conformity with accounting principles generally accepted in
the United States of America. 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 of these
statements in accordance with auditing standards generally accepted in the
United States of America, which 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, assessing
the accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for the opinion expressed above.
/s/ PricewaterhouseCoopers LLP
- ------------------------------
PricewaterhouseCoopers LLP
Baltimore, Maryland
January 17, 2001
CONSOLIDATED STATEMENTS OF INCOME -- CONSTELLATION ENERGY GROUP INC. AND SUBSIDIARIES
Year Ended December 31, 2000 1999 1998
- -------------------------------------------------------------------------------------------------------
(In millions, except per share amounts)
Revenues
Nonregulated revenues $1,140.0 $1,050.9 $ 717.8
Regulated electric revenues 2,134.7 2,258.8 2,219.2
Regulated gas revenues 603.8 476.5 449.4
- -------------------------------------------------------------------------------------------------------
Total revenues 3,878.5 3,786.2 3,386.4
Expenses
Operating expenses 2,347.3 2,349.2 2,053.0
Depreciation and amortization 470.0 449.8 375.5
Taxes other than income taxes 221.0 227.3 219.4
- -------------------------------------------------------------------------------------------------------
Total expenses 3,038.3 3,026.3 2,647.9
- -------------------------------------------------------------------------------------------------------
Income from Operations 840.2 759.9 738.5
Other Income 6.6 7.9 5.7
- -------------------------------------------------------------------------------------------------------
Income Before Fixed Charges and Income Taxes 846.8 767.8 744.2
Fixed Charges
Interest expense (net) 258.2 241.5 238.8
BGE preference stock dividends 13.2 13.5 21.8
- -------------------------------------------------------------------------------------------------------
Total fixed charges 271.4 255.0 260.6
- -------------------------------------------------------------------------------------------------------
Income Before Income Taxes 575.4 512.8 483.6
Income Taxes 230.1 186.4 177.7
- -------------------------------------------------------------------------------------------------------
Income Before Extraordinary Item 345.3 326.4 305.9
Extraordinary Loss, Net of Income Taxes of $30.4 (see Note 4) -- (66.3) --
- -------------------------------------------------------------------------------------------------------
Net Income $ 345.3 $ 260.1 $ 305.9
=======================================================================================================
Earnings Applicable to Common Stock $ 345.3 $ 260.1 $ 305.9
=======================================================================================================
Average Shares of Common Stock Outstanding 150.0 149.6 148.5
Earnings Per Common Share and Earnings Per Common Share--
Assuming Dilution Before Extraordinary Item $ 2.30 $ 2.18 $ 2.06
Extraordinary Loss -- (.44) --
- -------------------------------------------------------------------------------------------------------
Earnings Per Common Share and
Earnings Per Common Share--Assuming Dilution $ 2.30 $ 1.74 $ 2.06
=======================================================================================================
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME -- CONSTELLATION ENERGY GROUP INC. AND SUBSIDIARIES
Year Ended December 31, 2000 1999 1998
- -------------------------------------------------------------------------------------------------------
(In millions)
Net Income $345.3 $260.1 $305.9
Other comprehensive income/(loss), net of taxes 22.1 (6.2) 1.2
- -------------------------------------------------------------------------------------------------------
Comprehensive Income $367.4 $253.9 $307.1
=======================================================================================================
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
CONSOLIDATED BALANCE SHEETS -- CONSTELLATION ENERGY GROUP INC. AND SUBSIDIARIES
At December 31, 2000 1999
- -----------------------------------------------------------------------------------------
(In millions)
Assets
Current Assets
Cash and cash equivalents $ 182.7 $ 92.7
Accounts receivable (net of allowance for uncollectibles
of $21.3 and $34.8, respectively) 738.5 578.5
Trading securities 189.3 136.5
Assets from energy trading activities 2,056.5 312.1
Fuel stocks 78.2 94.9
Materials and supplies 151.3 149.1
Prepaid taxes other than income taxes 73.5 72.4
Other 32.7 54.0
- -----------------------------------------------------------------------------------------
Total current assets 3,502.7 1,490.2
- -----------------------------------------------------------------------------------------
Investments and Other Assets
Real estate projects and investments 290.3 310.1
Investments in power projects 517.5 513.9
Financial investments 161.0 145.4
Nuclear decommissioning trust fund 228.7 217.9
Net pension asset 93.2 99.5
Investment in Orion Power Holdings, Inc. 192.0 105.7
Other 123.0 154.3
- -----------------------------------------------------------------------------------------
Total investments and other assets 1,605.7 1,546.8
- -----------------------------------------------------------------------------------------
Property, Plant and Equipment
Regulated property, plant and equipment
Plant in service 4,780.3 8,620.1
Construction work in progress 75.3 222.3
Plant held for future use 4.5 13.0
- -----------------------------------------------------------------------------------------
Total regulated property, plant and equipment 4,860.1 8,855.4
Nonregulated generation property, plant and equipment 5,279.9 374.7
Other nonregulated property, plant and equipment 173.8 152.7
Nuclear fuel (net of amortization) 128.3 133.8
Accumulated depreciation (3,798.1) (3,559.1)
- -----------------------------------------------------------------------------------------
Net property, plant and equipment 6,644.0 5,957.5
- -----------------------------------------------------------------------------------------
Deferred Charges
Regulatory assets (net) 514.9 637.4
Other 117.3 51.9
- -----------------------------------------------------------------------------------------
Total deferred charges 632.2 689.3
- -----------------------------------------------------------------------------------------
Total Assets $12,384.6 $ 9,683.8
=========================================================================================
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
CONSOLIDATED BALANCE SHEETS--CONSTELLATION ENERGY GROUP INC. AND SUBSIDIARIES
At December 31, 2000 1999
- ---------------------------------------------------------------------
(In millions)
Liabilities and Capitalization
Current Liabilities
Short-term borrowings $ 243.6 $ 371.5
Current portion of long-term debt 906.6 808.3
Accounts payable 695.9 365.1
Liabilities from energy trading activities 1,586.8 163.8
Dividends declared 66.5 66.1
Accrued taxes 38.2 19.2
Other 212.6 209.4
- ---------------------------------------------------------------------
Total current liabilities 3,750.2 2,003.4
- ---------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred income taxes 1,339.5 1,288.8
Postretirement and postemployment benefits 265.2 269.8
Deferred investment tax credits 101.4 109.6
Other 426.0 253.8
- ---------------------------------------------------------------------
Total deferred credits and other liabilities 2,132.1 1,922.0
- ---------------------------------------------------------------------
Capitalization
Long-term debt 3,159.3 2,575.4
BGE preference stock not subject to mandatory
redemption 190.0 190.0
Common shareholders' equity 3,153.0 2,993.0
- ---------------------------------------------------------------------
Total capitalization 6,502.3 5,758.4
- ---------------------------------------------------------------------
Commitments, Guarantees, and Contingencies (see Note 10)
Total Liabilities and Capitalization $12,384.6 $9,683.8
=====================================================================
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
CONSOLIDATED STATEMENTS OF CASH FLOWS--CONSTELLATION ENERGY GROUP INC. AND
SUBSIDIARIES
Year Ended December 31, 2000 1999 1998
- -----------------------------------------------------------------------------------------------------------------
(In millions)
Cash Flows From Operating Activities
Net income $ 345.3 $ 260.1 $ 305.9
Adjustments to reconcile to net cash provided by operating activities
Extraordinary loss -- 66.3 --
Depreciation and amortization 524.8 505.9 427.8
Deferred income taxes 42.0 13.0 17.5
Investment tax credit adjustments (8.3) (8.6) (8.8)
Deferred fuel costs 2.8 (61.1) (8.3)
Accrued pension and postemployment benefits 27.9 36.1 41.6
Gain on sale of subsidiaries (13.3) -- --
Gain on sale of Orion Power Holdings, Inc. stock (19.2) -- --
Deregulation transition cost 24.0 -- --
Write-downs of real estate investments -- 9.6 23.7
Write-down of financial investment -- 26.2 --
Write-downs of power projects -- 28.5 --
Equity in earnings of affiliates and joint ventures (net) (5.3) (7.6) (54.5)
Changes in assets from energy trading activities (1,744.4) (179.1) (123.6)
Changes in liabilities from energy trading activities 1,423.0 64.8 90.4
Changes in other current assets (176.6) (216.4) 18.3
Changes in other current liabilities 352.1 121.0 77.0
Other 76.1 20.3 (7.2)
- -----------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 850.9 679.0 799.8
- -----------------------------------------------------------------------------------------------------------------
Cash Flows From Investing Activities
Purchases of property, plant and equipment and
other capital expenditures (1,079.0) (616.5) (730.2)
Investment in Orion (101.5) (97.7) --
Contributions to nuclear decommissioning trust fund (13.2) (17.6) (17.6)
Purchases of marketable equity securities (80.8) (27.3) (33.3)
Sales of marketable equity securities 110.2 34.9 32.8
Other investments 57.8 109.1 37.0
- -----------------------------------------------------------------------------------------------------------------
Net cash used in investing activities (1,106.5) (615.1) (711.3)
- -----------------------------------------------------------------------------------------------------------------
Cash Flows From Financing Activities
Net (maturity) issuance of short-term borrowings (127.9) 371.5 (316.1)
Proceeds from issuance of
Long-term debt 1,374.0 302.8 831.3
Common stock 35.9 9.6 51.8
Reacquisition of long-term debt (697.0) (584.4) (355.2)
Redemption of preference stock -- (7.0) (127.9)
Common stock dividends paid (250.7) (251.1) (246.0)
Other 11.3 13.7 84.7
- -----------------------------------------------------------------------------------------------------------------
Net cash provided by (used in) financing activities 345.6 (144.9) (77.4)
- -----------------------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents 90.0 (81.0) 11.1
Cash and Cash Equivalents at Beginning of Year 92.7 173.7 162.6
- -----------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 182.7 $ 92.7 $ 173.7
=================================================================================================================
Other Cash Flow Information
Cash paid during the year for:
Interest (net of amounts capitalized) $ 268.2 $ 245.3 $ 236.7
Income taxes $ 184.7 $ 165.6 $ 164.3
Noncash Investing and Financing Activities:
In 1998, Corporate Office Properties Trust (COPT) assumed approximately $62
million of Constellation Real Estate Group's (CREG) debt and issued to CREG 7.0
million common shares and 985,000 convertible preferred shares. In exchange,
COPT received 14 operating properties and two properties under development from
CREG.
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY--CONSTELLATION ENERGY
GROUP INC. AND SUBSIDIARIES
Accumulated
Other
Common Stock Retained Comprehensive Total
Years Ended December 31, 2000, 1999, and 1998 Shares Amount Earnings Income Amount
- -----------------------------------------------------------------------------------------------------------
(Dollar amounts in millions, number of shares in thousands)
Balance at December 31, 1997 147,667 $1,433.0 $1,432.5 $ 4.9 $2,870.4
Net income 305.9 305.9
Common stock dividend declared ($1.67 per share) (248.1) (248.1)
Common stock issued 1,579 51.8 51.8
Other 0.3 0.3
Net unrealized gain on securities 1.8 1.8
Deferred taxes on net unrealized gain on securities (0.6) (0.6)
- -----------------------------------------------------------------------------------------------------------
Balance at December 31, 1998 149,246 1,485.1 1,490.3 6.1 2,981.5
Net income 260.1 260.1
Common stock dividend declared ($1.68 per share) (251.3) (251.3)
Common stock issued 310 9.6 9.6
Other (0.7) (0.7)
Net unrealized loss on securities (9.6) (9.6)
Deferred taxes on net unrealized loss on securities 3.4 3.4
- -----------------------------------------------------------------------------------------------------------
Balance at December 31, 1999 149,556 1,494.0 1,499.1 (0.1) 2,993.0
Net income 345.3 345.3
Common stock dividend declared ($1.68 per share) (251.8) (251.8)
Common stock issued 976 35.9 35.9
Other 8.8 (0.3) 8.5
Net unrealized gain on securities 33.9 33.9
Deferred taxes on net unrealized gain on securities (11.8) (11.8)
- -----------------------------------------------------------------------------------------------------------
Balance at December 31, 2000 150,532 $1,538.7 $1,592.3 $22.0 $3,153.0
===========================================================================================================
See Notes to Consolidated Financial Statements.
CONSOLIDATED STATEMENTS OF CAPITALIZATION -- CONSTELLATION ENERGY GROUP INC. AND
SUBSIDIARIES
At December 31, 2000 1999
- ---------------------------------------------------------------------------------------------------------------------------
(In millions)
Long-Term Debt
Long-term debt of Constellation Energy
7 7/8% Notes, due April 1, 2005 $ 300.0 $ --
Floating rate notes, due April 4, 2003 200.0 --
Extendible notes, due June 21, 2010 300.0 --
Floating rate reset notes, due March 15, 2002 200.0 --
- ---------------------------------------------------------------------------------------------------------------------------
Total long-term debt of Constellation Energy 1,000.0 --
- ---------------------------------------------------------------------------------------------------------------------------
Long-term debt of nonregulated businesses
Tax-exempt debt transferred from BGE effective July 1, 2000
Pollution control loan, due July 1, 2011 36.0 --
Port facilities loan, due June 1, 2013 48.0 --
Adjustable rate pollution control loan, due July 1, 2014 20.0 --
5.55% Pollution control revenue refunding loan, due July 15, 2014 47.0 --
Economic development loan, due December 1, 2018 35.0 --
6.00% Pollution control revenue refunding loan, due April 1, 2024 75.0 --
Floating rate pollution control loan, due June 1, 2027 8.8 --
5 1/2% Installment series, due July 15, 2002 7.6 --
Loan under revolving credit agreement 34.0 33.0
Mortgage and construction loans
Floating rate mortgage notes and construction loans, due through 2005 51.3 112.0
Other mortgage notes ranging from 4.25% to 9.65% due July 31, 2001 to November 1, 2033 20.3 30.8
Unsecured notes 287.0 511.0
- ---------------------------------------------------------------------------------------------------------------------------
Total long-term debt of nonregulated businesses 670.0 686.8
- ---------------------------------------------------------------------------------------------------------------------------
First Refunding Mortgage Bonds of BGE
5 1/2% Series, due July 15, 2000 transferred to nonregulated businesses effective July 1, 2000 -- 124.3
8 3/8% Series, due August 15, 2001 122.2 122.3
7 1/4% Series, due July 1, 2002 124.0 124.5
6 1/2% Series, due February 15, 2003 124.8 124.8
6 1/8% Series, due July 1, 2003 124.9 124.9
5 1/2% Series, due April 15, 2004 125.0 125.0
Remarketed floating rate series, due September 1, 2006 111.5 125.0
7 1/2% Series, due January 15, 2007 123.5 123.5
6 5/8% Series, due March 15, 2008 124.9 124.9
7 1/2% Series, due March 1, 2023 109.9 109.9
7 1/2% Series, due April 15, 2023 84.0 84.1
Tax-exempt debt transferred to nonregulated businesses effective July 1, 2000 -- 8.5
- ---------------------------------------------------------------------------------------------------------------------------
Total First Refunding Mortgage Bonds of BGE 1,174.7 1,321.7
- ---------------------------------------------------------------------------------------------------------------------------
Other long-term debt of BGE
Floating rate reset notes, due October 19, 2001 200.0 --
Medium-term notes, Series B 23.1 60.0
Medium-term notes, Series C 25.5 101.0
Medium-term notes, Series D 128.0 128.0
Medium-term notes, Series E 200.0 200.0
Medium-term notes, Series G 200.0 200.0
Medium-term notes, Series H 27.0 177.0
6.75% Remarketable or redeemable securities, due December 15, 2012 173.0 --
Tax-exempt debt transferred to nonregulated businesses effective July 1, 2000 -- 269.8
- ---------------------------------------------------------------------------------------------------------------------------
Total other long-term debt of BGE 976.6 1,135.8
- ---------------------------------------------------------------------------------------------------------------------------
BGE obligated mandatorily redeemable trust preferred securities of subsidiary
trust holding solely 7.16% debentures of BGE due June 30, 2038 250.0 250.0
Unamortized discount and premium (5.4) (10.6)
Current portion of long-term debt (906.6) (808.3)
- ---------------------------------------------------------------------------------------------------------------------------
Total long-term debt $3,159.3 $2,575.4
- ---------------------------------------------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
continued on next page
CONSOLIDATED STATEMENTS OF CAPITALIZATION -- CONSTELLATION ENERGY GROUP INC. AND
SUBSIDIARIES
At December 31, 2000 1999
- ----------------------------------------------------------------------------------------------------------------------
(In millions)
BGE Preference Stock
Cumulative preference stock not subject to mandatory redemption, 6,500,000 shares authorized
7.125%, 1993 Series, 400,000 shares outstanding, not callable prior to July 1, 2003 $ 40.0 $ 40.0
6.97%, 1993 Series, 500,000 shares outstanding, not callable prior to October 1, 2003 50.0 50.0
6.70%, 1993 Series, 400,000 shares outstanding, not callable prior to January 1, 2004 40.0 40.0
6.99%, 1995 Series, 600,000 shares outstanding, not callable prior to October 1, 2005 60.0 60.0
- ----------------------------------------------------------------------------------------------------------------------
Total preference stock not subject to mandatory redemption 190.0 190.0
- ----------------------------------------------------------------------------------------------------------------------
Common Shareholders' Equity
Common stock without par value, 250,000,000 shares authorized; 150,531,716 and
149,556,416 shares issued and outstanding at December 31, 2000 and
1999, respectively. (At December 31, 2000 166,893 shares were reserved
for the Employee Savings Plan and 12,061,756 shares were reserved for the
Shareholder Investment Plan.) 1,538.7 1,494.0
Retained earnings 1,592.3 1,499.1
Accumulated other comprehensive income (loss) 22.0 (0.1)
- ----------------------------------------------------------------------------------------------------------------------
Total common shareholders' equity 3,153.0 2,993.0
- ----------------------------------------------------------------------------------------------------------------------
Total Capitalization $6,502.3 $5,758.4
======================================================================================================================
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
CONSOLIDATED STATEMENTS OF INCOME TAXES -- CONSTELLATION ENERGY GROUP INC. AND
SUBSIDIARIES
Year Ended December 31, 2000 1999 1998
- -------------------------------------------------------------------------------------------------------------
(Dollar amounts in millions)
Income Taxes
Current $ 196.4 $ 182.0 $ 169.0
- -------------------------------------------------------------------------------------------------------------
Deferred
Change in tax effect of temporary differences 50.4 9.6 14.2
Change in income taxes recoverable through future rates 3.4 -- 3.9
Deferred taxes credited (charged) to shareholders' equity (11.8) 3.4 (0.6)
- -------------------------------------------------------------------------------------------------------------
Deferred taxes charged to expense 42.0 13.0 17.5
Investment tax credit adjustments (8.3) (8.6) (8.8)
- -------------------------------------------------------------------------------------------------------------
Income taxes per Consolidated Statements of Income $ 230.1 $ 186.4 $ 177.7
=============================================================================================================
Reconciliation of Income Taxes Computed at Statutory
Federal Rate to Total Income Taxes
Income before income taxes (excluding BGE preference stock dividends) $ 588.6 $ 526.3 $ 505.4
Statutory federal income tax rate 35% 35% 35%
- -------------------------------------------------------------------------------------------------------------
Income taxes computed at statutory federal rate 206.0 184.2 176.9
Increases (decreases) in income taxes due to
Depreciation differences not normalized on regulated activities 12.6 15.3 13.6
Allowance for equity funds used during construction (0.9) (2.2) (2.2)
Amortization of deferred investment tax credits (8.3) (8.6) (8.8)
Tax credits flowed through to income (6.5) (3.2) (0.3)
Amortization of deferred tax rate differential on regulated activities (2.9) (3.0) (2.3)
State income taxes 34.0 8.9 9.8
Other (3.9) (5.0) (9.0)
- -------------------------------------------------------------------------------------------------------------
Total income taxes $ 230.1 $ 186.4 $ 177.7
=============================================================================================================
Effective income tax rate 39.1% 35.4% 35.2%
At December 31, 2000 1999
- -------------------------------------------------------------------------------------------------------------
(Dollar amounts in millions)
Deferred Income Taxes
Deferred tax liabilities
Net property, plant and equipment $1,121.1 $1,102.6
Income taxes recoverable through future rates 32.8 35.7
Deferred termination and postemployment costs 13.6 14.7
Deferred fuel costs 24.9 25.8
Leveraged leases 17.0 19.9
Energy trading activities 1,691.8 71.4
Deferred electric generation-related regulatory assets 93.7 100.3
Other 161.7 192.6
- -------------------------------------------------------------------------------------------------------------
Total deferred tax liabilities 3,156.6 1,563.0
- -------------------------------------------------------------------------------------------------------------
Deferred tax assets
Accrued pension and postemployment benefit costs 76.5 63.6
Deferred investment tax credits 35.5 38.3
Nuclear decommissioning liability 28.2 25.4
Energy trading activities 1,510.6 15.1
Other 166.3 131.8
- -------------------------------------------------------------------------------------------------------------
Total deferred tax assets 1,817.1 274.2
- -------------------------------------------------------------------------------------------------------------
Deferred tax liability, net $1,339.5 $1,288.8
=============================================================================================================
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1 SIGNIFICANT ACCOUNTING POLICIES
Nature of Our Business
- ----------------------
Constellation Energy(R) Group, Inc. (Constellation Energy) is a diversified
North American energy company. Constellation Energy conducts its business
through various subsidiaries that primarily include a domestic merchant energy
business and Baltimore Gas and Electric Company (BGE(R)). Our domestic merchant
energy business is focused mostly on power marketing and merchant generation in
North America. BGE is an electric and gas public utility distribution company
with a service territory that covers the City of Baltimore and all or part of
ten counties in Central Maryland. We describe our operating segments in Note 2.
References in this report to "we" and "our" are to Constellation Energy and
its subsidiaries, collectively. Reference in this report to the "utility
business" is to BGE.
On April 30, 1999, Constellation Energy became the holding company for BGE
and Constellation(R) Enterprises, Inc. Constellation Enterprises was previously
owned by BGE. BGE's outstanding common stock automatically became shares of
common stock of Constellation Energy. BGE's debt securities, obligated
mandatorily redeemable trust preferred securities, and preference stock remain
securities of BGE, or its subsidiaries.
Consolidation Policy
- --------------------
We use three different accounting methods to report our investments in our
subsidiaries or other companies: consolidation, the equity method, and the cost
method.
Consolidation
- -------------
We use consolidation when we own a majority of the voting stock of the
subsidiary. This means the accounts of our subsidiaries are combined with our
accounts. We eliminate intercompany balances and transactions when we
consolidate these accounts. Our consolidated financial statements include the
accounts of:
. Constellation Energy,
. BGE and its subsidiaries,
. Constellation Enterprises, Inc. and its subsidiaries, and
. Constellation Nuclear, LLC and its subsidiaries.
The Equity Method
- -----------------
We usually use the equity method to report investments, corporate joint
ventures, partnerships, and affiliated companies (including power projects)
where we hold a 20% to 50% voting interest. Under the equity method, we report:
. our interest in the entity as an investment in our Consolidated Balance
Sheets, and
. our percentage share of the earnings from the entity in our Consolidated
Statements of Income.
The only time we do not use this method is if we can exercise control over the
operations and policies of the company. If we have control, accounting rules
require us to use consolidation.
The Cost Method
- ---------------
We usually use the cost method if we hold less than a 20% voting interest in an
investment. Under the cost method, we report our investment at cost in our
Consolidated Balance Sheets. The only time we do not use this method is when we
can exercise significant influence over the operations and policies of the
company. If we have significant influence, accounting rules require us to use
the equity method.
Regulation of Utility Business
- ------------------------------
The Maryland Public Service Commission (Maryland PSC) provides the final
determination of the rates we charge our customers for our regulated businesses.
Generally, we use the same accounting policies and practices used by
nonregulated companies for financial reporting under accounting principles
generally accepted in the United States of America. However, sometimes the
Maryland PSC orders an accounting treatment different from that used by
nonregulated companies to determine the rates we charge our customers. When this
happens, we must defer certain utility expenses and income in our Consolidated
Balance Sheets as regulatory assets and liabilities. We have recorded these
regulatory assets and liabilities in our Consolidated Balance Sheets in
accordance with Statement of Financial Accounting Standards (SFAS) No. 71,
Accounting for the Effects of Certain Types of Regulation. We summarize and
discuss our regulatory assets and liabilities further in Note 5.
In 1997, the Financial Accounting Standards Board (FASB) through its Emerging
Issues Task Force (EITF) issued EITF 97-4, Deregulation of the Pricing of
Electricity--Issues Related to the Application of FASB Statements No. 71
and 101. The EITF concluded that a company should cease to apply SFAS No. 71
when either legislation is passed or a regulatory body issues an order that
contains sufficient detail to determine how the transition plan will affect the
deregulated portion of the business. Additionally, a company would continue to
recognize regulatory assets and liabilities in the Consolidated Balance Sheets
to the extent that the transition plan provides for their recovery.
On November 10, 1999, the Maryland PSC issued a Restructuring Order that we
believe provided sufficient details of the transition plan to competition for
BGE's electric generation business to require BGE to discontinue the application
of SFAS No. 71 for that portion of its business. Accordingly, in the fourth
quarter of 1999, we adopted the provisions of SFAS No. 101, Regulated
Enterprises--Accounting for the Discontinuation of FASB Statement No. 71 and
EITF No. 97-4 for BGE's electric generation business. BGE's transmission and
distribution business continues to meet the requirements of SFAS No. 71 as that
business remains regulated. We discuss this further in Note 4.
Revenues
- --------
Nonregulated Businesses
- -----------------------
We record nonregulated revenues in our Consolidated Statements of Income in the
period earned for services rendered, commodities or products delivered, or
contracts settled.
Our subsidiary, Constellation Power Source, engages in power marketing
activities, which include trading electricity, other energy commodities, and
related derivatives (such as futures, forwards, options, and swaps).
Constellation Power Source accounts for its activities using the mark-to-market
method of accounting in accordance with EITF Issue 98-10, Accounting for
Contracts Involved in Energy Trading and Risk Management Activities.
Under the mark-to-market method of accounting, we report:
. commodity positions and derivatives at fair value as "Assets from energy
trading activities" or "Liabilities from energy trading activities" in our
Consolidated Balance Sheets, and
. changes in fair value and net gains and losses from realized transactions
as components of "Nonregulated revenues" in our Consolidated Statements of
Income.
Changes in fair value result primarily from new transactions and the impact
of price and interest rate movements.
Regulated Utility
- -----------------
We record utility revenues when we provide service to customers.
Fuel and Purchased Energy Costs
- -------------------------------
We incur costs for:
. the fuel we use to generate electricity,
. purchases of electricity from others, and
. natural gas that we resell.
These costs are included in "Operating expenses" in our Consolidated
Statements of Income. We discuss each of these separately below.
Fuel Used to Generate Electricity and Purchases of Electricity From Others
- --------------------------------------------------------------------------
Effective July 1, 2000, these costs are recorded as incurred. Historically and
until July 1, 2000, we were allowed to recover our costs of electric fuel under
the electric fuel rate clause set by the Maryland PSC. Under the electric fuel
rate clause, we charged our electric customers for:
. the fuel we use to generate electricity (nuclear fuel, coal, gas, or oil),
and
. the net cost of purchases and sales of electricity.
We charged the actual costs of these items to customers with no profit to us.
To do this, we had to keep track of what we spent and what we collected from
customers under the fuel rate in a given period. Usually these two amounts were
not the same because there was a difference between the time we spent the money
and the time we collected it from our customers.
Under the electric fuel rate clause, we deferred (included as an asset or
liability in our Consolidated Balance Sheets and excluded from our Consolidated
Statements of Income) the difference between our actual costs of fuel and energy
and what we collected from customers under the fuel rate in a given period. We
either billed or refunded our customers that difference in the future. As a
result of the Restructuring Order, the fuel rate was discontinued effective July
1, 2000. We discuss this further in Note 5.
Natural Gas
- -----------
We charge our gas customers for the natural gas they purchase from us using "gas
cost adjustment clauses" set by the Maryland PSC. These clauses operate
similarly to the electric fuel rate clause described earlier in this note.
However, the Maryland PSC approved a modification of the gas cost adjustment
clauses to provide a market based rates incentive mechanism. Under market based
rates our actual cost of gas is compared to a market index (a measure of the
market price of gas in a given period). The difference between our actual cost
and the market index is shared equally between shareholders and customers.
Risk Management
- ---------------
We are exposed to the impact of market fluctuations in the price and
transportation costs of electricity, natural gas, and other commodities. Our
domestic merchant energy and regulated gas businesses use derivative instruments
to manage changes in their respective commodity prices. We discuss our risk
management activities in more detail below.
Domestic Merchant Energy Business
- ---------------------------------
Our domestic merchant energy business is exposed to market risk from the power
marketing operation of Constellation Power Source and from our electric
generation operations. Constellation Power Source manages the market risk
inherent in its power marketing activities on a portfolio basis, subject to
established trading and risk management policies. Constellation Power Source
uses a variety of derivative instruments, including:
. forward contracts, which commit us to purchase or sell energy commodities
in the future;
. futures contracts, which are exchange-traded standardized commitments to
purchase or sell a commodity or financial instrument, or to make a cash
settlement, at a specific price and future date;
. swap agreements, which require payments to or from counterparties based
upon the differential between two prices for a predetermined contractual
(notional) amount; and
. option contracts, which convey the right to buy or sell a commodity,
financial instrument, or index at a predetermined price.
Market risk arises from the potential for changes in the value of energy
commodities and related derivatives due to: changes in commodity prices,
volatility of commodity prices, and fluctuations in interest rates. A number of
factors associated with the structure and operation of the electricity market
significantly influence the level and volatility of prices for energy
commodities and related derivative products. These factors include:
. seasonal changes in demand,
. hourly fluctuations in demand due to weather conditions,
. available supply resources,
. transportation availability and reliability within and between regions,
. procedures used to maintain the integrity of the physical electricity
system during extreme conditions, and
. changes in the nature and extent of federal and state regulations.
These factors can affect energy commodity and derivative prices in different
ways and to different degrees. These effects may vary throughout the country as
a result of regional differences in:
. weather conditions,
. market liquidity,
. capability and reliability of the physical electricity and gas systems, and
. the nature and extent of electricity deregulation.
Our domestic merchant energy business conducts electric generation operations
primarily through Constellation Power Source Generation, Calvert Cliffs, and
Constellation Power. Presently, the majority of the generating capacity
controlled by our domestic merchant energy business is used to provide standard
offer service to BGE. However, beginning in July 2002, we expect approximately
1,000 megawatts of industrial customer load will leave standard offer service.
The remainder of the standard offer service arrangement with BGE terminates on
June 30, 2003. Additionally, we plan to expand our generation operations.
As a result, our domestic merchant energy business has a substantial and
increasing amount of generating capacity that is subject to future changes in
wholesale electricity prices and has fuel requirements that are subject to
future changes in coal, natural gas, and oil prices. Additionally, if one or
more of our generating facilities is not able to produce electricity when
required due to operational factors, we may have to forego sales opportunities
or fulfill fixed price sale commitments through the operation of other more
costly generating facilities or through the purchase of energy in the wholesale
market at higher prices.
Constellation Power Source manages the commodity price risk of our electric
generation operations as part of its overall portfolio. Additionally, the
domestic merchant energy business may enter into fixed-price contracts to hedge
a portion of its exposure to future electricity and fuel commodity price risk.
At December 31, 2000, our domestic merchant energy business has several
contracts to sell electricity for each calendar year beginning 2003 through 2010
at fixed prices to hedge a portion of the forecasted sales of electricity by our
domestic merchant energy plants during these periods. At December 31, 2000, we
recorded deferred hedge losses of $58 million in "Other deferred charges" in our
Consolidated Balance Sheets. We will reclassify these deferred hedge losses to
"Accumulated other comprehensive income" when we adopt SFAS No. 133 in 2001.
Regulated Electric Business
- ---------------------------
The standard offer service arrangement between BGE and Constellation Power
Source ends June 30, 2003. Under the Restructuring Order, effective July 1,
2000, BGE's residential rates are frozen for a six-year period and its
commercial and industrial rates are frozen for four to six years. As a result,
BGE will be subject to commodity price risk beginning July 1, 2003 upon
termination of the existing standard offer arrangement. In accordance with the
Restructuring Order, BGE will competitively bid the standard offer service
supply for the remaining period of the rate freeze subsequent to June 30, 2003.
During the remaining period of BGE's rate freeze, BGE will be unable to pass
through to its customers any increase in the market price of electricity it must
purchase to meet the standard offer service load. Our regulated electric
business is evaluating various alternatives to minimize the market risk after
June 30, 2003.
Regulated Gas Business
- ----------------------
We use basis swaps in the winter months (November through March) to hedge our
price risk associated with natural gas purchases under our market based rates
incentive mechanism. We also use fixed-to-floating and floating-to-fixed swaps
to hedge our price risk associated with our off-system gas sales. The fixed
portion represents a specific dollar amount that we will pay or receive and the
floating portion represents a fluctuating amount based on a published index that
we will receive or pay. Our regulated gas business internal guidelines do not
permit the use of swap agreements for any purpose other than to hedge price
risk.
BGE's off-system gas sales activities represent trading activities under EITF
98-10. Accordingly, we use mark-to-market accounting to record these
transactions. The trading activities relating to our off-system gas sales were
not material at December 31, 2000 and 1999.
We defer, as unrealized gains or losses, the changes in fair value of the
swap agreements under the market based rates incentive mechanism and the
customers' portion of off-system gas sales in our Consolidated Balance Sheets.
When amounts are paid under the agreements, we report the payments as gas costs
in our Consolidated Statements of Income. We report the changes in fair value
for the shareholders' portion of off-system gas sales in earnings as a component
of gas costs.
Credit Risk
- -----------
We are exposed to credit risk, primarily through Constellation Power Source.
Credit risk is the loss that may result from a counterparty's nonperformance.
Constellation Power Source uses credit policies to control its credit risk,
including utilizing an established credit approval process, monitoring
counterparty limits, employing credit mitigation measures such as margin,
collateral or prepayment arrangements, and using master netting agreements.
However, due to the possibility of extreme volatility in the prices of
electricity commodities and derivatives, the market value of contractual
positions with individual counterparties could exceed established credit limits
or collateral provided by those counterparties. If such a counterparty were then
to fail to perform its obligations under its contract (for example, fail to
deliver the electricity Constellation Power Source had contracted for),
Constellation Power Source could sustain a loss that could have a material
impact on our financial results.
Taxes
- -----
We summarize our income taxes in our Consolidated Statements of Income Taxes. As
you read this section, it may be helpful to refer to those statements.
Income Tax Expense
- ------------------
We have two categories of income taxes in our Consolidated Statements of Income-
- -current and deferred. We describe each of these below.
Our current income tax expense consists solely of regular tax less applicable
tax credits.
Our deferred income tax expense is equal to the changes in the net deferred
income tax liability, excluding amounts charged or credited to common
shareholders' equity. Our deferred income tax expense is increased or reduced
for changes to the "Income taxes recoverable through future rates (net)"
regulatory asset (described later in this note) during the year.
Investment Tax Credits
- ----------------------
We have deferred the investment tax credit associated with our regulated utility
business and assets previously held by our regulated utility business in our
Consolidated Balance Sheets. The investment tax credit is amortized evenly to
income over the life of each property. We reduce income tax expense in our
Consolidated Statements of Income for the investment tax credit and other tax
credits associated with our nonregulated businesses, other than leveraged
leases.
Deferred Income Tax Assets and Liabilities
- ------------------------------------------
We must report some of our revenues and expenses differently for our financial
statements than we do for income tax purposes. The tax effects of the
differences in these items are reported as deferred income tax assets or
liabilities in our Consolidated Balance Sheets. We measure the assets and
liabilities using income tax rates that are currently in effect.
A portion of our total deferred income tax liability relates to our regulated
utility business, but has not been reflected in the rates we charge our
customers. We refer to this portion of the liability as "Income taxes
recoverable through future rates (net)." We have recorded that portion of the
net liability as a regulatory asset in our Consolidated Balance Sheets. We
discuss this further in Note 5.
State and Local Taxes
- ---------------------
As discussed in Note 4, tax legislation has made comprehensive changes to the
state and local taxation of electric and gas utilities. State and local income
taxes are included in "Income taxes" in our Consolidated Statements of Income.
Through December 31, 1999, we paid Maryland public service company franchise
tax on our utility revenue from sales in Maryland instead of state income tax.
We include the franchise tax in "Taxes other than income taxes" in our
Consolidated Statements of Income.
Cash and Cash Equivalents
- -------------------------
For the purpose of reporting our cash flows, we define cash equivalents as
highly liquid investments that mature in three months or less.
At December 31, 2000, $112.5 million of the cash balance included in our
Consolidated Balance Sheets was restricted under certain collateral arrangements
for our power marketing operation.
Inventory
- ---------
We report the majority of our fuel stocks and materials and supplies at average
cost.
Real Estate Projects and Investments
- ------------------------------------
In Note 3, we summarize the real estate projects and investments that are in our
Consolidated Balance Sheets. The projects and investments consist of:
. land under development in the Baltimore-Washington corridor,
. a mixed-use planned-unit development, and
. an equity interest in Corporate Office Properties Trust, a real estate
investment trust.
The costs incurred to acquire and develop properties are included as part of
the cost of the properties.
Financial Investments and Trading Securities
- --------------------------------------------
In Note 3, we summarize the financial investments that are in our Consolidated
Balance Sheets.
SFAS No. 115, Accounting for Certain Investments in Debt and Equity
Securities, applies particular requirements to some of our investments in debt
and equity securities. We report those investments at fair value, and we use
specific identification to determine their cost for computing realized gains or
losses. We classify these investments as either trading securities or available-
for-sale securities, which we describe separately on the next page. We report
investments that are not covered by SFAS No. 115 at their cost.
Trading Securities
- ------------------
Our other nonregulated businesses classify some of their investments in
marketable equity securities and financial limited partnerships as trading
securities. We include any unrealized gains or losses on these securities in
"Nonregulated revenues" in our Consolidated Statements of Income.
Available-for-Sale Securities
- -----------------------------
We classify our investments in the nuclear decommissioning trust fund as
available-for-sale securities. We include any unrealized gains or losses on the
trust assets as a change in the decommissioning reserve. We describe the nuclear
decommissioning trust and the reserve under the heading "Decommissioning Costs"
later in this note.
In addition, our other nonregulated businesses classify some of their
investments in marketable equity securities as available-for-sale securities. We
include any unrealized gains or losses on these securities in "Accumulated other
comprehensive income" in our Consolidated Statements of Common Shareholders'
Equity and in the Consolidated Statements of Capitalization.
Evaluation of Assets for Impairment and Other Than Temporary Decline in Value
- -----------------------------------------------------------------------------
SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-
Lived Assets to Be Disposed Of, applies particular requirements to some of our
assets that have long lives (some examples are generating property and equipment
and real estate). We determine if those assets are impaired by comparing their
undiscounted expected future cash flows to their carrying amount in our
accounting records. We recognize an impairment loss if the undiscounted expected
future cash flows are less than the carrying amount of the asset. Additionally,
we evaluate our equity-method investments to determine whether our investments
have a loss in value that is considered other than a temporary decline in value.
We use our best estimates to determine if there has been an impairment or
decline in value other than temporary and consider various factors including
forward price curves for energy, fuel costs, and operating costs. However, it is
possible that future market prices and project costs could vary from those used
in evaluating our long-lived assets and investments, and the impact of such
variations could be material.
Property, Plant and Equipment, Depreciation, Amortization, and Decommissioning
- ------------------------------------------------------------------------------
We report our property, plant and equipment at its original cost, unless
impaired under the provisions of SFAS No. 121. Our original costs include:
. material and labor,
. contractor costs, and
. construction overhead costs and financing costs (where applicable).
We charge retired or otherwise disposed of property, plant and equipment that
was depreciated under the composite, straight-line method to accumulated
depreciation. This includes regulated utility property, plant and equipment and
nonregulated generating assets previously owned by the regulated utility. When
any other property, plant and equipment is retired, or otherwise disposed of, we
reduce the property, plant and equipment balances and related accumulated
depreciation and amortization amounts, and recognize any gain or loss in our
Consolidated Statements of Income.
The costs of maintenance and certain replacements are charged to "Operating
expenses" in our Consolidated Statements of Income as incurred.
We own an undivided interest in the Keystone and Conemaugh electric
generating plants in Western Pennsylvania, as well as in the transmission line
that transports the plants' output to the joint owners' service territories. Our
ownership interests in these plants are 20.99% in Keystone and 10.56% in
Conemaugh. These ownership interests represented a net investment of $143
million at December 31, 2000 and $156 million at December 31, 1999.
The "Nonregulated generation property, plant and equipment" in our
Consolidated Balance Sheets includes nonregulated generation construction work
in progress of $901.8 million at December 31, 2000 and $97.7 million at December
31, 1999.
Depreciation Expense
- --------------------
We compute depreciation over the estimated useful lives of depreciable property
using the:
. composite, straight-line rates (approved by the Maryland PSC for our
regulated utility business) applied to the average investment in classes of
depreciable property based on an average rate of approximately three
percent per year,
. units of production method for certain nonregulated generation facilities,
or
. straight-line method.
Amortization Expense
- --------------------
Amortization is an accounting process of reducing an amount in our Consolidated
Balance Sheets evenly over a period of time. When we reduce amounts in our
Consolidated Balance Sheets, we increase amortization expense in our
Consolidated Statements of Income. An amount is considered fully amortized when
it has been reduced to zero.
We are required, along with other domestic utilities, by the Energy Policy
Act of 1992 to make contributions to a fund for decommissioning and
decontaminating the Department of Energy's uranium enrichment facilities. The
contributions are generally payable over 15 years with escalation for inflation
and are based upon the proportionate amount of uranium enriched by the
Department of Energy for each utility. We amortize the deferred costs of
decommissioning and decontaminating the Department of Energy's uranium
enrichment facilities.
We also amortize nuclear fuel based on the energy produced over the life of
the fuel including the quarterly fees we pay to the Department of Energy for the
future disposal of spent nuclear fuel. These fees are based on the kilowatt-
hours of electricity sold. We report the amortization expense for nuclear fuel
in "Operating expenses" in our Consolidated Statements of Income.
Decommissioning Costs
- ---------------------
We must accumulate a reserve for the costs that we expect to incur in the future
to decommission the radioactive portion of Calvert Cliffs. We do this based on a
sinking fund methodology. The Maryland PSC authorized us to include in the rates
that we charge our customers decommissioning expense based on a facility-
specific cost estimate so we can accumulate a decommissioning reserve of $521
million in 1993 dollars by the end of Calvert Cliffs' service life, adjusted to
reflect expected inflation. We have reported the decommissioning reserve in
"Accumulated depreciation" in our Consolidated Balance Sheets. The total reserve
was $310.1 million at December 31, 2000 and $287.5 million at December 31, 1999.
Our contributions to the nuclear decommissioning trust funds were $13.2 million
for 2000 and $17.6 million for 1999 and 1998.
To fund the costs we expect to incur to decommission the plant, we
established an external decommissioning trust in accordance with Nuclear
Regulatory Commission (NRC) regulations. We report the assets in the trust in
"Nuclear decommissioning trust fund" in our Consolidated Balance Sheets. The NRC
requires utilities to provide financial assurance that they will accumulate
sufficient funds to pay for the cost of nuclear decommissioning based upon
either a generic NRC formula or a facility-specific decommissioning cost
estimate. We use the facility-specific cost estimate for funding these costs and
providing the required financial assurance.
Capitalized Interest and Allowance for Funds Used During Construction
- ---------------------------------------------------------------------
Capitalized Interest
- --------------------
With the issuance of the Restructuring Order, we ceased accruing AFC (discussed
below) for electric generation-related construction projects.
Our nonregulated businesses capitalize interest costs under SFAS No. 34,
Capitalizing Interest Costs, for costs incurred to finance our power projects
and real estate developed for internal use.
Allowance for Funds Used During Construction (AFC)
- --------------------------------------------------
We finance regulated utility construction projects with borrowed funds and
equity funds. We are allowed by the Maryland PSC to record the costs of these
funds as part of the cost of construction projects in our Consolidated Balance
Sheets. We do this through the AFC, which we calculate using a rate authorized
by the Maryland PSC. We bill our customers for the AFC plus a return after the
utility property is placed in service.
The AFC rates are 9.40% for electric plant, 8.61% for gas plant, and 9.19%
for common plant. We compound AFC annually.
Long-Term Debt
- --------------
We defer (include as an asset or liability in our Consolidated Balance Sheets
and exclude from our Consolidated Statements of Income) all costs related to the
issuance of long-term debt. These costs include underwriters' commissions,
discounts or premiums, and other costs such as legal, accounting, and regulatory
fees, and printing costs. We amortize these costs over the life of the debt.
When we incur gains or losses on debt that we retire prior to maturity in our
regulated utility business, we amortize those gains or losses over the remaining
original life of the debt.
When we incur gains or losses on debt that we retire prior to maturity in our
nonregulated businesses, we record these gains or losses as an extraordinary
item, if material.
Use of Accounting Estimates
- ---------------------------
Management makes estimates and assumptions when preparing financial statements
under accounting principles generally accepted in the United States of America.
These estimates and assumptions affect various matters, including:
. our reported amounts of assets and liabilities in our Consolidated Balance
Sheets at the dates of the financial statements,
. our disclosure of contingent assets and liabilities at the dates of the
financial statements, and
. our reported amounts of revenues and expenses in our Consolidated
Statements of Income during the reporting periods.
These estimates involve judgments with respect to, among other things, future
economic factors that are difficult to predict and are beyond management's
control. As a result, actual amounts could differ from these estimates.
Reclassifications
- -----------------
We have reclassified certain prior-year amounts for comparative purposes. These
reclassifications did not affect consolidated net income for the years
presented.
Accounting Standards Issued
- ---------------------------
In June 1998, the FASB issued SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities. SFAS No. 133 establishes the accounting and
disclosure standards for derivative financial instruments and hedging
activities. In July 1999, the FASB issued SFAS No. 137 that delayed the
effective date for SFAS No. 133 by one year. Therefore, we must adopt the
provisions of SFAS No. 133 in our financial statements for the quarter ended
March 31, 2001. In June 2000, the FASB issued SFAS No. 138, Accounting for
Certain Derivative Instruments and Certain Hedging Activities, that amended
certain provisions of SFAS No. 133 and addressed a limited number of
implementation issues related to SFAS No. 133.
These statements require that we recognize all derivatives on the balance
sheet at fair value. Changes in the value of derivatives that are not hedges
must be recorded in earnings. We expect to use derivatives to hedge the risk of
variations in future cash flows from forecasted purchases and sales of
electricity. Changes in the value of these derivatives will be recognized in
other comprehensive income until the forecasted transaction occurs. The
ineffective portion of the change in fair value of a derivative being used as a
hedge will be immediately recognized in earnings.
The cumulative effect on earnings of adopting these statements is not
material. As of December 31, 2000, we entered into certain forward sales of
electricity that were designated as cash flow hedges of forecasted transactions.
We will record a reduction in other comprehensive income of approximately $35
million after-tax to reflect these cash flow hedges in accordance with these
statements.
2 INFORMATION BY OPERATING SEGMENT
In 1999, we reported three operating business segments--Electric, Gas, and
Energy Services. In response to the deregulation of electric generation, we
realigned our organization and combined our wholesale power marketing operation
with our domestic plant development and operation activities to form a domestic
merchant energy business.
In 2000, we revised our operating segments to reflect the realignments of our
organization. Our new reportable operating segments are--Domestic Merchant
Energy, Regulated Electric, and Regulated Gas:
. Our nonregulated domestic merchant energy business:
. provides power marketing and risk management services,
. develops, owns, and operates domestic power projects, and
. provides nuclear consulting services.
. Our regulated electric business purchases, distributes and sells
electricity, and
. Our regulated gas business purchases, transports, and sells natural gas.
We have restated certain prior period information for comparative purposes
based on our new reportable operating segments.
Effective July 1, 2000, the financial results of the electric generation
portion of our business are included in the domestic merchant energy business
segment. Prior to that date, the financial results of electric generation are
included in our regulated electric business.
Our remaining nonregulated businesses:
. develop, own, and operate international power projects in Latin America,
. provide energy products and services,
. sell and service electric and gas appliances, and heating and air
conditioning systems, engage in home improvements, and sell natural gas
through mass marketing efforts,
. provide cooling services,
. engage in financial investments, and
. develop, own and manage real estate and senior-living facilities.
These reportable segments are strategic businesses based principally upon
regulations, products, and services that require different technology and
marketing strategies. We evaluate the performance of these segments based on net
income. We account for intersegment revenues using market prices. A summary of
information by operating segment is shown on the next page.
Domestic Unallocated
Merchant Regulated Regulated Other Corporate
Energy Electric Gas Nonregulated Items and
Business Business Business Businesses Eliminations Consolidated
- ------------------------------------------------------------------------------------------------------------------------
(In millions)
2000
Unaffiliated revenues $ 415.4 $2,134.7 $ 603.8 $ 724.6 $ -- $ 3,878.5
Intersegment revenues 576.6 0.5 7.8 15.7 (600.6) --
- ------------------------------------------------------------------------------------------------------------------------
Total revenues 992.0 2,135.2 611.6 740.3 (600.6) 3,878.5
Depreciation and amortization 80.9 319.9 46.2 23.0 -- 470.0
Equity in income of equity-
method investees (a) -- 2.4 -- -- -- 2.4
Net interest expense 31.0 157.0 25.5 53.1 (8.4) 258.2
Income tax expense 122.5 72.2 21.9 13.5 -- 230.1
Net income (b) 206.8 102.3 30.6 5.6 -- 345.3
Segment assets 6,753.3 3,453.4 1,028.8 1,299.5 (150.4) 12,384.6
Capital expenditures 811.2 290.3 59.7 19.3 -- 1,180.5
1999
Unaffiliated revenues $ 212.9 $2,258.8 $ 476.5 $ 838.0 $ -- $ 3,786.2
Intersegment revenues -- 1.2 11.6 20.1 (32.9) --
- ------------------------------------------------------------------------------------------------------------------------
Total revenues 212.9 2,260.0 488.1 858.1 (32.9) 3,786.2
Depreciation and amortization 5.0 376.4 44.9 23.5 -- 449.8
Equity in income of equity-
method investees (a) -- 5.1 -- -- -- 5.1
Net interest expense -- 162.4 24.4 56.1 (1.4) 241.5
Income tax expense (benefit) 29.4 149.2 18.1 (10.3) -- 186.4
Extraordinary loss -- 66.3 -- -- -- 66.3
Net income (loss) (c) 52.4 198.8 33.0 (24.1) -- 260.1
Segment assets 1,206.1 6,312.6 915.3 1,231.3 18.5 9,683.8
Capital expenditures 260.9 366.8 69.2 17.3 -- 714.2
1998
Unaffiliated revenues $ 147.3 $2,219.2 $ 449.4 $ 570.5 $ -- $ 3,386.4
Intersegment revenues -- 1.6 1.7 12.5 (15.8) --
- ------------------------------------------------------------------------------------------------------------------------
Total revenues 147.3 2,220.8 451.1 583.0 (15.8) 3,386.4
Depreciation and amortization 3.0 313.0 45.4 13.9 0.2 375.5
Equity in income of equity-
method investees (a) -- 5.0 -- -- -- 5.0
Net interest expense -- 164.9 23.6 50.7 (0.4) 238.8
Income tax expense (benefit) 28.6 146.6 13.4 (10.9) -- 177.7
Net income (loss) (d) 53.1 259.6 26.1 (32.9) -- 305.9
Segment assets 885.3 6,342.8 934.6 1,275.2 (3.8) 9,434.1
Capital expenditures 317.5 339.5 65.5 7.7 -- 730.2
(a) Our domestic merchant energy business records its equity in the income of
equity method investees in unaffiliated revenues.
(b) Our regulated electric business recorded expense of $4.2 million related
to employees that elected to participate in a Targeted Voluntary Special Early
Retirement Program. In addition, our domestic merchant energy business recorded
a $15.0 million deregulation transition cost incurred by our power marketing
operation.
(c) Our regulated electric business recorded expense of $4.9 million related
to Hurricane Floyd. Our domestic merchant energy business recorded $14.2 million
for the write-off of two geothermal power plants. Our Latin American operation
recorded $4.5 million for the write-down to reflect the fair value of our
investment in a power project in Bolivia. Our financial investments operation
recorded $16.0 million for the write-down of its investment in Capital Re stock
to reflect the market value of this investment. Our real estate and senior-
living facilities operation recorded $5.8 million for the write-down of certain
senior-living facilities.
(d) Our domestic merchant energy business recorded $10.4 million for its
share of earnings in a partnership. Our energy products and services operation
recorded $5.5 million for the write-off of an energy services investment. Our
real estate and senior-living facilities operation recorded $15.4 million for
the write-down of a real estate project.
3 INVESTMENTS
Real Estate Projects and Investments
- ------------------------------------
Real estate projects and investments held by Constellation Real Estate Group
(CREG), consist of the following:
At December 31, 2000 1999
- ----------------------------------------------------
(In millions)
Properties under development $165.1 $197.8
Rental and operating properties
(net of accumulated
depreciation) 12.7 9.2
Equity interest in real estate
investments 112.5 103.1
- ----------------------------------------------------
Total real estate projects and
investments $290.3 $310.1
====================================================
In 1999, CREG sold Church Street Station--an entertainment, dining, and
retail complex in Orlando, Florida--for $11.5 million, the approximate book
value of the complex.
In 1998, CREG entered into an agreement with Corporate Office Properties
Trust (COPT), a real estate investment trust based in Philadelphia, under which
COPT assumed approximately $62 million of CREG's outstanding debt, paid CREG
approximately $22.8 million in cash, and issued to CREG approximately 7.0
million common shares representing a 41.9% equity interest in COPT and 985,000
convertible preferred shares. Each convertible preferred share yields 5.5% per
year, and is convertible after two years into 1.8748 common shares.
In exchange, COPT received 14 operating properties and two properties under
development from CREG as well as certain other assets, options, and first
refusal rights. These options and first refusal rights are related to
approximately 91 acres of identified properties which are adjacent to operating
properties acquired by COPT. At December 31, 2000, 30 acres remain under these
options and first refusal rights with terms that range from one to three years.
In September 2000, CREG converted 984,307 preferred shares of COPT into
approximately 1.8 million common shares of COPT.
Power Projects
- --------------
Investments in power projects held by our domestic merchant energy business
consist of the following:
At December 31, 2000 1999
- --------------------------------------------------
(In millions)
East $ 86.3 $ 85.1
West 419.8 416.5
- --------------------------------------------------
Total domestic power projects $506.1 $501.6
==================================================
Our Domestic-West power projects include investments of $297.9 million in
2000 and $301.8 million in 1999 that sell electricity in California under power
purchase agreements called "Interim Standard Offer No. 4" agreements. We discuss
these projects further in Note 10.
In 1999, our domestic generation operation recorded a $14.2 million after-tax
write-off of two geothermal power projects. These write-offs occurred because
the expected future cash flows from the projects are less than the investment in
the projects. For the first project, this resulted from the inability to
restructure certain project agreements. For the second project, the water
temperature of the geothermal resource used by one of the plants for production
declined.
In 1998, our domestic generation operation recorded $10.4 million after-tax
gain for its share of earnings in a partnership. The partnership recognized a
gain on the sale of its ownership interest in a power sales contract.
Our Latin American operation held power projects of $11.4 million at December
31, 2000 and $12.3 million at December 31, 1999.
In 1999, our Latin American operation recorded a $4.5 million after-tax
write-down to reflect the fair value of our investment in a generating company
in Bolivia as a result of our international exit strategy.
Financial Investments
- ---------------------
Financial investments held by Constellation Investments, Inc. consist of the
following:
At December 31, 2000 1999
- ---------------------------------------------------
(In millions)
Marketable equity securities $105.9 $ 84.2
Financial limited partnerships 32.7 35.8
Leveraged leases 22.4 25.4
- ---------------------------------------------------
Total financial investments $161.0 $145.4
===================================================
In 1999, our financial investments operation announced that it would exchange
its shares of common stock in Capital Re, an insurance company, for common stock
of ACE Limited (ACE), another insurance company, as part of a business
combination whereby ACE would acquire all of the outstanding capital stock of
Capital Re. As a result, our financial investments operation wrote-down its
$94.2 million investment in Capital Re stock by $16.0 million after-tax to
reflect the closing price of the business combination.
Investments Classified as Available-for-Sale
- --------------------------------------------
We classify our investments in the nuclear decommissioning trust fund as
available-for-sale. In addition, we classify some of our other nonregulated
businesses' marketable equity securities (shown above) as available-for-sale.
This means we do not expect to hold them to maturity and we do not consider them
trading securities.
We show the fair values, gross unrealized gains and losses, and amortized
cost bases for all of our available-for-sale securities, in the following
tables.
Amortized Unrealized Unrealized Fair
At December 31, 2000 Cost Basis Gains Losses Value
- -------------------------------------------------------------------------
(In millions)
Marketable equity
securities $171.8 $68.9 $(2.2) $238.5
Corporate debt and
U.S. Government
agency 26.1 0.1 (0.1) 26.1
State municipal bonds 61.3 2.3 (0.4) 63.2
- -------------------------------------------------------------------------
Totals $259.2 $71.3 $(2.7) $327.8
=========================================================================
Amortized Unrealized Unrealized Fair
At December 31, 1999 Cost Basis Gains Losses Value
- -------------------------------------------------------------------------
(In millions)
Marketable equity
securities $167.1 $42.8 $(2.1) $207.8
Corporate debt and
U.S. Government
agency 14.4 -- -- 14.4
State municipal bonds 74.2 -- (0.8) 73.4
- -------------------------------------------------------------------------
Totals $255.7 $42.8 $(2.9) $295.6
=========================================================================
The preceding tables include $34.7 million in 2000 and $40.5 million in 1999
of unrealized net gains associated with the nuclear decommissioning trust fund
which are reflected as a change in the nuclear decommissioning trust fund on the
Consolidated Balance Sheets.
Gross and net realized gains and losses on available-for-sale securities were
as follows:
2000 1999 1998
- -------------------------------------------------------------------------
(In millions)
Gross realized gains $54.5 $ 11.7 $ 4.2
Gross realized losses (8.0) (38.8) (0.7)
- -------------------------------------------------------------------------
Net realized gains (losses) $46.5 $(27.1) $ 3.5
=========================================================================
The Corporate debt securities, U.S. Government agency obligations, and state
municipal bonds mature on the following schedule:
At December 31, 2000 Amount
- ---------------------------------------------------------
(In millions)
Less than 1 year $ 0.9
1-5 years 41.9
5-10 years 23.7
More than 10 years 22.8
- ---------------------------------------------------------
Total maturities of debt securities $89.3
=========================================================
4 RATE MATTERS AND ACCOUNTING IMPACTS OF DEREGULATION
On April 8, 1999, Maryland enacted the Electric Customer Choice and Competition
Act of 1999 (the "Act") and accompanying tax legislation that significantly
restructured Maryland's electric utility industry and modified the industry's
tax structure. In the Restructuring Order discussed below, the Maryland PSC
addressed the major provisions of the Act.
The tax legislation made comprehensive changes to the state and local
taxation of electric and gas utilities. Effective January 1, 2000, the Maryland
public service franchise tax was altered to generally include a tax equal to
.062 cents on each kilowatt-hour of electricity and .402 cents on each therm of
natural gas delivered for final consumption in Maryland. The Maryland 2%
franchise tax on electric and natural gas utilities continues to apply to
transmission and distribution revenue. Additionally, all electric and natural
gas utility results are subject to the Maryland corporate income tax.
Beginning July 1, 2000, the tax legislation also provides for a two-year
phase-in of a 50% reduction in the local personal property taxes on machinery
and equipment used to generate electricity for resale and a 60% corporate income
tax credit for real property taxes paid on those facilities.
On November 10, 1999, the Maryland PSC issued a Restructuring Order that
resolved the major issues surrounding electric restructuring, accelerated the
timetable for customer choice, and addressed the major provisions of the Act.
The Restructuring Order also resolved the electric restructuring proceeding
(transition costs, customer price protections, and unbundled rates for electric
services) and a petition filed in September 1998 by the Office of People's
Counsel (OPC) to lower our electric base rates. The major provisions of the
Restructuring Order are:
. All customers, except a few commercial and industrial companies that have
signed contracts with BGE, can choose their electric energy supplier
beginning July 1, 2000. BGE will provide a standard offer service for
customers that do not select an alternative supplier. In either case, BGE
will continue to deliver electricity to all customers in areas
traditionally served by BGE.
. BGE's electric base rates were frozen through June 30, 2000.
. BGE reduced residential base rates by approximately 6.5%, on average about
$54 million a year, beginning July 1, 2000. These rates will not change
before July 2006.
. Commercial and industrial customers have up to four service options that
will fix electric energy rates and transition charges for a period that
generally ranges from four to six years.
. BGE's electric fuel rate clause was discontinued effective July 1, 2000.
. Electric delivery service rates are frozen for a four-year period for
commercial and industrial customers. The generation and transmission
components of rates are frozen for different time periods depending on the
service options selected by those customers.
. BGE will recover $528 million after-tax of its potentially stranded
investments and utility restructuring costs through a competitive
transition charge on customers' bills. Residential customers will pay this
charge for six years. Commercial and industrial customers will pay in a
lump sum or over the four to six-year period, depending on the service
option selected by each customer.
. Generation-related regulatory assets and nuclear decommissioning costs are
included in delivery service rates effective July 1, 2000 and will be
recovered on a basis approximating their amortization schedules prior to
July 1, 2000.
. Effective July 1, 2000, BGE unbundled rates to show separate components for
delivery service, competitive transition charges, standard offer services
(generation), transmission, universal service, and taxes.
. Effective July 1, 2000, BGE transferred, at book value, its ten Maryland-
based fossil and nuclear power plants and its partial ownership interest in
two coal plants and a hydroelectric plant in Pennsylvania to nonregulated
subsidiaries of Constellation Energy.
. BGE reduced its generation assets by $150 million pre-tax during the period
July 1, 1999-June 30, 2000 to mitigate a portion of BGE's potentially
stranded investments.
. Universal service is being provided for low-income customers without
increasing their bills. BGE will provide its share of a statewide fund
totaling $34 million annually.
As discussed in Note 1, EITF 97-4 requires that a company should cease
applying SFAS No. 71 when either legislation is passed or a regulatory body
issues an order that contains sufficient detail to determine how the transition
plan will affect the deregulated portion of the business. Additionally, a
company would continue to recognize regulatory assets and liabilities in the
Consolidated Balance Sheets to the extent that the transition plan provides for
their recovery.
We believe that the Restructuring Order provided sufficient details of the
transition plan to competition for BGE's electric generation business to require
BGE to discontinue the application of SFAS No. 71 for that portion of its
business. Accordingly, in the fourth quarter of 1999, we adopted the provisions
of SFAS No. 101 and EITF 97-4 for BGE's electric generation business.
SFAS No. 101 requires the elimination of the effects of rate regulation that
have been recognized as regulatory assets and liabilities pursuant to SFAS No.
71. However, EITF 97-4 requires that regulatory assets and liabilities that will
be recovered in the regulated portion of the business continue to be classified
as regulatory assets and liabilities. The Restructuring Order provided for the
creation of a single, new generation-related regulatory asset to be recovered
through BGE's regulated transmission and distribution business. We discuss this
further in Note 5.
Pursuant to SFAS No. 101, the book value of property, plant, and equipment
may not be adjusted unless those assets are impaired under the provisions of
SFAS No. 121. The process we used in evaluating and measuring impairment under
the provisions of SFAS No. 121 involved two steps. First, we compared the net
book value of each generating plant to the estimated undiscounted future net
operating cash flows from that plant. An electric generating plant was
considered impaired when its undiscounted future net operating cash flows were
less than its net book value. Second, we computed the fair value of each plant
that is determined to be impaired based on the present value of that plant's
estimated future net operating cash flows discounted using an interest rate that
considers the risk of operating that facility in a competitive environment. To
the extent that the net book value of each impaired electric generation plant
exceeded its fair value, we recorded a write-down.
Under the Restructuring Order, BGE will recover $528 million after-tax of its
potentially stranded investments and utility restructuring costs through the
competitive transition charge component of its customer rates beginning July 1,
2000. This recovery mostly relates to the stranded costs associated with BGE's
Calvert Cliffs Nuclear Power Plant, whose book value was substantially higher
than its estimated fair value. However, Calvert Cliffs was not considered
impaired under the provisions of SFAS No. 121 since its estimated future
undiscounted cash flows exceeded its book value. Accordingly, BGE did not record
any impairment write-down related to Calvert Cliffs. However, we recognized
after-tax impairment losses totaling $115.8 million associated with certain of
our fossil plants under the provisions of SFAS No. 121.
BGE had contracts to purchase electric capacity and energy that became
uneconomic upon the deregulation of electric generation. Therefore, we recorded
a $34.2 million after-tax charge based on the net present value of the excess of
estimated contract costs over the market-based revenues to recover these costs
over the remaining terms of the contracts. In addition, BGE had deferred certain
energy conservation expenditures that would not be recovered through its
transmission and distribution business under the Restructuring Order.
Accordingly, we recorded a $10.3 million after-tax charge to eliminate the
regulatory asset previously established for these deferred expenditures.
At December 31, 1999, the total charge for BGE's electric generating plants
that were impaired, losses on uneconomic purchased capacity and energy
contracts, and deferred energy conservation expenditures was approximately
$160.3 million after-tax.
BGE recorded approximately $94.0 million of the $160.3 million on its balance
sheet. This consisted of a $150.0 million regulatory asset of its regulated
transmission and distribution business, net of approximately $56.0 million of
associated deferred income taxes. The regulatory asset was amortized as it was
recovered from ratepayers through June 30, 2000. This accomplished the $150
million reduction of its generation plants required by the Restructuring Order.
We recorded an after-tax, extraordinary charge against earnings for
approximately $66.3 million related to the remaining portion of the $160.3
million described above that was not recovered under the Restructuring Order.
5 REGULATORY ASSETS (NET)
As discussed in Note 1, the Maryland PSC provides the final determination of the
rates we charge our customers for our regulated businesses. Generally, we use
the same accounting policies and practices used by nonregulated companies for
financial reporting under accounting principles generally accepted in the United
States of America. However, sometimes the Maryland PSC orders an accounting
treatment different from that used by nonregulated companies to determine the
rates we charge our customers. When this happens, we must defer certain utility
expenses and income in our Consolidated Balance Sheets as regulatory assets and
liabilities. We then record them in our Consolidated Statements of Income (using
amortization) when we include them in the rates we charge our customers.
We summarize regulatory assets and liabilities in the following table, and we
discuss each of them separately below.
At December 31, 2000 1999
- -------------------------------------------------------
(In millions)
Generation plant reduction
recoverable in current rates $ -- $ 75.0
Electric generation-related
regulatory asset 267.8 286.6
Income taxes recoverable through
future rates (net) 101.2 110.4
Deferred postretirement and
postemployment benefit costs 38.7 41.9
Deferred conservation expenditures 5.8 12.9
Deferred environmental costs 28.8 31.3
Deferred fuel costs (net) 71.1 73.8
Other (net) 1.5 5.5
- -------------------------------------------------------
Total regulatory assets (net) $514.9 $637.4
=======================================================
Generation Plant Reduction Recoverable in Current Rates
- -------------------------------------------------------
Under the Restructuring Order, BGE recorded a reduction to its generation plant
of $150 million which it recovered through its rates between July 1, 1999 and
June 30, 2000. In 1999, BGE recorded a $150 million regulatory asset for the
required generation plant reduction that was amortized as it was recovered from
ratepayers through June 30, 2000.
Electric Generation-Related Regulatory Asset
- --------------------------------------------
With the issuance of the Restructuring Order, BGE no longer met the requirements
for the application of SFAS No. 71 for the electric generation portion of its
business. In accordance with SFAS No. 101 and EITF 97-4, all individual
generation-related regulatory assets and liabilities must be eliminated from our
balance sheet unless these regulatory assets and liabilities will be recovered
in the regulated portion of the business. Pursuant to the Restructuring Order,
BGE wrote-off all of its individual, generation-related regulatory assets and
liabilities. BGE established a single, new generation-related regulatory asset
for amounts to be collected through its regulated transmission and distribution
business. The new regulatory asset is being amortized on a basis that
approximates the pre-existing individual regulatory asset amortization
schedules.
Income Taxes Recoverable Through Future Rates (net)
- ---------------------------------------------------
As described in Note 1, income taxes recoverable through future rates are the
portion of our net deferred income tax liability that is applicable to our
regulated utility business, but has not been reflected in the rates we charge
our customers. These income taxes represent the tax effect of temporary
differences in depreciation and the allowance for equity funds used during
construction, offset by differences in deferred tax rates and deferred taxes on
deferred investment tax credits. We amortize these amounts as the temporary
differences reverse.
In 1999, we reclassified the electric generation-related portion of this net
regulatory asset to the electric generation-related regulatory asset discussed
earlier in this note.
Deferred Postretirement and Postemployment Benefit Costs
- --------------------------------------------------------
Deferred postretirement and postemployment benefit costs are the costs we
recorded under SFAS No. 106 (for postretirement benefits) and No. 112 (for
postemployment benefits) in excess of the costs we included in the rates we
charge our customers. We began amortizing these costs over a 15-year period in
1998. We discuss these costs further in Note 6.
In 1999, we reclassified the electric generation-related portion of this
regulatory asset to the electric generation-related regulatory asset discussed
earlier in this note.
Deferred Conservation Expenditures
- ----------------------------------
Deferred conservation expenditures include two components:
. operations costs (labor, materials, and indirect costs) associated with
conservation programs approved by the Maryland PSC, which we are amortizing
over periods of four to five years in accordance with the Maryland PSC's
orders, and
. revenues we collected from customers in 1996 in excess of our profit limit
under the conservation surcharge.
In 1999, we wrote off a portion of the unamortized electric conservation
expenditures that will not be recovered under the Restructuring Order as
discussed in Note 4.
Deferred Environmental Costs
- ----------------------------
Deferred environmental costs are the estimated costs of investigating and
cleaning up contaminated sites we own. We discuss this further in Note 10. We
are amortizing $21.6 million of these costs (the amount we had incurred through
October 1995) and $6.4 million of these costs (the amount we incurred from
November 1995 through June 2000) over 10-year periods in accordance with
Maryland PSC's orders.
Deferred Fuel Costs
- -------------------
As described in Note 1, deferred fuel costs are the difference between our
actual costs of electric fuel, net purchases and sales of electricity, and
natural gas, and our fuel rate revenues collected from customers. We reduce
deferred fuel costs as we collect them from or refund them to our customers.
We show our deferred fuel costs in the following table.
At December 31, 2000 1999
- --------------------------------------------
(In millions)
Electric $42.3 $60.0
Gas 28.8 13.8
- --------------------------------------------
Deferred fuel costs (net) $71.1 $73.8
============================================
Under the terms of the Restructuring Order, BGE's electric fuel rate clause
was discontinued effective July 1, 2000. In September 2000, the Maryland PSC
approved the collection of the $54.6 million accumulated difference between our
actual costs of fuel and energy and the amounts collected from customers that
were deferred under the electric fuel rate clause through June 30, 2000. We are
collecting this accumulated difference from customers over the twelve-month
period beginning October 2000.
6 PENSION, POSTRETIREMENT, OTHER POSTEMPLOYMENT, AND EMPLOYEE SAVINGS PLAN
BENEFITS
We offer pension, postretirement, other postemployment, and employee savings
plan benefits. We describe each of these separately below.
Pension Benefits
- ----------------
We sponsor several defined benefit pension plans for our employees. A defined
benefit plan specifies the amount of benefits a plan participant is to receive
using information about the participant. Our employees do not contribute to
these plans. Generally, we calculate the benefits under these plans based on
age, years of service, and pay.
Sometimes we amend the plans retroactively. These retroactive plan amendments
require us to recalculate benefits related to participants' past service. We
amortize the change in the benefit costs from these plan amendments on a
straight-line basis over the average remaining service period of active
employees.
We fund the plans by contributing at least the minimum amount required under
Internal Revenue Service regulations. We calculate the amount of funding using
an actuarial method called the projected unit credit cost method. The assets in
all of the plans at December 31, 2000 were mostly marketable equity and fixed
income securities, and group annuity contracts.
In 1999, our Board of Directors approved the following amendments:
. eligible participants were allowed to choose between an enhanced version of
the current benefit formula and a new pension equity plan (PEP) formula.
Pension benefits for eligible employees hired after December 31, 1999 are
based on a PEP formula, and
. pension and survivor benefits were increased for participants who retired
prior to January 1, 1994 and for their surviving spouses.
The financial impacts of the amendments are included in the tables beginning
on the next page.
Also during 1999, our Board of Directors approved a Targeted Voluntary
Special Early Retirement Program (TVSERP) to provide enhanced early retirement
benefits to certain eligible participants in targeted jobs that elected to
retire on June 1, 2000. BGE recorded approximately $10.0 million ($7.6 million
for pension and $2.4 million for postretirement benefit costs) for employees
that elected to participate in the program. Of this amount, BGE recorded
approximately $3.0 million on its balance sheet as a regulatory asset of its gas
business. We will amortize this regulatory asset over a 5-year period as
provided by the June 2000 Maryland PSC gas base rate order. The remaining $7.0
million related to BGE's electric business was charged to expense. The TVSERP
charges are not included in the tables of net periodic pension and
postretirement benefit costs included in this section.
Postretirement Benefits
- -----------------------
We sponsor defined benefit postretirement health care and life insurance plans
which cover nearly all BGE employees and certain employees of our subsidiaries.
Generally, we calculate the benefits under these plans based on age, years of
service, and pension benefit levels. We do not fund these plans.
For nearly all of the health care plans, retirees make contributions to cover
a portion of the plan costs. Contributions for employees who retire after June
30, 1992 are calculated based on age and years of service. The amount of retiree
contributions increases based on expected increases in medical costs. For the
life insurance plan, retirees do not make contributions to cover a portion of
the plan costs.
Effective January 1, 1993, we adopted SFAS No. 106, Employers' Accounting for
Postretirement Benefits Other Than Pensions. The adoption of that statement
caused:
. a transition obligation, which we are amortizing over 20 years, and
. an increase in annual postretirement benefit costs.
For our nonregulated businesses, we expense all postretirement benefit costs.
For our regulated utility business, we accounted for the increase in annual
postretirement benefit costs under two Maryland PSC rate orders:
. in an April 1993 rate order, the Maryland PSC allowed us to expense one-
half and defer, as a regulatory asset (see Note 5), the other half of the
increase in annual postretirement benefit costs related to our regulated
electric and gas businesses, and
. in a November 1995 rate order, the Maryland PSC allowed us to expense all
of the increase in annual postretirement benefit costs related to our
regulated gas business.
Beginning in 1998, the Maryland PSC authorized us to:
. expense all of the increase in annual postretirement benefit costs related
to our regulated electric business, and
. amortize the regulatory asset for postretirement benefit costs related to
our regulated electric and gas businesses over 15 years.
Obligations, Assets, and Funded Status
- --------------------------------------
We show the change in the benefit obligations, plan assets, and funded status of
the pension and postretirement benefit plans in the following tables:
Pension Postretirement
Benefits Benefits
2000 1999 2000 1999
- ----------------------------------------------------------------------------
(In millions)
Change in benefit obligation
Benefit obligation at
January 1 $1,016.7 $1,031.3 $358.7 $383.1
Service cost 25.4 26.1 7.7 8.6
Interest cost 73.1 65.3 26.6 24.4
Plan participants'
contributions -- -- 2.8 2.0
Actuarial (gain) loss 0.8 (93.0) 40.9 (34.2)
Plan amendments 6.7 44.6 (41.1) (5.0)
TVSERP charge 7.6 -- 2.4 --
Benefits paid (85.2) (57.6) (22.1) (20.2)
- ----------------------------------------------------------------------------
Benefit obligation at
December 31 $1,045.1 $1,016.7 $375.9 $358.7
============================================================================
Pension Postretirement
Benefits Benefits
2000 1999 2000 1999
- ----------------------------------------------------------------------------
(In millions)
Change in plan assets
Fair value of plan
assets at
January 1 $1,084.9 $ 985.5 $ -- $ --
Actual return on
plan assets 3.7 139.4 -- --
Employer contribution 26.7 17.6 19.3 18.2
Plan participants'
contributions -- -- 2.8 2.0
Benefits paid (85.2) (57.6) (22.1) (20.2)
- ----------------------------------------------------------------------------
Fair value of plan
assets at
December 31 $1,030.1 $1,084.9 $ -- $ --
============================================================================
Pension Postretirement
Benefits Benefits
2000 1999 2000 1999
- -----------------------------------------------------------------------------
(In millions)
Funded Status
Funded Status at
December 31 $(15.0) $ 68.2 $(375.9) $(358.7)
Unrecognized net
actuarial (gain) loss 49.2 (27.2) 61.4 23.6
Unrecognized prior
service cost 59.2 59.0 (0.4) (0.1)
Unrecognized
transition obligation -- -- 94.8 143.4
Unamortized net asset
from adoption of
SFAS No. 87 (0.2) (0.5) -- --
- -----------------------------------------------------------------------------
Prepaid (accrued)
benefit cost $ 93.2 $ 99.5 $(220.1) $(191.8)
=============================================================================
Net Periodic Benefit Cost
- -------------------------
We show the components of net periodic pension benefit cost in the following
table:
Year Ended December 31, 2000 1999 1998
- ---------------------------------------------------------------------------------------------
(In millions)
Components of net periodic
pension benefit cost
Service cost $ 25.4 $ 26.1 $ 21.6
Interest cost 73.1 65.3 63.0
Expected return on plan assets (83.6) (76.6) (72.1)
Amortization of transition obligation (0.2) (0.2) (0.2)
Amortization of prior
service cost 6.5 2.5 2.5
Recognized net actuarial loss 2.6 10.1 5.6
Amount capitalized as
construction cost (3.4) (4.2) (3.8)
- ---------------------------------------------------------------------------------------------
Net periodic pension
benefit cost $ 20.4 $ 23.0 $ 16.6
=============================================================================================
We show the components of net periodic postretirement benefit cost in the
following table:
Year Ended December 31, 2000 1999 1998
- -------------------------------------------------------------------------------------------
(In millions)
Components of net periodic
postretirement benefit cost
Service cost $ 7.7 $ 8.6 $ 6.6
Interest cost 26.6 24.4 23.4
Amortization of transition obligation 7.9 11.0 11.4
Recognized net actuarial loss 3.1 1.9 0.2
Amount capitalized as
construction cost (10.8) (9.4) (8.1)
- -------------------------------------------------------------------------------------------
Net periodic postretirement
benefit cost $ 34.5 $ 36.5 $ 33.5
===========================================================================================
Assumptions
- -----------
We made the assumptions below to calculate our pension and postretirement
benefit obligations.
Pension Postretirement
Benefits Benefits
At December 31, 2000 1999 2000 1999
- ----------------------------------------------------------
Discount rate 7.50% 7.25% 7.50% 7.25%
Expected return on
plan assets 9.00 9.00 N/A N/A
Rate of compensation
increase 4.00 4.00 4.00 4.00
We assumed the health care inflation rates to be:
. in 2000, 10.7% for Medicare-eligible retirees and 12.3% for retirees not
covered by Medicare, and
. in 2001, 6.5% for Medicare-eligible retirees and 8.0% for retirees not
covered by Medicare.
After 2001, we assumed both inflation rates will decrease by 0.5% annually to
a rate of 5.5% in the years 2003 and 2006, respectively. After these dates, the
inflation rate will remain at 5.5%.
A one-percent increase in the health care inflation rate from the assumed
rates would increase the accumulated postretirement benefit obligation by
approximately $51.7 million as of December 31, 2000 and would increase the
combined service and interest costs of the postretirement benefit cost by
approximately $5.5 million annually.
A one-percent decrease in the health care inflation rate from the assumed
rates would decrease the accumulated postretirement benefit obligation by
approximately $41.5 million as of December 31, 2000 and would decrease the
combined service and interest costs of the postretirement benefit cost by
approximately $4.4 million annually.
Other Postemployment Benefits
- -----------------------------
We provide the following postemployment benefits:
. health and life insurance benefits to our employees and certain employees
of our subsidiaries who are found to be disabled under our Disability
Insurance Plan, and
. income replacement payments for employees found to be disabled before
November 1995 (payments for employees found to be disabled after that date
are paid by an insurance company, and the cost is paid by employees).
The liability for these benefits totaled $46.7 million as of December 31,
2000 and $46.5 million as of December 31, 1999.
Effective December 31, 1993, we adopted SFAS No. 112, Employers' Accounting
for Postemployment Benefits. We deferred, as a regulatory asset (see Note 5),
the postemployment benefit liability attributable to our regulated utility
business as of December 31, 1993, consistent with the Maryland PSC's orders for
postretirement benefits (described earlier in this note).
We began to amortize the regulatory asset over 15 years beginning in 1998.
The Maryland PSC authorized us to reflect this change in our regulated electric
and gas base rates to recover the higher costs in 1998.
We assumed the discount rate for other postemployment benefits to be 5.5% in
2000 and 1999.
Employee Savings Plan Benefits
- ------------------------------
We also sponsor a defined contribution savings plan that is offered to all
eligible employees of Constellation Energy and certain employees of our
subsidiaries. In a defined contribution plan, the benefits a participant is to
receive result from regular contributions to a participant account. Under this
plan, we make matching contributions to participant accounts. We made matching
contributions to this plan of:
. $10.8 million in 2000,
. $10.4 million in 1999, and
. $10.1 million in 1998.
7 SHORT-TERM BORROWINGS
Our short-term borrowings may include bank loans, commercial paper, and bank
lines of credit. Short-term borrowings mature within one year from the date of
issuance. We pay commitment fees to banks for providing us lines of credit. When
we borrow under the lines of credit, we pay market interest rates.
Constellation Energy
- --------------------
Constellation Energy had commercial paper outstanding of $198.7 million at
December 31, 2000 and $242.5 million at December 31, 1999.
Constellation Energy had unused committed bank lines of credit of $565.0
million at December 31, 2000 and $295.0 million at December 31, 1999 for short-
term financial needs, including letters of credit. These agreements also support
Constellation Energy's commercial paper program. Letters of credit issued under
these facilities totaled $180.3 million at December 31, 2000 and $23.1 million
at December 31, 1999. In addition, Constellation Energy had $116.9 million in
letters of credit outstanding at December 31, 2000 that were issued under
separate credit facilities.
The weighted-average effective interest rate for Constellation Energy's
commercial paper were 6.31% for the year ended December 31, 2000 and 5.68% for
1999.
BGE
- ---
BGE had commercial paper outstanding of $32.1 million at December 31, 2000 and
$129.0 million at December 31, 1999.
At December 31, 2000, BGE had unused committed bank lines of credit totaling
$218.0 million supporting the commercial paper program compared to $183.0
million at December 31, 1999.
The weighted-average effective interest rates for BGE's commercial paper were
6.36% for the year ended December 31, 2000 and 5.25% for 1999.
Other Nonregulated Businesses
- -----------------------------
Our other nonregulated businesses had short-term borrowings outstanding of $12.8
million at December 31, 2000. The weighted-average effective interest rate for
our other nonregulated businesses' short-term borrowings was 8.59% for the year
ended December 31, 2000.
8 LONG-TERM DEBT
Long-term debt matures in one year or more from the date of issuance. We
summarize our long-term debt in the Consolidated Statements of Capitalization.
As you read this section, it may be helpful to refer to those statements.
Constellation Energy
- --------------------
In 2000, Constellation Energy issued $1.0 billion in long-term debt. On April 4,
2000, we issued $300.0 million of 7 7/8% Fixed Rate Notes, due April 1, 2005 and
$200.0 million of Floating Rate Notes, due April 4, 2003. Interest on the
floating rate notes is reset quarterly.
On June 21, 2000, we issued $300.0 million of Extendible Notes, due June 21,
2010. The interest rate on these notes resets quarterly. On June 21, 2001, the
notes may be remarketed for an additional period or redeemed for a purchase
price equal to 100% of their principal amount, plus accrued interest.
On October 19, 2000, we issued $200.0 million of Floating Rate Reset Notes,
due March 15, 2002. We redeemed these notes on January 17, 2001 at par.
On January 17, 2001, we issued $400.0 million of Mandatorily Redeemable
Floating Rate Notes, due January 17, 2002. These notes are mandatorily
redeemable at a purchase price equal to 100% of their principal amount, plus
accrued interest, at least five days prior to the separation of our domestic
merchant energy business from our remaining businesses.
In connection with the initiative to separate our businesses, Constellation
Energy expects to redeem all of its outstanding debt at or prior to the
separation. The redemption will occur through a combination of open market
purchases, tender offers, and redemption calls. We expect to fund this
redemption with short-term debt or other credit facilities, and to refinance
this debt longer term after the separation.
BGE
- ---
BGE's First Refunding Mortgage Bonds
- ------------------------------------
BGE's first refunding mortgage bonds are secured by a mortgage lien on all of
its assets, including all utility properties and franchises and its subsidiary
capital stock. Capital stock pledged under the mortgage is that of Safe Harbor
Water Power Corporation and Constellation Enterprises, Inc. The generating
assets BGE transferred to subsidiaries of Constellation Energy also remain
subject to the lien of BGE's mortgage.
BGE is required to make an annual sinking fund payment each August 1 to the
mortgage trustee. The amount of the payment is equal to 1% of the highest
principal amount of bonds outstanding during the preceding 12 months. The
trustee uses these funds to retire bonds from any series through repurchases or
calls for early redemption. However, the trustee cannot call the following bonds
for early redemption:
. 8 3/8% Series, due 2001 . 5 1/2% Series, due 2004
. 7 1/4% Series, due 2002 . 7 1/2% Series, due 2007
. 6 1/2% Series, due 2003 . 6 5/8% Series, due 2008
. 6 1/8% Series, due 2003
Holders of the Remarketed Floating Rate Series due September 1, 2006 have the
option to require BGE to repurchase their bonds at face value on September 1 of
each year. BGE is required to repurchase and retire at par any bonds that are
not remarketed or purchased by the remarketing agent. BGE also has the option to
redeem all or some of these bonds at face value each September 1.
BGE's Other Long-Term Debt
- --------------------------
On July 1, 2000, BGE transferred $278.0 million of tax-exempt debt to our
domestic merchant energy business related to the transferred assets. At December
31, 2000, BGE remains contingently liable for this debt.
On October 19, 2000, BGE issued $200.0 million of Floating Rate Reset Notes,
due October 19, 2001. BGE can redeem these notes at 100% of the principal
amount.
On December 20, 2000, BGE issued $173.0 million of 6.75% Remarketable and
Redeemable Securities (ROARS) due December 15, 2012. The ROARS contain an option
for the underwriters to remarket the ROARS on December 15, 2002. If the
underwriters do not elect to remarket the ROARS on that date, then BGE must
redeem the ROARS at 100% of the principal amount on December 15, 2002.
We show the weighted-average interest rates and maturity dates for BGE's
fixed-rate medium-term notes outstanding at December 31, 2000 in the following
table.
Weighted-Average Maturity
Series Interest Rate Date
- -----------------------------------------
B 8.77% 2002-2006
C 7.97 2003
D 6.66 2001-2006
E 6.66 2006-2012
G 6.08 2002-2008
Some of the medium-term notes include a "put option." These put options allow
the holders to sell their notes back to BGE on the put option dates at a price
equal to 100% of the principal amount. The following is a summary of medium-term
notes with put options.
Series E Notes Principal Put Option Dates
- --------------------------------------------------
(In millions)
6.75%, due 2012 $60.0 June 2002 and 2007
6.75%, due 2012 $25.0 June 2004 and 2007
6.73%, due 2012 $25.0 June 2004 and 2007
BGE has a $25 million revolving credit agreement that is available through
2003. At December 31, 2000 and 1999, BGE did not have any borrowings under
revolving credit agreements. The bank charges us commitment fees based on the
daily average of the unborrowed amount, and we pay market interest rates on any
borrowings. This agreement also supports BGE's commercial paper program, as
described in Note 7.
BGE Obligated Mandatorily Redeemable Trust Preferred Securities
- ---------------------------------------------------------------
On June 15, 1998, BGE Capital Trust I (Trust), a Delaware business trust
established by BGE, issued 10,000,000 Trust Originated Preferred Securities
(TOPrS) for $250 million ($25 liquidation amount per preferred security) with a
distribution rate of 7.16%.
The Trust used the net proceeds from the issuance of the common securities and
the preferred securities to purchase a series of 7.16% Deferrable Interest
Subordinated Debentures due June 30, 2038 (debentures) from BGE in the aggregate
principal amount of $257.7 million with the same terms as the TOPrS. The Trust
must redeem the TOPrS at $25 per preferred security plus accrued but unpaid
distributions when the debentures are paid at maturity or upon any earlier
redemption. BGE has the option to redeem the debentures at any time on or after
June 15, 2003 or at any time when certain tax or other events occur.
The interest paid on the debentures, which the Trust will use to make
distributions on the TOPrS, is included in "Interest expense (net)" in the
Consolidated Statements of Income and is deductible for income tax purposes.
BGE fully and unconditionally guarantees the TOPrS based on its various
obligations relating to the trust agreement, indentures, debentures, and the
preferred security guarantee agreement.
The debentures are the only assets of the Trust. The Trust is wholly owned by
BGE because it owns all the common securities of the Trust that have general
voting power.
For the payment of dividends and in the event of liquidation of BGE, the
debentures are ranked prior to preference stock and common stock.
Other Nonregulated Businesses
- -----------------------------
Revolving Credit Agreement
- --------------------------
ComfortLink has a $50 million unsecured revolving credit agreement that matures
September 26, 2001. Under the terms of the agreement, ComfortLink has the option
to obtain loans at various rates for terms up to nine months. ComfortLink pays a
facility fee on the total amount of the commitment. Under this agreement,
ComfortLink had outstanding $34 million at December 31, 2000 and $33 million at
December 31, 1999.
Mortgage and Construction Loans
- -------------------------------
Our nonregulated businesses' mortgage and construction loans have varying terms.
The following mortgage notes require monthly principal and interest payments:
. 8.00%, due in 2001 . 9.65%, due in 2028
. 4.25%, due in 2009 . 8.00%, due in 2033
The variable rate mortgage notes and construction loans require periodic
payment of principal and interest.
Unsecured Notes
- ---------------
The unsecured notes mature on the following schedule:
Amount
- ----------------------------------------------------------------
(In millions)
7.66%, due May 5, 2001 $135.0
5.67%, due May 5, 2001 152.0
- ----------------------------------------------------------------
Total unsecured notes at December 31, 2000 $287.0
================================================================
Maturities of Long-Term Debt
- ----------------------------
All of our long-term borrowings mature on the following schedule (includes
sinking fund requirements):
Constellation Nonregulated
Year Energy Businesses BGE
- --------------------------------------------------------------------------------
(In millions)
2001 $ -- $318.9 $ 481.2
2002 200.0 15.3 319.8
2003 200.0 0.8 285.7
2004 -- 8.3 155.3
2005 300.0 6.1 46.9
Thereafter 300.0 320.6 1,112.4
- --------------------------------------------------------------------------------
Total long-term debt at
December 31, 2000 $1,000.0 $670.0 $2,401.3
================================================================================
At December 31, 2000, BGE had long-term loans totaling $221.5 million that
mature after 2002 (including $110.0 million of medium-term notes discussed in
this Note under "BGE's Other Long-Term Debt") that lenders could potentially
require us to repay early. Of this amount, $111.5 million could be repaid in
2001, $60.0 million in 2002, and $50.0 million thereafter. At December 31, 2000,
$86.5 million is classified as current portion of long-term debt as a result of
these provisions.
At December 31, 2000, our nonregulated businesses had long-term loans totaling
$20.0 million that mature after 2002 that lenders could potentially require us
to repay early. This amount is classified as current portion of long-term debt
as a result of these repayment provisions.
Weighted-Average Interest Rates for Variable Rate Debt
- ------------------------------------------------------
Our weighted-average interest rates for variable rate debt were:
Year ended December 31, 2000 1999
- ----------------------------------------------------------
Nonregulated Businesses
(including Constellation Energy)
Floating rate notes 6.98% --%
Loans under credit agreement 6.64 5.68
Mortgage and construction loans 7.78 6.65
Tax-exempt debt transferred from BGE 4.26 --
BGE
Remarketed floating rate series
mortgage bonds 6.59% 5.19%
Floating rate series mortgage bonds -- 5.41
Floating rate reset notes 7.27 --
Medium-term notes, Series G 6.58 5.38
Medium-term notes, Series H 6.58 5.64
Pollution control loan -- 3.22
Port facilities loan -- 3.24
Adjustable rate pollution control loan -- 3.59
Economic development plan -- 3.26
Variable rate pollution control plan -- 3.30
9 LEASES
There are two types of leases--operating and capital. Capital leases qualify as
sales or purchases of property and are reported in the Consolidated Balance
Sheets. Capital leases are not material in amount. All other leases are
operating leases and are reported in the Consolidated Statements of Income. We
present information about our operating leases below.
Outgoing Lease Payments
- -----------------------
We, as lessee, lease some facilities and equipment used in our businesses. The
lease agreements expire on various dates and have various renewal options. We
expense all lease payments associated with our regulated utility operations.
Lease expense was:
. $11.3 million in 2000,
. $12.2 million in 1999, and
. $10.5 million in 1998.
At December 31, 2000, we owed future minimum payments for long-term,
noncancelable, operating leases as follows:
Year
- ----------------------------------------------------------
(In millions)
2001 $ 7.8
2002 6.4
2003 5.0
2004 3.5
2005 2.9
Thereafter 8.1
- ----------------------------------------------------------
Total future minimum lease payments $33.7
==========================================================
10 COMMITMENTS, GUARANTEES, AND CONTINGENCIES
Commitments
- -----------
We have made substantial commitments in connection with our domestic merchant
energy business construction program for future years. In addition, we have two
long-term contracts for the purchase of electric generating capacity and energy.
The contracts expire in 2001 and 2013. We made payments under these contracts
of:
. $77.3 million in 2000,
. $67.8 million in 1999, and
. $70.7 million in 1998.
At December 31, 2000, we estimate our future payments for capacity and energy
that we are obligated to buy under these contracts to be:
Year
- --------------------------------------------------------------
(In millions)
2001 $ 40.2
2002 16.4
2003 16.0
2004 15.5
2005 15.1
Thereafter 113.6
- --------------------------------------------------------------
Total estimated future payments for
capacity and energy under long-term contracts $216.8
==============================================================
Portions of these contracts became uneconomic upon the deregulation of
electric generation. Therefore, we recorded a charge and accrued a corresponding
liability based on the net present value of the excess of estimated contract
costs over the market-based revenues to recover these costs over the remaining
terms of the contracts as discussed in Note 4. At December 31, 2000, the accrued
portion of these contracts was $21.2 million.
Our domestic merchant energy business has committed to contribute additional
capital and to make additional loans to some affiliates, joint ventures, and
partnerships in which they have an interest. At December 31, 2000, the total
amount of investment requirements committed to by our domestic merchant energy
business was $181.0 million.
BGE and BGE Home Products & Services have agreements to sell on an ongoing
basis an undivided interest in a designated pool of customer receivables. Under
the agreements, BGE can sell up to a total of $40 million, and BGE Home Products
& Services can sell up to a total of $50 million. Under the terms of the
agreements, the buyer of the receivables has limited recourse against BGE and
has no recourse against BGE Home Products & Services. BGE and BGE Home Products
& Services have recorded reserves for credit losses. At December 31, 2000, BGE
had sold $23.9 million and BGE Home Products & Services had sold $42.5 million
of receivables under these agreements.
Planned Acquisition
- -------------------
On December 12, 2000, we announced that a subsidiary of Constellation Nuclear
will purchase 1,550 megawatts of the 1,757 megawatts total generating capacity
of the Nine Mile Point nuclear power plant, located in Scriba, New York. The
subsidiary of Constellation Nuclear will buy 100 percent of Unit 1 and 82
percent of Unit 2 for $815 million, including $78 million for fuel. The sale is
expected to close in mid-2001 after receipt of all necessary regulatory
approvals. Key regulatory approvals are required from the NRC, Federal Energy
Regulatory Commission (FERC), and the New York State Public Service Commission.
One-half of the purchase price, or $407.5 million, is due at the closing of
the transaction. The sellers will finance the remaining half of the purchase
price at an 11.0% fixed rate for a period of five years with equal annual
principal repayments. Nine Mile Point includes two boiling-water reactors. Unit
1 is a 609-megawatt reactor that entered service in 1969. Unit 2 is a 1,148-
megawatt reactor that began operation in 1988.
Niagara Mohawk Power Corporation is the sole owner of Nine Mile Point Unit 1.
The co-owners of Nine Mile Point Unit 2 that are selling their interests include
Niagara Mohawk (41 percent), New York State Electric and Gas (18 percent),
Rochester Gas & Electric Corporation (14 percent), and Central Hudson Gas &
Electric Corporation (9 percent). The Long Island Power Authority, which owns 18
percent of Nine Mile Point Unit 2, has chosen not to sell its portion at this
time.
The terms of the transaction include power purchase agreements whereby we have
agreed to sell 90 percent of our share of the Nine Mile Point plant's output
back to the sellers for approximately 10 years at an average price of nearly $35
per megawatt-hour over the term of the power purchase agreements. The contracts
for the output of both plants are based on operation of the individual units.
The sellers will transfer approximately $450 million in decommissioning funds
at the time of closing. We believe this transfer is sufficient to meet the
decommissioning requirements for our share of the Nine Mile Point site.
Separation Initiatives
- ----------------------
On October 23, 2000, we announced three initiatives to advance our growth
strategies. The first initiative is that we entered into an agreement (the
"Agreement") with an affiliate of The Goldman Sachs Group, Inc. ("Goldman
Sachs"). Under the terms of the Agreement, Goldman Sachs will acquire up to a
17.5% equity interest in our domestic merchant energy business, which will be
consolidated under a single holding company ("Holdco"). Goldman Sachs will also
acquire a ten-year warrant for up to 13% of Holdco's common stock (subject to
certain adjustments). The warrant is exercisable six months after Holdco's
common stock becomes publicly available. The amount of common stock which
Goldman Sachs may receive upon exercise will be equal to the excess of the
market price of Holdco's common stock at the time of exercise over the exercise
price of $60 per share for all the stock subject to the warrant, divided by the
market price. Holdco may at its option pay Goldman Sachs such excess in cash.
Goldman Sachs is acquiring its interest and the warrant in exchange for $250
million in cash (subject to adjustment in certain instances) and certain assets
related to our power marketing operation. At closing, Goldman Sachs' existing
services agreement with our power marketing operation will terminate.
The second initiative is a plan to separate our domestic merchant energy
business from our remaining businesses. The separation will create two stand-
alone, publicly traded energy companies. One will be a merchant energy business
engaged in wholesale power marketing and generation under the name
"Constellation Energy Group" after the separation. The other will be a regional
retail energy delivery and energy services company, BGE Corp., which will
include BGE, our other nonregulated businesses, and our investment in Orion
Power Holdings, Inc. ("Orion").
As a result of the separation, shareholders will continue to own all of
Constellation Energy's current businesses through their ownership of the new
Constellation Energy Group and BGE Corp.
The third initiative is a change in our common stock dividend policy effective
April 2001. In a move closely aligned with our separation plan, effective April
2001, our annual dividend is expected to be set at $.48 per share. After the
business separation, BGE Corp. expects to pay initial annual dividends of $.48
per share. Constellation Energy Group, as a growing merchant energy company,
initially expects to reinvest its earnings in order to fund its growth plans and
not to pay a dividend.
The closing of the transaction with Goldman Sachs and the separation are
subject to customary closing conditions and contingent upon obtaining regulatory
approvals and a Private Letter Ruling from the Internal Revenue Service
regarding certain tax matters. The transaction and separation are expected to be
completed by mid to late 2001.
Guarantees
- ----------
At December 31, 2000, Constellation Energy issued guarantees in an amount up to
$825.8 million related to credit facilities and contractual performance of
certain of its nonregulated subsidiaries. The actual subsidiary liabilities
related to these guarantees totaled $586.6 million at December 31, 2000.
At December 31, 2000, our nonregulated businesses had guaranteed outstanding
loans and letters of credit of certain power projects and real estate projects
totaling $50.1 million. Our nonregulated businesses also guarantee certain other
borrowings of various power projects and real estate projects.
BGE guarantees two-thirds of certain debt of Safe Harbor Water Power
Corporation. The maximum amount of our guarantee is $23 million. At December 31,
2000, Safe Harbor Water Power Corporation had outstanding debt of $20.0 million,
of which $13.3 million is guaranteed by BGE.
We assess the risk of loss from these guarantees to be minimal.
Environmental Matters
- ---------------------
We are subject to regulation by various federal, state and local authorities
with regard to:
. air quality,
. water quality,
. waste disposal, and
. other environmental matters.
We discuss the significant matters below.
Clean Air
- ---------
The Clean Air Act of 1990 contains two titles designed to reduce emissions of
sulfur dioxide and nitrogen oxide (NOx) from electric generating stations--Title
IV and Title I.
Title IV addresses emissions of sulfur dioxide. Compliance is required in two
phases:
. Phase I became effective January 1, 1995. We met the requirements of this
phase by installing flue gas desulfurization systems, switching fuels, and
retiring some units.
. Phase II became effective January 1, 2000. We met the compliance
requirements through a combination of switching fuels and allowance trading.
We will meet the ongoing compliance requirements through a combination of
switching fuels and allowance trading.
Title I addresses emissions of NOx. The Maryland Department of the Environment
(MDE) issued regulations, effective October 18, 1999, which required up to 65%
NOx emissions reductions by May 1, 2000. We entered into a settlement agreement
with the MDE since we could not meet this deadline. Under the terms of the
settlement agreement, we will install emissions reduction equipment at two sites
by May 2002. In the meantime, we are taking steps to control NOx emissions at
our generating plants.
The Environmental Protection Agency (EPA) issued a final rule in September
1998 that required up to 85% NOx emissions reduction by 22 states including
Maryland and Pennsylvania. Maryland and Pennsylvania expect to meet the
requirements of the rule by 2003. The emissions reduction equipment
installations discussed above will allow us to meet these requirements.
We currently estimate that the controls needed at our generating plants to
meet the MDE's 65% NOx emission reduction requirements will cost approximately
$150 million. Through December 31, 2000, we have spent approximately $115
million to meet the 65% reduction requirements. We estimate the additional cost
for the EPA's 85% reduction requirements to be approximately $55 million by the
end of 2002.
In July 1997, the EPA published new National Ambient Air Quality Standards for
very fine particulates and revised standards for ozone attainment. In 1999,
these new standards were successfully challenged in court. The EPA appealed the
1999 court rulings to the Supreme Court. In May 2000, the Supreme Court decided
to hear the EPA's appeal. While these standards may require increased controls
at our fossil generating plants in the future, implementation, if required,
would be delayed for several years. We cannot estimate the cost of these
increased controls at this time because the states, including Maryland and
Pennsylvania, still need to determine what reductions in pollutants will be
necessary to meet the EPA standards.
In December 2000, the EPA issued a determination that coal-fired power plant
mercury emissions will be controlled. Final regulations are expected to be
issued in 2004 with controls required by 2007. The costs of these controls
cannot be estimated at this time since the level of control or system to
implement them have not yet been established.
We received letters from the EPA requesting us to provide certain information
under Section 114 of the federal Clean Air Act regarding some of our electric
generating plants. This information is to determine compliance with the Clean
Air Act and state implementation plan requirements, including potential
application of federal New Source Performance Standards. In general, such
standards can require the installation of additional air pollution control
equipment upon the major modification of an existing plant. We believe our
generating plants have been operated in accordance with the Clean Air Act and
the rules implementing the Clean Air Act. However, we cannot estimate the impact
of this inquiry on our generating plants, and our financial results, at this
time.
Waste Disposal
- --------------
The EPA and several state agencies have notified us that we are considered a
potentially responsible party with respect to the cleanup of certain
environmentally contaminated sites owned and operated by others. We cannot
estimate the cleanup costs for all of these sites.
We can, however, estimate that our current 15.47% share of the reasonably
possible cleanup costs at one of these sites, Metal Bank of America, a metal
reclaimer in Philadelphia, could be as much as $2.3 million higher than amounts
we have recorded as a liability on our Consolidated Balance Sheets. This
estimate is based on a Record of Decision issued by the EPA.
Also, we are coordinating investigation of several sites where gas was
manufactured in the past. The investigation of these sites includes reviewing
possible actions to remove coal tar. In late December 1996, we signed a consent
order with the MDE that required us to implement remedial action plans for
contamination at and around the Spring Gardens site, located in Baltimore,
Maryland. We submitted the required remedial action plans and they were approved
by the MDE. Based on the remedial action plans, the costs we consider to be
probable to remedy the contamination are estimated to total $47 million. We have
recorded these costs as a liability on our Consolidated Balance Sheets and have
deferred these costs, net of accumulated amortization and amounts we recovered
from insurance companies, as a regulatory asset. Because of the results of
studies at these sites, it is reasonably possible that these additional costs
could exceed the amount we recognized by approximately $14 million. We discuss
this further in Note 5. Through December 31, 2000, we have spent approximately
$35 million for remediation at this site.
We do not expect the cleanup costs of the remaining sites to have a material
effect on our financial results.
Our potential environmental liabilities and pending environmental actions are
described further in our most recent Annual Report on Form 10-K in Item 1.
Business--Environmental Matters.
Litigation
- ----------
In the normal course of business, we are involved in various legal proceedings.
We discuss the significant matters below.
Employment Discrimination
- -------------------------
Miller v. Baltimore Gas and Electric Company, et al.--This action was filed on
September 20, 2000 in the U.S. District Court for the District of Maryland.
Besides BGE, Constellation Energy Group, Constellation Nuclear and Calvert
Cliffs Nuclear Power Plant are also named defendants. The action seeks class
certification for approximately 150 past and present employees and alleges
racial discrimination at Calvert Cliffs Nuclear Power Plant. The amount of
damages is unspecified, however the plaintiffs seek back and front pay, along
with compensatory and punitive damages. We believe this case is without merit.
However, we cannot predict the timing, or outcome, of it or its possible effect
on our, or BGE's, financial results.
Moore v. Constellation Energy Group--This action was filed on October 23, 2000
in the U.S. District Court for the District of Maryland by an employee alleging
employment discrimination. Besides Constellation Energy, BGE and Constellation
Holdings, Inc. are also named defendants. The Equal Employment Opportunity
Commission has previously concluded that it was unable to establish a violation
of law. The plaintiff seeks, among other things, unspecific monetary damages and
back pay. We believe this case is without merit.
Asbestos
- --------
Since 1993, we have been involved in several actions concerning asbestos. The
actions are based upon the theory of "premises liability," alleging that we knew
of and exposed individuals to an asbestos hazard. The actions relate to two
types of claims.
The first type is direct claims by individuals exposed to asbestos. We
described these claims in a Report on Form 8-K filed August 20, 1993. We are
involved in these claims with approximately 70 other defendants. Approximately
530 individuals that were never employees of BGE each claim $6 million in
damages ($2 million compensatory and $4 million punitive). These claims were
filed in the Circuit Court for Baltimore City, Maryland in the summer of 1993.
We do not know the specific facts necessary to estimate our potential liability
for these claims. The specific facts we do not know include:
. the identity of our facilities at which the plaintiffs allegedly worked as
contractors,
. the names of the plaintiff's employers, and
. the date on which the exposure allegedly occurred.
To date, 29 of these cases were settled for amounts that were not significant.
The second type is claims by one manufacturer--Pittsburgh Corning Corp.
(PCC)--against us and approximately eight others, as third-party defendants. On
April 17, 2000, PCC declared bankruptcy and we do not expect PCC to prosecute
this claim.
These claims relate to approximately 1,500 individual plaintiffs and were
filed in the Circuit Court for Baltimore City, Maryland in the fall of 1993. To
date, about 350 cases have been resolved, all without any payment by BGE. We do
not know the specific facts necessary to estimate our potential liability for
these claims. The specific facts we do not know include:
. the identity of our facilities containing asbestos manufactured by the
manufacturer,
. the relationship (if any) of each of the individual plaintiffs to us,
. the settlement amounts for any individual plaintiffs who are shown to have
had a relationship to us, and
. the dates on which/places at which the exposure allegedly occurred.
Until the relevant facts for both types of claims are determined, we are
unable to estimate what our liability, if any, might be. Although insurance and
hold harmless agreements from contractors who employed the plaintiffs may cover
a portion of any awards in the actions, our potential liability could be
material.
Restructuring Order
- -------------------
In early December 1999, the Mid-Atlantic Power Supply Association (MAPSA),
Trigen-Baltimore Energy Corporation and Sweetheart Cup Company, Inc. filed
appeals of the Restructuring Order, which were consolidated in the Baltimore
City Circuit Court. MAPSA also filed a motion to delay implementation of the
Restructuring Order, pending a decision on the merits of the appeals by the
court.
On April 21, 2000, the Circuit Court dismissed MAPSA's appeal based on a lack
of standing (the right of a party to bring a lawsuit to court) and denied its
motion for a delay of the Restructuring Order. However, MAPSA filed an appeal of
this decision. On May 24, 2000, the Circuit Court dismissed both the Trigen and
Sweetheart Cup appeals.
MAPSA subsequently filed several appeals with the Maryland Court of Special
Appeals, the Maryland Court of Appeals, and the Baltimore City Circuit Court.
The effect of the appeals was to delay the implementation of customer choice in
BGE's service territory.
However, on August 4, 2000, the delay was rescinded and BGE retroactively
adjusted its rates as if customer choice had been implemented July 1, 2000.
On September 29, 2000, the Baltimore City Circuit Court issued an order
upholding the Restructuring Order.
On October 27, 2000, MAPSA filed an appeal with the Maryland Court of Special
Appeals challenging the September 29, 2000 order issued by the Circuit Court. We
believe that this appeal is without merit. However, we cannot predict the timing
or outcome of this case, which, if adverse, could have a material effect on our,
and BGE's, financial results.
Asset Transfer Order
- --------------------
On July 6, 2000, MAPSA and Shell Energy LLC filed, in the Circuit Court for
Baltimore City, a petition for review and a delay of the Maryland PSC's order
approving the transfer of BGE's generation assets issued on June 19, 2000. The
Court denied MAPSA's request for a delay on August 4, 2000, and after a hearing
on the petition on August 23, 2000 issued an order on September 29, 2000
upholding the Maryland PSC's order on the asset transfer. On October 27, 2000,
MAPSA filed an appeal with the Maryland Court of Special Appeals challenging the
September 29, 2000 order issued by the Circuit Court. We also believe that this
appeal is without merit. However, we cannot predict the timing or outcome of
this case, which, if adverse, could have a material effect on our, and BGE's,
financial results.
Calvert Cliffs' License Renewal
- -------------------------------
On April 11, 2000 the United States Court of Appeals for the District of
Columbia Circuit, in National Whistleblowers Center v. Nuclear Regulatory
Commission and Baltimore Gas and Electric Company, upheld the NRC's denial of
the Center's motion to intervene in BGE's license renewal proceeding. The NRC
had denied the Center's motion to intervene for failing to file timely
contentions. The Center filed a petition for certiorari, a request to hear an
appeal, with the U.S. Supreme Court, which was denied.
Nuclear Insurance
- -----------------
If there were an accident or an extended outage at either unit of the Calvert
Cliffs Nuclear Power Plant (Calvert Cliffs), it could have a substantial adverse
financial effect on us. The primary contingencies that would result from an
incident at Calvert Cliffs could include:
. physical damage to the plant,
. recoverability of replacement power costs, and
. our liability to third parties for property damage and bodily injury.
We have insurance policies that cover these contingencies, but the policies
have certain industry standard exclusions. Furthermore, the costs that could
result from a covered major accident or a covered extended outage at either of
the Calvert Cliffs units could exceed our insurance coverage limits.
Insurance for Calvert Cliffs and Third Party Claims
- ---------------------------------------------------
For physical damage to Calvert Cliffs, we have $2.75 billion of property
insurance from an industry mutual insurance company. If an outage at either of
the two units at Calvert Cliffs is caused by an insured physical damage loss and
lasts more than 12 weeks, we have insurance coverage for replacement power costs
up to $490.0 million per unit, provided by an industry mutual insurance company.
This amount can be reduced by up to $98.0 million per unit if an outage at both
units of the plant is caused by a single insured physical damage loss. If
accidents at any insured plants cause a shortfall of funds at the industry
mutual insurance company, all policyholders could be assessed, with our share
being up to $15.4 million.
In addition we, as well as others, could be charged for a portion of any third
party claims associated with a nuclear incident at any commercial nuclear power
plant in the country. At December 31, 2000, the limit for third party claims
from a nuclear incident is $9.54 billion under the provisions of the Price
Anderson Act. If third party claims exceed $200 million (the amount of primary
insurance), our share of the total liability for third party claims could be up
to $176.2 million per incident. That amount would be payable at a rate of $20
million per year.
Insurance for Worker Radiation Claims
- -------------------------------------
As an operator of a commercial nuclear power plant in the United States, we are
required to purchase insurance to cover radiation injury claims of certain
nuclear workers. On January 1, 1998, a new insurance policy became effective for
all operators requiring coverage for current operations. Waiving the right to
make additional claims under the old policy was a condition for acceptance under
the new policy. We describe both the old and new policies below.
Nuclear worker claims reported on or after January 1, 1998 are covered by a
new insurance policy with an annual industry aggregate limit of $200 million for
radiation injury claims against all those insured by this policy.
All nuclear worker claims reported prior to January 1, 1998 are still covered
by the old insurance policies. Insureds under the old policies, with no current
operations, are not required to purchase the new policy described above, and may
still make claims against the old policies for the next seven years. If
radiation injury claims under these old policies exceed the policy reserves, all
policyholders could be assessed, with our share being up to $6.3 million.
If claims under these polices exceed the coverage limits, the provisions of
the Price Anderson Act (discussed in this section) would apply.
California Power Purchase Agreements
- ------------------------------------
Constellation Power, Inc. and subsidiaries and Constellation Investments, Inc.
(whose power projects are managed by Constellation Power) have $297.9 million
invested in 14 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:
. a fixed rate for capacity and energy for 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.
Generally, a "capacity rate" is paid to a power plant for its availability to
supply electricity, and an "energy rate" is paid for the electricity actually
generated. "Avoided cost" generally is the cost of a utility's cheapest next-
available source of generation to service the demands on its system.
We use the term "transitioned" to describe when the 10-year periods for fixed
energy rates have expired for these power generation projects and they began
supplying electricity at variable rates. In 2000, the last four projects
transitioned to variable rates.
Prior to 2000, the projects that have transitioned to variable rates have had
lower revenues under variable rates than they did under fixed rates. In 2000,
the prices received under these agreements were higher due to the increases in
the variable-rate pricing terms.
11 FAIR VALUE OF ASSETS AND LIABILITIES FROM ENERGY TRADING ACTIVITIES AND
FINANCIAL INSTRUMENTS
Assets and Liabilities from Energy Trading Activities
- -----------------------------------------------------
As described in Note 1, we report assets and liabilities from energy trading
activities at fair value.
At December 31, 2000, the notional amounts and terms of trading instruments at
Constellation Power Source were as follows:
Maximum
Terms in
Purchased Sold Years
- ----------------------------------------------------------------
(Notional amounts in millions)
Electric energy
(megawatt-hours) 391.3 144.2 21
Electric capacity
(megawatt-hours) 66.8 84.9 21
Oil (barrels) 8.5 11.9 5
Natural gas (millions
of British thermal units) 373.5 316.3 9
Notional amounts express the contractual volume of transactions but do not
necessarily represent the amounts to be exchanged by the parties to the
instruments. Accordingly, notional amounts do not accurately measure our
exposure to market or credit risk.
Financial Instruments
- ---------------------
The fair value of a financial instrument represents the amount at which the
instrument could be exchanged in a current transaction between willing parties,
other than in a forced sale or liquidation. Significant differences can occur
between the fair value and carrying amount of financial instruments that are
recorded at historical amounts. We used the following methods and assumptions in
estimating fair value disclosures for financial instruments.
. Cash and cash equivalents, net accounts receivable, other current assets,
certain current liabilities, short-term borrowings, current portion of long-
term debt, and certain deferred credits and other liabilities: The amounts
reported in the Consolidated Balance Sheets approximate fair value.
. Investments and other assets where it was practicable to estimate fair
value: The fair value is based on quoted market prices where available.
. Long-term debt: The fair value is based on quoted market prices where
available or by discounting remaining cash flows at current market rates.
We show the carrying amounts and fair values of financial instruments included
in our Consolidated Balance Sheets in the following table, and we describe some
of the items separately later in this section.
At December 31, 2000 1999
- ----------------------------------------------------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
- ----------------------------------------------------------------------
(In millions)
Investments and other
assets for which it is:
Practicable to
estimate fair value $349.8 $ 349.8 $ 313.3 $ 313.3
Not practicable to
estimate fair value 43.5 N/A 46.7 N/A
Fixed-rate long-term
debt 2,734.1 2,819.9 2,728.9 2,637.3
Variable-rate long-
term debt 1,331.8 1,243.3 654.8 654.8
It was not practicable to estimate the fair value of investments held by our
nonregulated businesses in:
. several financial partnerships that invest in nonpublic debt and equity
securities, and
. several partnerships that own solar powered energy production facilities.
This is because the timing and amount of cash flows from these investments are
difficult to predict. We report these investments at their original cost in our
Consolidated Balance Sheets.
The investments in financial partnerships totaled $32.7 million at December
31, 2000 and $35.8 million at December 31, 1999, representing ownership
interests up to 11%. The total assets of all of these partnerships totaled $6.1
billion at December 31, 1999 (which is the latest information available).
The investments in solar powered energy production facility partnerships
totaled $10.8 million at December 31, 2000 and $10.9 million at December 31,
1999, representing ownership interests up to 13%. The total assets of all of
these partnerships totaled $26.7 million at December 31, 1999 (which is the
latest information available).
Guarantees
- ----------
It was not practicable to determine the fair value of certain loan guarantees of
Constellation Energy and its subsidiaries. Constellation Energy guaranteed
outstanding debt of $341.0 million at December 31, 2000 and $16.5 million at
December 31, 1999. Our nonregulated businesses guaranteed outstanding debt
totaling $50.1 million at December 31, 2000 and $48.8 million at December 31,
1999. BGE guaranteed outstanding debt of $13.3 million at December 31, 2000 and
$13.6 million at December 31, 1999. We do not anticipate that we will need to
fund these guarantees.
12 STOCK-BASED COMPENSATION
As permitted by SFAS No. 123, Accounting for Stock-Based Compensation, we
measure our stock-based compensation in accordance with Accounting Principles
Board Opinion (APB) No. 25, Accounting for Stock Issued to Employees, and
related interpretations.
Under our existing long-term incentive plans, we can issue awards that include
stock options and performance-based restricted stock to officers and key
employees. Under the plans, we can issue up to a total of 6,000,000 shares for
these awards.
Stock Options
- -------------
In May 2000, our Board of Directors approved the issuance of non-qualified stock
options. The options were granted at prices not less than the market value of
the stock at the date of grant, generally become exercisable ratably over a
three-year period beginning one-year from the date of grant, and expire ten
years from the date of grant. The grants provide for the exercise of the options
on a pro-rata basis for service to date upon the separation of our businesses.
The tables below do not reflect the impact of the business separation. In
accordance with APB No. 25, no compensation expense is recognized for the stock
option awards. Summarized information for our stock option awards is as follows:
Weighted-
Average
Shares Exercise Price
- ----------------------------------------------------------------------
(In thousands, except per share amounts)
Outstanding at
January 1, 2000 -- $ --
Granted 2,462 34.64
Exercised -- --
Cancelled/Expired (42) (34.25)
- ----------------------------------------------------------------------
Outstanding at
December 31, 2000 2,420 $ 34.65
======================================================================
Exercisable at
December 31, 2000 -- --
======================================================================
Weighted-average fair value per share
of options granted during year $ 5.60
======================================================================
A summary of the weighted-average remaining contractual life and the weighted-
average exercise price of options outstanding as of December 31, 2000 is
presented below:
Weighted-
Options Average
Range of Outstanding at Weighted- Remaining
Exercise December 31, 2000 Average Contractual
Prices (In thousands) Exercise Price Life (In years)
- ------------------------------------------------------------------------------
$34.25-$40.72 2,420 $34.65 9.4
Performance-Based Restricted Stock Awards
- -----------------------------------------
In addition, we issue common stock based on meeting certain performance and
service goals that vests to participants at various times ranging from three to
five years. In accordance with APB No. 25, we recognize compensation expense for
our restricted stock awards. Compensation expense recorded was $16.3 million for
2000 and $10.5 million for 1999. Prior to 1999, compensation expense was not
material. Summarized share information for our restricted stock awards is as
follows:
2000 1999
- ---------------------------------------------------------------
(In thousands, except per share amounts)
Outstanding, beginning of year 323 350
Granted 353 358
Released to participants (277) (362)
Cancelled (22) (23)
- ---------------------------------------------------------------
Outstanding, end of year 377 323
===============================================================
Weighted-average fair value
per share of restricted stock
granted during the year $32.89 $28.61
===============================================================
Pro-forma Information
- ---------------------
Disclosure of pro-forma information regarding net income and earnings per share
is required under SFAS No. 123, which uses the fair value method. The fair
values of our stock-based awards were estimated as of the date of grant using
the Black-Scholes option pricing model based on the following weighted-average
assumptions:
2000
- ---------------------------------------------------------
Risk-free interest rate 6.37%
Expected life (in years) 10.0
Expected market price
volatility factors 21.0%
Expected dividend yields 5.7%
The effect of applying SFAS No. 123 to our stock-based awards results in net
income and earnings per share that are not materially different from amounts
reported.
13 QUARTERLY FINANCIAL DATA (UNAUDITED)
Our quarterly financial information has not been audited but, in management's
opinion, includes all adjustments necessary for a fair presentation. Our utility
business is seasonal in nature with the peak sales periods generally occurring
during the summer and winter months. Accordingly, comparisons among quarters of
a year may not represent overall trends and changes in operations.
2000 Quarterly Data
Earnings Earnings
Income Applicable Per Share
from to Common of Common
Revenue Operations Stock Stock
- ----------------------------------------------------------------------------
(In millions, except per-share amounts)
Quarter Ended
March 31 $ 992.2 $182.8 $ 72.1 $0.48
June 30 868.4 133.9 39.6 0.26
September 30 981.6 315.4 147.5 0.98
December 31 1,036.3 208.1 86.1 0.57
- ----------------------------------------------------------------------------
Year Ended
December 31 $3,878.5 $840.2 $345.3 $2.30
============================================================================
Our first quarter results include a $2.5 million after-tax expense for BGE
Employees that elected to participate in a Targeted Voluntary Special Early
Retirement Program (TVSERP) (see Note 2).
Our second quarter results include:
. a $15.0 million after-tax deregulation transition cost to a third party
incurred by our power marketing operation to provide BGE's standard offer
service requirements (see Note 2), and
. a $1.7 million after-tax expense for the TVSERP (see Note 2).
1999 Quarterly Data
Earnings Earnings
Income Applicable Per Share
from to Common of Common
Revenue Operations Stock Stock
- --------------------------------------------------------------------
(In millions, except per-share amounts)
Quarter Ended
March 31 $ 983.4 $198.1 $ 82.8 $ 0.55
June 30 858.5 163.9 68.0 0.45
September 30 1,010.2 277.7 136.1 0.91
December 31 934.1 120.2 (26.8) (0.18)
- --------------------------------------------------------------------
Year Ended
December 31 $3,786.2 $759.9 $260.1 $ 1.74
====================================================================
Our second quarter results include a $3.6 million after-tax write-down of a
financial investment (see Note 3).
Our third quarter results include:
. $7.5 million associated with Hurricane Floyd (see the "Electric Operations
and Maintenance Expenses" section of Management's Discussion and Analysis,)
. a $37.5 million deferral of revenues collected associated with the
deregulation of our electric generation business (see Note 5),
. a $17.3 million after-tax write-down of a financial investment (see Note 3),
. a $6.7 million after-tax write-off of a power project (see Note 3), and
. a $3.4 million after-tax write-down of certain senior-living facilities (see
Note 2).
Our fourth quarter results include:
. a $66.3 million extraordinary charge associated with the Restructuring Order
(see Note 4),
. the recognition of the $37.5 million of revenues that were deferred in the
third quarter (see above),
. $75 million in amortization expense for the reduction of our generation
plants associated with the Restructuring Order (see the "Electric
Depreciation and Amortization Expense" section of Management's Discussion
and Analysis),
. a $4.9 million after-tax gain on a financial investment (see Note 3),
. $12.0 million after-tax write-downs of certain power projects (see Note 3),
and
. a $2.4 million after-tax write-down of certain senior-living facilities (see
Note 2).
The sum of the quarterly earnings per share amounts may not equal the total for
the year due to the effects of rounding.