UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended March 31, 1999
Commission Exact name of registrant IRS Employer
file number as specified in its charter Identification No.
----------- --------------------------- ------------------
1-12869 CONSTELLATION ENERGY GROUP, INC. 52-1964611
1-1910 BALTIMORE GAS AND ELECTRIC COMPANY 52-0280210
Maryland
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(State of Incorporation)
39 W. Lexington Street Baltimore, Maryland 21201
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(Address of principal executive offices) (Zip Code)
410-783-5920
(Registrant's telephone number, including area code)
Not Applicable
(Former name,former address and former fiscal year,if changed since last report)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months, and (2) has been subject to such filing requirements
for the past 90 days.
Yes X No
Common Stock, without par value - 149,556,416 shares outstanding on May 3, 1999.
1
CONSTELLATION ENERGY GROUP, INC.
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PART I. FINANCIAL INFORMATION
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Item 1. Financial Statements
Consolidated Statements of Income (Unaudited)
- ---------------------------------------------
Three Months Ended March 31,
---------------------------------
1999 1998
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(In Millions, Except Per-Share Amounts)
Revenues
Electric $ 513.0 $ 499.2
Gas 192.8 180.5
Diversified businesses 226.5 186.4
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Total revenues 932.3 866.1
---------- ----------
Expenses Other Than Interest and Income Taxes
Electric fuel and purchased energy 121.1 126.5
Gas purchased for resale 102.1 98.3
Operations 135.3 126.1
Maintenance 48.9 34.2
Diversified businesses - selling, general, and administrative 176.3 144.1
Depreciation and amortization 90.3 96.5
Taxes other than income taxes 60.2 57.0
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Total expenses other than interest and income taxes 734.2 682.7
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Income From Operations 198.1 183.4
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Other Income (Expense)
Allowance for equity funds used during construction 1.7 1.7
Equity in earnings of Safe Harbor Water Power Corporation 1.3 1.2
Net other expense (3.8) (1.0)
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Total other income (expense) (0.8) 1.9
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Income Before Interest and Income Taxes 197.3 185.3
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Interest Expense
Interest charges 62.4 61.8
Capitalized interest (0.3) (1.4)
Allowance for borrowed funds used during construction (0.9) (0.9)
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Net interest expense 61.2 59.5
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Income Before Income Taxes 136.1 125.8
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Income Taxes
Current 49.6 57.3
Deferred 2.5 (9.9)
Investment tax credit adjustments (2.2) (1.8)
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Total income taxes 49.9 45.6
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Net Income 86.2 80.2
Preference Stock Dividends 3.4 5.8
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Earnings Applicable to Common Stock $ 82.8 $ 74.4
========== ==========
Average Shares of Common Stock Outstanding 149.5 147.9
Earnings Per Common Share and
Earnings Per Common Share - Assuming Dilution $0.55 $0.50
Dividends Declared Per Share of Common Stock $0.42 $0.41
Consolidated Statements of Comprehensive Income (Unaudited)
- -----------------------------------------------------------
Net income $ 86.2 $ 80.2
Other comprehensive income (expense), net of taxes (3.2) 0.9
---------- ----------
Comprehensive Income $ 83.0 $ 81.1
========== ==========
See Notes to Consolidated Financial Statements.
2
CONSTELLATION ENERGY GROUP, INC.
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PART I. FINANCIAL INFORMATION (Continued)
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Item 1. Financial Statements
Consolidated Balance Sheets
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March 31, December 31,
1999* 1998
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(In Millions)
ASSETS
Current Assets
Cash and cash equivalents $ 344.0 $ 173.7
Accounts receivable (net of allowance for uncollectibles
of $21.4 and $20.3 respectively) 422.7 401.8
Trading securities 118.5 119.7
Fuel stocks 47.2 85.4
Materials and supplies 148.3 145.1
Prepaid taxes other than income taxes 32.0 68.8
Assets from energy trading activities 215.6 160.2
Other 19.7 21.4
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Total current assets 1,348.0 1,176.1
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Investments and Other Assets
Real estate projects and investments 335.6 353.9
Power projects 641.4 656.8
Financial investments 188.9 198.0
Nuclear decommissioning trust fund 191.0 181.4
Net pension asset 102.3 108.0
Safe Harbor Water Power Corporation 34.4 34.4
Senior living facilities 99.3 93.5
Other 114.5 115.4
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Total investments and other assets 1,707.4 1,741.4
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Utility Plant
Plant in service
Electric 6,927.3 6,890.3
Gas 934.3 921.3
Common 554.3 552.8
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Total plant in service 8,415.9 8,364.4
Accumulated depreciation (3,141.7) (3,087.5)
-------------- -------------
Net plant in service 5,274.2 5,276.9
Construction work in progress 218.2 223.0
Nuclear fuel (net of amortization) 122.2 132.5
Plant held for future use 25.4 24.3
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Net utility plant 5,640.0 5,656.7
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Deferred Charges
Regulatory assets (net) 529.4 565.7
Other 58.8 55.1
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Total deferred charges 588.2 620.8
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TOTAL ASSETS $ 9,283.6 $ 9,195.0
============== =============
* Unaudited
See Notes to Consolidated Financial Statements.
3
CONSTELLATION ENERGY GROUP, INC.
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PART I. FINANCIAL INFORMATION (Continued)
- -----------------------------------------
Item 1. Financial Statements
Consolidated Balance Sheets
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March 31, December 31,
1999* 1998
-------------- -------------
(In Millions)
LIABILITIES AND CAPITALIZATION
Current Liabilities
Current portions of long-term debt and preference stock $ 510.4 $ 541.7
Accounts payable 254.6 249.6
Customer deposits 36.9 35.5
Accrued taxes 59.8 6.5
Accrued interest 66.9 58.6
Dividends declared 66.3 66.1
Accrued vacation costs 36.1 34.7
Liabilities from energy trading activities 158.2 126.2
Other 23.7 45.3
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Total current liabilities 1,212.9 1,164.2
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Deferred Credits and Other Liabilities
Deferred income taxes 1,305.5 1,309.1
Postretirement and postemployment benefits 226.3 217.0
Deferred investment tax credits 115.8 118.0
Decommissioning of federal uranium enrichment facilities 30.8 30.8
Other 60.6 56.3
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Total deferred credits and other liabilities 1,739.0 1,731.2
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Capitalization
Long-term Debt
First refunding mortgage bonds of BGE 1,554.2 1,554.2
Other long-term debt of BGE 1,000.8 1,000.8
BGE obligated mandatorily redeemable
trust preferred securities 250.0 250.0
Long-term debt of diversified businesses 846.4 870.2
Unamortized discount and premium (12.1) (12.4)
Current portion of long-term debt (503.4) (534.7)
-------------- -------------
Total long-term debt 3,135.9 3,128.1
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Redeemable Preference Stock 7.0 7.0
Current portion of redeemable preference stock (7.0) (7.0)
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Total redeemable preference stock - -
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Preference Stock Not Subject to Mandatory Redemption 190.0 190.0
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Common Shareholders' Equity
Common stock 1,492.6 1,485.1
Retained earnings 1,510.3 1,490.3
Accumulated other comprehensive income 2.9 6.1
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Total common shareholders' equity 3,005.8 2,981.5
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Total capitalization 6,331.7 6,299.6
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TOTAL LIABILITIES AND CAPITALIZATION $ 9,283.6 $ 9,195.0
============== =============
* Unaudited
See Notes to Consolidated Financial Statements.
4
CONSTELLATION ENERGY GROUP, INC.
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PART I. FINANCIAL INFORMATION (Continued)
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Item 1. Financial Statements
Consolidated Statements of Cash Flows (Unaudited)
- -------------------------------------------------
Three Months Ended March 31,
--------------------------------
1999 1998
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(In Millions)
Cash Flows From Operating Activities
Net income $ 86.2 $ 80.2
Adjustments to reconcile to net cash provided by operating activities
Depreciation and amortization 104.7 110.3
Deferred income taxes 2.5 (9.9)
Investment tax credit adjustments (2.2) (1.8)
Deferred fuel costs 7.6 22.8
Accrued pension and postemployment benefits 16.2 4.5
Allowance for equity funds used during construction (1.7) (1.7)
Equity in earnings of affiliates and joint ventures (net) 22.5 (6.0)
Changes in assets from energy trading activities (55.5) (51.2)
Changes in liabilities from energy trading activities 32.0 41.9
Changes in other current assets 57.6 94.4
Changes in other current liabilities 53.4 4.6
Other (2.4) (12.1)
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Net cash provided by operating activities 320.9 276.0
------------ ------------
Cash Flows From Investing Activities
Utility construction expenditures (including AFC) (73.4) (63.1)
Allowance for equity funds used during construction 1.7 1.7
Nuclear fuel expenditures (1.6) (2.8)
Deferred conservation expenditures (0.3) (4.8)
Contributions to nuclear decommissioning trust fund (4.4) (4.4)
Purchases of marketable equity securities (7.8) (6.1)
Sales of marketable equity securities 4.2 9.8
Other financial investments 5.5 (2.1)
Real estate projects and investments 26.1 31.8
Power projects (5.5) (61.7)
Other (12.1) (11.6)
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Net cash used in investing activities (67.6) (113.3)
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Cash Flows From Financing Activities
Proceeds from issuance of:
Short-term borrowings 523.5 1,090.1
Long-term debt 104.6 36.4
Common stock 9.6 12.6
Repayment of short-term borrowings (523.5) (1,185.6)
Reacquisition of long-term debt (128.8) (29.9)
Common stock dividends paid (62.7) (60.5)
Preference stock dividends paid (3.4) (5.8)
Other (2.3) (3.3)
------------ ------------
Net cash used in financing activities (83.0) (146.0)
------------ ------------
Net Increase in Cash and Cash Equivalents 170.3 16.7
Cash and Cash Equivalents at Beginning of Period 173.7 162.6
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Cash and Cash Equivalents at End of Period $ 344.0 $ 179.3
============ ============
Other Cash Flow Information:
Interest paid (net of amounts capitalized) $ 51.6 $ 51.5
Income taxes paid $ 1.0 $ 0.8
See Notes to Consolidated Financial Statements.
Certain prior period amounts have been reclassified to conform with the current
period presentation.
5
Notes to Consolidated Financial Statements
- ------------------------------------------
Weather conditions can have a great impact on our results for interim
periods. This means that results for interim periods do not necessarily
represent results to be expected for the year.
Our interim financial statements on the previous pages reflect all
adjustments which Management believes are necessary for the fair presentation of
the financial position and results of operations for the interim periods
presented. These adjustments are of a normal recurring nature.
Holding Company Formation
- -------------------------
On April 30, 1999, Constellation Energy Group, Inc. (Constellation Energy)
became the holding company for Baltimore Gas and Electric Company (BGE) and
BGE's former subsidiary Constellation Enterprises, Inc. BGE's outstanding common
stock was exchanged on a share-for-share basis for shares of common stock of
Constellation Energy. BGE's debt securities, BGE obligated mandatorily
redeemable trust preferred securities, and preference stock remain securities of
BGE.
Basis of Presentation
- ---------------------
This Quarterly Report on Form 10-Q is a combined report of Constellation
Energy and BGE. The consolidated financial statements include the accounts of
BGE, Constellation Enterprises, Inc. and its subsidiaries, District Chilled
Water General Partnership (ComfortLink), and BGE Capital Trust I and, therefore,
also represent the consolidated financial statements of Constellation Energy.
References in this report to "we" and "our" are to Constellation Energy and its
subsidiaries, collectively.
Information by Operating Segment
- --------------------------------
Energy Other Unallocated
Electric Gas Services Diversified Corporate
Business Business Businesses Businesses Items (a) Eliminations Consolidated
------------ ------------ ------------- --------------- -------------- ------------- ---------------
For the three months ended March 31, (in millions)
1999
- ----
Unaffiliated revenues $ 513.0 $192.8 $ 177.5 $ 49.0 $ - $ - $ 932.3
Intersegment revenues 0.4 2.1 0.6 (0.3) - (2.8) -
----------- ------------ ------------- --------------- -------------- ------------- ---------------
Total revenues 513.4 194.9 178.1 48.7 - (2.8) 932.3
Net income (loss) 49.4 22.0 16.1 (1.6) - 0.3 86.2
Segment assets 6,314.7 888.8 1,299.9 803.8 (11.4) (12.2) 9,283.6
- -------------------------- ----------- ------------ ------------- --------------- -------------- ------------- ---------------
1998
- ----
Unaffiliated revenues $ 499.2 $180.5 $ 116.3 $ 70.1 $ - $ - $ 866.1
Intersegment revenues - - 0.1 0.2 - (0.3) -
----------- ------------ ------------- --------------- -------------- ------------- ---------------
Total revenues 499.2 180.5 116.4 70.3 - (0.3) 866.1
Net income 50.5 16.4 10.0 3.0 - 0.3 80.2
Segment assets 6,287.3 864.5 1,070.6 647.6 2.8 (1.3) 8,871.5
(a) A holding company for our diversified businesses does not allocate the
items presented in the table to our Energy Services and Other Diversified
businesses.
6
Financing Activity
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Constellation Energy
- --------------------
Issuances
- ---------
As discussed on page 6, effective April 30, 1999, BGE's outstanding common
stock was exchanged on a share-for-share basis for shares of common stock of
Constellation Energy.
BGE
- ---
Issuances
- ---------
BGE issued the following medium-term notes during the period from January
1, 1999 through the date of this report:
Date Net
Principal Issued Proceeds
--------- ------ --------
(In millions)
Series G
- --------
Floating rate, due 2001 $60.0 3/99 $59.9
Series H
- --------
Floating rate, due 2001 27.0 3/99 26.9
During the period from January 1, 1999 through April 30, 1999, BGE issued a
total of 310,775 shares of common stock, without par value, under the
Shareholder Investment Plan. Net proceeds were about $9.6 million.
In the future, BGE may purchase some of its long-term debt or preference
stock in the market. This will depend on market conditions and BGE's capital
structure, including the mix of secured and unsecured debt.
Diversified Businesses
- ----------------------
Please refer to the "Capital Requirements of our Diversified Businesses"
section of Management's Discussion and Analysis on page 22 for information about
the debt of our diversified businesses.
Commitments
- -----------
In 1998, Constellation Power Source, Inc., our power marketing and trading
business, and Goldman, Sachs Capital Partners II L.P., an affiliate of Goldman,
Sachs & Co., formed Orion Power Holdings, Inc. to acquire electric generating
plants in the United States and Canada. Constellation Power Source owns a
minority interest in Orion, and has committed to contribute up to $175 million
in equity to fund its investment in Orion.
Environmental Matters
- ---------------------
The Clean Air Act of 1990 contains two titles designed to reduce emissions
of sulfur dioxide and nitrogen oxide (NOx) from electric generating stations
Title IV and Title I.
Title IV addresses emissions of sulfur dioxide. Compliance is required in
two phases:
o Phase I became effective January 1, 1995. We met the requirements of
this phase by installing flue gas desulfurization systems, switching
fuels, and retiring some units.
o Phase II must be implemented by January 1, 2000. We expect to meet the
compliance requirements through a combination of switching fuels and
allowance trading.
Title I addresses NOx emissions. The Maryland Department of the Environment
(MDE) issued NOx regulations effective June 1, 1998. The MDE regulations require
major NOx sources to reduce NOx emissions up to 65% by May 1999. On February 9,
1999, the Baltimore City Circuit Court ordered the MDE to issue a new compliance
date to meet their 65% emissions reduction regulations. 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 requires the reduction of NOx emissions up to 85% by 22 states
(including Maryland and Pennsylvania). The 22 states must submit plans to the
EPA by September 1999 showing how they will meet its new NOx emissions reduction
requirements.
Based on the MDE and EPA regulations, we currently estimate that the
additional controls needed at our generating plants to meet the 65% NOx emission
reduction requirements will cost approximately $126 million. Through the date of
this report, we have spent approximately $30 million to meet the 65% reduction
requirements. We cannot estimate the cost for the 85% reduction requirements at
this time, however, these costs could be material.
In July 1997, the EPA published new National Ambient Air Quality Standards
for very fine particulates and revised standards for ozone attainment. These
standards may require increased controls at our fossil generating plants in the
future. We cannot estimate the cost of these increased controls at this time
because the states, including Maryland, still need to determine what reductions
in pollutants will be necessary to meet the federal standards.
7
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 15.42% 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 $4.9 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 in 1998. The cleanup costs for some of the remaining sites
could be significant, but we do not expect them to have a material effect on our
financial position or results of operations.
Also, we are 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 requires 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 have been
approved by MDE. Based on the remedial action plans, the costs we consider to be
probable to remedy the contamination are estimated to total $47 million in
nominal dollars (including inflation). We have recorded these costs as a
liability on our Consolidated Balance Sheets and have deferred these costs, net
of accumulated amortization and amounts recovered from insurance companies, as a
regulatory asset. We discuss this further in Note 4 of BGE's 1998 Annual Report
on Form 10-K. Through the date of this report, we have spent approximately $33
million for remediation at this site.
We are also required by accounting rules to disclose additional costs we
consider to be less likely than probable costs, but still "reasonably possible"
of being incurred at these sites. Because of the results of studies at these
sites, it is reasonably possible that these additional costs could exceed the
amount we recognized by approximately $14 million in nominal dollars ($7 million
in current dollars, plus the impact of inflation at 3.1% over a period of up to
36 years).
Our potential environmental liabilities and pending environmental actions
are described further in BGE's 1998 Annual Report on Form 10-K under "Item 1.
Business - Environmental Matters."
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:
o physical damage to the plant,
o recoverability of replacement power costs, and
o our liability to third parties for property damage and bodily injury.
We have insurance policies that cover these contingencies, but the policies
have certain exclusions. Furthermore, the costs that could result from a covered
major accident or a covered extended outage at either of the Calvert Cliffs
units could exceed our insurance coverage limits.
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 17 weeks, we have insurance coverage for replacement power costs
up to $494.2 million per unit, provided by an industry mutual insurance company.
This amount can be reduced by up to $98.8 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 $23.2 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 the date of this report, the limit for third
party claims from a nuclear incident is $9.71 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.
8
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.
o BGE nuclear worker claims reported on or after January 1, 1998 are
covered by a new insurance policy with an annual industry aggregate
limit of $200 million for radiation injury claims against all those
insured by this policy.
o All nuclear worker claims reported prior to January 1, 1998 are still
covered by the old insurance policies. Insureds under the old policies,
with no current operations, are not required to purchase the new policy
described above, and may still make claims against the old policies for
the next nine 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.
Recoverability of Electric Fuel Costs
- -------------------------------------
By law, we are allowed to recover our cost of electric fuel if the Maryland
Public Service Commission (Maryland PSC) finds that, among other things, we have
kept the productive capacity of our generating plants at a reasonable level. To
do this, the Maryland PSC will evaluate the performance of our generating
plants, and will determine if we used all reasonable and cost-effective
maintenance and operating control procedures.
The Maryland PSC, under the Generating Unit Performance Program, measures
annually whether we have maintained the productive capacity of our generating
plants at reasonable levels. To do this, the program uses a system-wide
generating performance target and an individual performance target for each base
load generating unit. In fuel rate hearings, actual generating performance
adjusted for planned outages will be compared first to the system-wide target.
If that target is met, it should mean that the requirements of Maryland law
have been met. If the system-wide target is not met, each unit's adjusted actual
generating performance will be compared to its individual performance target to
determine if the requirements of Maryland law have been met and, if not, to
determine the basis for possibly imposing a penalty on BGE. Even if we meet
these targets, parties to fuel rate hearings may still question whether we used
all reasonable and cost-effective procedures to try to prevent an outage. If the
Maryland PSC decides we were deficient in some way, the Maryland PSC may not
allow us to recover the cost of replacement energy.
The two units at Calvert Cliffs use the cheapest fuel. As a result, the
costs of replacement energy associated with outages at these units can be
significant. We cannot estimate the amount of replacement energy costs that
could be challenged or disallowed in future fuel rate proceedings, but such
amounts could be material. We discuss significant disallowances in prior years
related to past outages at Calvert Cliffs in BGE's 1998 Annual Report on Form
10-K.
BGE's electric fuel rate clause will be discontinued when electric
generation is deregulated and, therefore, earnings will be affected by the
changes in the cost of fuel and energy. We discuss competition and its impact on
BGE's generation business further in the "Competition and Response to Regulatory
Change" section of Management's Discussion and Analysis on page 14.
California Power Purchase Agreements
- ------------------------------------
Constellation Power, Inc. and subsidiaries and Constellation Investments,
Inc. (whose power projects are managed by Constellation Power) have $293.6
million invested in 15 projects that sell electricity in California under power
purchase agreements called "Interim Standard Offer No. 4" agreements. Earnings
from these projects were $8.0 million, or $.05 per share, for the quarter ended
March 31,1999.
Under these agreements, the projects supply electricity to utility companies
at:
o a fixed rate for capacity and energy for the first 10 years of the
agreements, and
o a fixed rate for capacity plus a variable rate for energy based on the
utilities' avoided cost for the remaining term of the agreements.
Generally, a "capacity rate" is paid to a power plant for its availability
to supply electricity, and an "energy rate" is paid for the electricity actually
generated.
9
"Avoided cost" generally is the cost of a utility's cheapest next-available
source of generation to service the demands on its system.
We use the term "transition period" to describe the time frame when the
10-year periods for fixed energy rates expire for these 15 power generation
projects and they begin supplying electricity at variable rates. The transition
period for some of the projects began in 1996 and will continue for the
remaining projects through 2000.
The projects that have already transitioned to variable rates have had lower
revenues under variable rates than they did under fixed rates. However, we have
not yet experienced significantly lower earnings from the California projects
because the combined revenues from the remaining projects, which continue to
supply electricity at fixed rates, are high enough to offset the lower revenues
from the variable-rate projects. When the remaining projects transition to
variable rates, we expect the revenues from those projects also to be lower than
they are under fixed rates.
Our power generation business is pursuing alternatives for some of these
power generation projects including:
o repowering the projects to reduce operating costs,
o changing fuels to reduce operating costs,
o renegotiating the power purchase agreements to improve the terms,
o restructuring financing to improve existing terms, and
o selling its ownership interests in the projects.
At the date of this report, nine projects had already transitioned to
variable rates. The remaining six projects that make the highest revenues will
transition between June 1999 and December 2000. The projects which transition in
1999 contributed $2.1 million, or $.01 per share to the quarter ended March 31,
1999 earnings, while those changing over in 2000 contributed $5.9 million, or
$.04 per share to the quarter ended March 31, 1999 earnings. We expect earnings
to ultimately decrease by similar amounts as these projects transition.
Constellation Real Estate
- -------------------------
In April 1999, Constellation Real Estate Group, Inc. (CREG) sold Church
Street Station, our entertainment, dining, and retail complex in Orlando,
Florida for $11.5 million, the approximate book value of the complex.
Most of CREG's remaining real estate 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.
CREG's real estate projects have continued to incur carrying costs and
depreciation over the years. Additionally, CREG 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 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 diversified subsidiaries.
Management's current real estate strategy is to hold each real estate
project until we can realize a reasonable value for it. Management evaluates
strategies for all its businesses, including real estate, on an ongoing basis.
We anticipate that competing demands for our financial resources and changes in
the utility industry will cause us to evaluate thoroughly all diversified
business strategies on a regular basis so we use capital and other resources in
a manner that is most beneficial.
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 projects. If we were to decide to sell our real estate projects, we could
have write-downs. In addition, if we were to sell our remaining real estate
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.
It may be helpful for you to understand when we are required, by accounting
rules, to write down the value of a real estate project to market value. A
write-down is required in either of two cases. The first is if we change our
intent about a project from an intent to hold to an intent to sell and the
market value of that project is below book value. The second is if the expected
cash flow from the project is less than the investment in the project.
10
Item 2. Management's Discussion
- -------------------------------
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.
BGE is an electric and gas public utility company with a service territory
in the City of Baltimore and in all or part of ten counties in Central Maryland.
Constellation Enterprises is a holding company for several diversified
businesses engaged primarily in energy services.
Our energy services businesses include certain subsidiaries of Constellation
Enterprises and the District Chilled Water General Partnership (ComfortLink(R)),
a general partnership in which BGE is a partner. Our energy services businesses
are as follows:
o Constellation Power Source,(TM) Inc. -- our
wholesale power marketing and trading business,
o Constellation Power, Inc.,(TM) and Subsidiaries -- our power projects
business,
o Constellation Energy Source,(TM) Inc. -- our energy products and
services business,
o BGE Home Products & Services,(TM) Inc. and Subsidiaries -- our home
products, commercial building systems, and residential and small
commercial gas retail marketing business,
o ComfortLink -- our cooling services business for commercial customers in
Baltimore.
Constellation Enterprises, Inc. also has two other subsidiaries:
o Constellation Investments,(TM) Inc. -- our
financial investments business, and
o Constellation Real Estate Group,(TM) Inc. -- our
real estate and senior-living facilities
business.
The consolidated financial statements in this report include the accounts of
BGE and its subsidiaries. Therefore, they also represent the financial
statements of Constellation Energy and its subsidiaries. References in this
report to "we" and "our" are to Constellation Energy and its subsidiaries,
collectively. In Exhibit 99(a), we present financial information summarizing
certain pro forma financial effects of the restructuring of BGE. The pro forma
information assumes that the holding company was formed as of January 1, 1999.
It presents BGE's summarized financial statements on a "stand-alone" basis by
excluding the results of Constellation Enterprises and its subsidiaries. These
companies became subsidiaries of Constellation Energy effective April 30, 1999.
The electric utility industry is undergoing rapid and substantial change. On
April 8, 1999, legislation authorizing customer choice and competition among
electric suppliers in Maryland was enacted. In the natural gas industry,
deregulation is well under way. The regulatory environment (federal and state)
for both electricity and natural gas is shifting toward customer choice. These
matters are discussed further in the "Competition and Response to Regulatory
Change" section on page 14.
In response to this change, we regularly evaluate our strategies with two
goals in mind: to improve our competitive position, and to anticipate and adapt
to regulatory change. Constellation Energy will continue to invest in the growth
of its power projects and power marketing and trading businesses with the
objective of providing new sources of earnings in anticipation of lower electric
utility revenues as competition is introduced into this industry in Maryland. In
addition, we might consider one or more of the following strategies:
o the complete or partial separation of our generation, transmission, and
distribution functions,
o purchase or sale of generation assets,
o mergers or acquisitions of utility or non-utility businesses,
o spin-off or sale of one or more businesses, and
o growth of earnings from other nonregulated businesses.
We cannot predict whether any of the strategies described above may actually
occur, or what their effect on our financial condition or competitive position
might be. Please refer to the "Forward Looking Statements" section. Additional
detail on competition is included in BGE's 1998 Annual Report on Form 10-K under
the heading "Electric Regulatory Matters and Competition."
11
In this discussion and analysis, we explain the general financial condition
and the results of operations for Constellation Energy including:
o what factors affect our business,
o what our earnings and costs were in the periods presented,
o why earnings and costs changed between periods,
o where our earnings came from,
o how all of this affects our overall financial condition,
o what our expenditures for capital projects were in the current period and
what we expect them to be in the future, and
o where we expect to get cash for future capital expenditures.
As you read this discussion and analysis, it may be helpful to refer to our
Consolidated Statements of Income on page 2, which present the results of our
operations for the quarters ended March 31, 1999 and 1998. We analyze and
explain the differences between periods in the specific line items of the
Consolidated Statements of Income. Our analysis may be important to you in
making decisions about your investments in Constellation Energy.
Results of Operations for the Quarter Ended March 31, 1999 Compared With the
Same Period of 1998
- --------------------------------------------------------------------------------
In this section, we discuss our earnings and the factors affecting them. We
begin with a general overview, then separately discuss earnings for the utility
business and for diversified businesses.
Overview
- --------
Total Earnings per Share of Common Stock
- ----------------------------------------
Quarter Ended
March 31
--------------------
1999 1998
-------- --------
Utility business......... $ .45 $ .41
Diversified businesses... .10 .09
-------- --------
Total earnings per share. $ .55 $ .50
======== ========
Our total earnings for the quarter ended March 31, 1999 increased $8.4
million, or $.05 per share, compared to the same period of 1998 mostly because
we had higher utility earnings.
In the first quarter of 1999, we had higher utility earnings than we did in
the same period of 1998 mostly because we sold more electricity and gas due to
colder weather this year (people use more electricity and gas to heat their
homes in colder weather). Utility earnings would have been even higher except we
had higher operations and maintenance expenses. We discuss our utility earnings
in more detail in the "Utility Business" section below.
In the first quarter of 1999, diversified business earnings increased
slightly compared to the same period of 1998 mostly because of higher earnings
from our power marketing and trading business. Diversified business earnings
would have been even higher except we had lower earnings from our financial
investments business. We discuss our diversified business earnings in further in
the "Diversified Businesses" section beginning on page 18.
Utility Business
- ----------------
Before we go into the details of our electric and gas operations, we believe
it is important to discuss four factors that have a strong influence on our
utility business performance: regulation, the weather, other factors including
the condition of the economy in our service territory, and competition.
Regulation by the Maryland Public Service Commission (Maryland PSC)
- -------------------------------------------------------------------
The Maryland PSC determines the rates we can charge our customers. Our rates
consist of a "base rate" and a "fuel rate." The base rate is the rate the
Maryland PSC allows us to charge our customers for the cost of providing them
service, plus a profit. We have both an electric base rate and a gas base rate.
Higher electric base rates apply during the summer when the demand for
electricity is the highest. Gas base rates are not affected by seasonal changes.
The Maryland PSC allows us to include in base rates a component to recover
money spent on conservation programs. This component is called a "conservation
surcharge." However, under this surcharge the Maryland PSC limits what our
profit can be. If, at the end of the year, we have exceeded our allowed profit,
we defer (include as a liability in our Consolidated Balance Sheets and exclude
from our Consolidated Statements of Income) the excess in that year and we lower
the amount of future surcharges to our customers to correct the amount of
overage, plus interest.
12
In addition, we charge our electric customers separately for the fuel we use
to generate electricity (nuclear fuel, coal, gas, or oil) and for the net cost
of purchases and sales of electricity (primarily with other utilities). We
charge the actual cost of these items to the customer with no profit to us. If
these fuel costs go up, the Maryland PSC permits us to increase the fuel rate.
If these costs go down, our customers benefit from a reduction in the fuel rate.
The fuel rate is impacted most by the amount of electricity generated at the
Calvert Cliffs Nuclear Power Plant (Calvert Cliffs) because the cost of nuclear
fuel is cheaper than coal, gas, or oil.
We discuss this in more detail in the "Electric Fuel Rate Clause" section on
page 17 and in Note 1 of BGE's 1998 Annual Report on Form 10-K.
Changes in the fuel rate normally do not affect earnings. However, if the
Maryland PSC disallows recovery of any part of the fuel costs, our earnings are
reduced. We discuss this in the "Recoverability of Electric Fuel Costs" section
of the Notes to Consolidated Financial Statements on page 9.
BGE's electric fuel rate clause will be discontinued when electric
generation is deregulated and, therefore, earnings will be affected by the
changes in the cost of fuel and energy. In addition, any accumulated difference
between our actual costs of fuel and energy and the amounts collected from
customers under the electric fuel rate clause will be refunded to or collected
from our customers. This will occur over a period not to exceed twelve months
from when the electric fuel rate clause no longer exists. At March 31, 1999, we
have collected $6.7 million of electric fuel rate revenues in excess of our
actual costs of fuel and energy.
We also 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 on page 17.
From time to time, when necessary to cover increased costs, we ask the
Maryland PSC for base rate increases. The Maryland PSC holds hearings to
determine whether to grant us all or a portion of the amount requested. The
Maryland PSC has historically allowed us to increase base rates to recover
increased utility plant 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 lower our base rates. We
discuss this in more detail in the "Competition and Response to Regulatory
Change" section on page 14.
Weather
- -------
Weather affects the demand for electricity and gas. Very hot summers and
very cold winters increase demand. Mild weather reduces demand. Weather impacts
residential sales more than commercial and industrial sales, which are mostly
affected by business needs for electricity and gas.
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.
Effective March 1, 1998, the Maryland PSC allowed us to implement a monthly
adjustment to our gas business revenues to eliminate the effect of abnormal
weather patterns. We discuss this further in the "Weather Normalization" section
on page 17.
We show the number of heating degree days in the quarters ended March 31,
1999 and 1998 and the percentage change in the number of degree days between
these two periods in the following table:
Quarter Ended
March 31
------------------------
1999 1998
---------- ---------
Heating degree days........ 2,389 2,022
Percent change
compared to prior period 18.2%
Other Factors
- -------------
Other factors, aside from weather, impact the demand for electricity and
gas. These factors include the "number of customers" and "usage per customer"
during a given period. We use these terms later in our discussions of electric
and gas operations. In those sections, we discuss how these and other factors
affected electric and gas sales during the periods presented.
13
The number of customers in a given period is affected by new home and
apartment construction and by the number of businesses in our service territory.
Usage per customer refers to all other items impacting customer sales that
cannot be separately measured. These factors include the strength of the economy
in our service territory. When the economy is healthy and expanding, customers
tend to consume more electricity and gas. Conversely, during an economic
downtrend, our customers tend to consume less electricity and gas.
Competition and Response to Regulatory Change
- ---------------------------------------------
Our electric and gas businesses are also affected by competition as
discussed below.
Electric Business
- -----------------
Electric utilities are facing competition on various fronts, including:
o the construction of generating units to meet increased demand for
electricity,
o the sale of electricity in bulk power markets,
o competing with alternative energy suppliers, and
o electric sales to retail customers.
On July 1, 1998, BGE and all other Maryland investor-owned electric
utilities filed with the Maryland PSC their individual proposals for the
transition from a regulated electric supply system to one where generation is
priced based on a competitive retail electric market. The details of our
proposal are discussed in BGE's 1998 Annual Report on Form 10-K.
On December 22, 1998, other parties filed their positions in response to our
proposals. The counter-proposals contain provisions, which, if adopted by the
Maryland PSC, could negatively impact BGE's electric business. On September 3,
1998, the Office of People's Counsel (OPC) filed a petition requesting the
Maryland PSC to lower our electric base rates. At our request, the Maryland PSC
agreed to consolidate any such review of our electric base rates with its review
of our electric restructuring transition proposal mentioned above. We filed
testimony and exhibits with the Maryland PSC supporting our position that our
current electric base rates are justified.
On February 5, 1999, other parties, including the OPC, filed testimonies to
lower our electric base rates by as much as $131 million. As a condition of the
Maryland PSC's consolidation of these matters, we agreed to make our rates
subject to refund effective July 1, 1999 should the Maryland PSC issue a rate
reduction order after that date.
On April 8, 1999, Maryland enacted the Electric Customer Choice and
Competition Act of 1999 (the "Act") and accompanying tax legislation that will
significantly restructure Maryland's electric utility industry and modify the
industry's tax structure. Major elements of the Act are:
o residential customer choice begins on July 1, 2000 for a third of
customers, and the next two thirds will be phased in over the
following two years,
o all commercial and industrial customers may choose electric suppliers
beginning January 1, 2001,
o rates are frozen for all customers for four years after choice begins,
at the rates in effect on June 30, 2000,
o residential customers are guaranteed a reduction of 3% to 7.5% of
rates in effect on June 30, 1999 (exact amount to be determined by the
Maryland PSC) on electric base rates effective July 1, 2000 for 4
years after choice begins,
o generation is deregulated beginning on July 1, 2000,
o existing utilities are responsible for the transmission and delivery
of electricity,
o the Maryland PSC continues to have the authority to mandate
cost-effective energy conservation programs,
o the Maryland PSC will determine transition costs or benefits as
discussed further in this section,
o the Maryland PSC is empowered to protect low-income customers through
the establishment of a $34 million statewide universal service fund,
o competitive billing is required to begin July 1, 2000 and competitive
metering is required to begin in 2002,
o a reciprocity provision is included for the sale of electricity,
whereby utilities in neighboring states are prevented from competing
with Maryland utilities unless the Maryland utility can compete in
their service territory, and
o customers who do not wish to change their electricity provider will
receive "standard offer service" under procedures established by the
Maryland PSC.
14
The tax legislation made comprehensive changes to the state and local
taxation of electric and gas utilities. Starting in the year 2000, the Maryland
public service franchise tax will be 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 (gross receipts) tax on electric and natural gas utilities will
continue to apply to transmission and distribution revenue. Additionally, all
electric and natural gas utility revenue will become 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.
The impact of these tax law changes will depend on Maryland PSC's ruling on
our transition plan and BGE's operating results once generation is deregulated.
The changes are designed, in part, to tax Maryland electric generating
facilities on a more comparable basis with electric generation in surrounding
states.
On May 7, 1999, we reached a tentative agreement in principle with a
majority of the active parties on the major issues in the electric restructuring
proceedings discussed above and are in the process of finalizing an agreement
that will potentially resolve all the issues. As a result, the Maryland PSC has
suspended the procedural schedule and has instructed the settling parties to
file a settlement agreement by June 15, 1999. All parties will then have an
opportunity to comment on the settlement agreement based on a schedule to be
determined. At that point, the Maryland PSC will determine what type of
proceedings are necessary to render a decision regarding whether the settlement
is in the public interest. The settlement agreement can modify some of the Act's
provisions discussed above, with the Maryland PSC's concurrence. It is expected
that the Maryland PSC will issue a final order by October 1, 1999.
As part of its ruling, the Maryland PSC must authorize the amount, if any,
of BGE's stranded investments in its generation plants. If it determines that
there are stranded investments, the time frame over which BGE will recover its
investment from customers must also be determined. BGE's current estimate of its
stranded investments is approximately $900 million, including costs associated
with the transition to competition.
At March 31, 1999, we met the requirements to continue to apply Statement of
Financial Accounting Standards (SFAS) No. 71 to BGE's utility operations. When
sufficient details of the transition plan ultimately approved by the Maryland
PSC become known, the generation portion of BGE's electric business will likely
no longer meet the provisions of SFAS No. 71. At that time, we would implement
SFAS No. 101, "Regulated Enterprises - Accounting for the Discontinuation of
FASB Statement No. 71."
A provision under SFAS No. 101 requires an evaluation of potential
impairments of plant assets under SFAS No. 121, Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets To Be Disposed Of. If any of our
generating plant assets are impaired under the provisions of SFAS No. 121, BGE
would be required to record a write-down. The amount of any such write-down
could materially affect BGE's financial position and results of operations.
However, we cannot estimate the amount of the potential impairment loss, if any,
at this time.
Currently, Maryland law does not allow BGE to securitize the recovery of
stranded investments. A securitization bill was introduced in the Maryland
General Assembly this year but was not considered for enactment. It is expected
that a securitization bill will be considered in the 2000 General Assembly.
Securitization is a mechanism to recover stranded investments. Generally, bonds
would be issued and the proceeds used primarily to reduce stranded investments
and related capitalization of BGE. The bonds would be payable from irrevocable
customer charges.
We cannot predict the ultimate effect the implementation of electric
customer choice as described in this section will have on BGE's financial
position or results of operations, but such effects could be material.
Gas Business
- ------------
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 industrial and commercial gas customers, and 50,000
BGE residential gas customers (under a pilot program) have the option to
purchase gas from other suppliers. On November 1, 1999, all BGE residential
customers will have the same option.
15
Utility Business Earnings per Share of Common Stock
- ---------------------------------------------------
Quarter Ended
March 31
--------------------
1999 1998
-------- --------
Electric business........ $ .31 $ .31
Gas business............. .14 .10
-------- --------
Total utility
earnings per share.... $ .45 $ .41
======== ========
Our utility earnings for the quarter ended March 31, 1999 increased $6.9
million, or $.04 per share compared to the same period of 1998. We discuss the
factors affecting utility earnings below.
Electric Operations
- -------------------
Electric Revenues
- -----------------
The changes in electric revenues in 1999 compared to 1998 were caused by:
Quarter Ended
March 31
1999 vs. 1998
----------------------
(In millions)
Electric system sales volumes.. $ 19.2
Base rates..................... -
Fuel rates..................... 2.7
---------
Total change in electric revenues
from electric system sales. 21.9
Interchange and other sales.... (8.3)
Other........................... 0.2
---------
Total change in electric revenues $ 13.8
=========
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 1999 compared to 1998 were:
Quarter Ended
March 31
1999 vs. 1998
----------------------
Residential................... 7.9%
Commercial.................... 3.7
Industrial.................... (0.9)
During the quarter ended March 31, 1999, we sold more electricity to
residential and commercial customers mostly due to colder weather. We sold about
the same amount of electricity to industrial customers as we did during the same
period of 1998.
Base Rates
- ----------
During the quarter ended March 31, 1999, base rate revenues were about the
same as they were in the same period of 1998. Although we sold more electricity
this quarter, our base rate revenues were about the same because of lower
conservation surcharge revenues.
Fuel Rates
- ----------
During the quarter ended March 31, 1999, fuel rate revenues increased
compared to the same period of 1998 because we sold more electricity.
Interchange and Other Sales
- ---------------------------
"Interchange and other sales" are sales in the PJM (Pennsylvania-New
Jersey-Maryland) Interconnection energy market and to others. The PJM is a
regional power pool with members that include many wholesale market
participants, as well as BGE and seven other utility companies. We sell energy
to PJM members and to others after we have satisfied the demand for electricity
in our own system.
During the quarter ended March 31, 1999, we had lower interchange and other
sales compared to the same period of 1998 mostly because the increased demand
for system sales this quarter reduced the amount of energy we had available for
off-system sales.
Electric Fuel and Purchased Energy Expenses
- -------------------------------------------
Quarter Ended
March 31
-----------------------
1999 1998
--------- ----------
(In millions)
Actual costs.............. $ 127.2 $ 114.6
Net recovery (deferral)
of costs under
electric fuel rate
clause (see Note 1 of
BGE's 1998 Form 10-K)... (6.1) 11.9
--------- ----------
Total electric fuel and
purchased energy expenses $ 121.1 $ 126.5
========= ==========
Actual Costs
- ------------
During the quarter ended March 31, 1999, our actual costs of fuel to
generate electricity (nuclear fuel, coal, gas, or oil) and electricity we bought
from others was higher than in the same period of 1998 mostly because the price
of purchased electricity was higher. The price
16
of electricity purchased changes based on market conditions, complex pricing
formulas for PJM transactions, and contract terms.
Electric Fuel Rate Clause
- -------------------------
Under the electric fuel rate clause, we defer (include as an asset or
liability on the Consolidated Balance Sheets and exclude from the Consolidated
Statements of Income) the difference between our actual costs of fuel and energy
and what we collect from customers under the fuel rate in a given period. We
either bill or refund our customers that difference in the future.
During the quarter ended March 31, 1999, our actual costs of fuel and energy
were higher than the fuel rate revenues we collected from our customers.
Gas Operations
- --------------
Gas Revenues
- ------------
The changes in gas revenues in 1999 compared to 1998 were caused by:
Quarter Ended
March 31
1999 vs. 1998
----------------------
(In millions)
Gas system sales volumes..... $ 5.8
Base rates................... 2.6
Weather normalization........ 3.7
Gas cost adjustments......... 7.8
---------
Total change in gas
revenues from gas 19.9
system sales..............
Off-system sales............. (7.4)
Other........................ (0.2)
---------
Total change in gas revenues. $ 12.3
=========
Gas System Sales Volumes
- ------------------------
The percentage changes in our gas system sales volumes, by type of customer,
in 1999 compared to 1998 were:
Quarter Ended
March 31
1999 vs. 1998
---------------------
Residential................ 11.8%
Commercial................. 13.3
Industrial................. 4.2
During the quarter ended March 31, 1999, we sold more gas to residential
customers mostly because of two factors: colder weather and the number of
customers increased. We would have sold even more gas to residential customers
except we had lower usage per customer. We sold more gas to commercial customers
mostly because of colder weather and the number of customers increased. We sold
more gas to industrial customers mostly because of two factors: colder weather
and increased usage by Bethlehem Steel (our largest customer) and other
industrial customers.
Base Rates
- ----------
During the quarter ended March 31, 1999, base rate revenues were higher than
they were during the same period of 1998. Effective March 1, 1998, the Maryland
PSC allowed us to increase our base rates which increased our base rate revenues
over the twelve-month period March 1998 through February 1999 by approximately
$16 million.
Weather Normalization
- ---------------------
Effective March 1, 1998, the Maryland PSC allowed us to implement 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
will be based on weather that is considered "normal" for the month and,
therefore, will not be 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 which include a market based
rate incentive mechanism. These clauses operate similar to the electric fuel
rate clause described in the "Electric Fuel Rate Clause" section above.
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 essentially the same as the base rate charged
for gas sales and are included in gas system sales volumes.
During the quarter ended March 31, 1999, gas cost adjustment revenues
increased compared to the same period of 1998 mostly because we sold more gas.
17
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).
During the quarter ended March 31, 1999, revenues from off-system gas sales
decreased compared to the same period of 1998 mostly because we sold less gas
off-system.
Gas Purchased For Resale Expenses
- ---------------------------------
Quarter Ended
March 31
----------------------
1999 1998
--------- ---------
(In millions)
Actual costs................ $ 93.2 $ 96.6
Net recovery of costs under
gas adjustment clauses
(see Note 1 of BGE's 1998
Form 10-K)................ 8.9 1.7
--------- ---------
Total gas purchased
for resale expenses...... $102.1 $ 98.3
========= =========
Actual Costs
- ------------
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. During the quarter ended March 31, 1999, actual
gas costs decreased compared to the same period of 1998 mostly because we bought
less gas for off-system sales and we bought it at a lower price.
Gas Adjustment Clauses
- ----------------------
We charge customers for the cost of gas sold through gas adjustment clauses
(determined by the Maryland PSC), as discussed under "Gas Cost Adjustments"
earlier in this section.
During the quarter ended March 31, 1999, our actual gas costs were lower
than the fuel rate revenues we collected from our customers.
Other Operating Expenses
- ------------------------
Operations and Maintenance Expenses
- -----------------------------------
During the quarter ended March 31, 1999, operations and maintenance expenses
increased $23.9 million compared to the same period of 1998 mostly because of
the timing of costs associated with the annual refueling outage at Calvert
Cliffs. Costs related to a major storm during 1999 also contributed to the
increase.
Depreciation and Amortization Expenses
- --------------------------------------
During the quarter ended March 31, 1999, depreciation and amortization
decreased $6.2 million compared to the same period of 1998 mostly because 1998
expense reflects an adjustment for the reduction of the amortization period for
certain computer software from five years to three years. We did not have a
similar adjustment in 1999.
Other Income and Expenses
- -------------------------
Interest Charges
- ----------------
Interest charges represent the interest on our outstanding debt. During the
quarter ended March 31, 1999, interest charges were about the same compared to
the same period of 1998.
Income Taxes
- ------------
During the quarter ended March 31, 1999, our total income taxes increased
$4.3 million compared to the same period of 1998 mostly because we had higher
taxable income from our utility operations.
Diversified Businesses
- ----------------------
Our diversified businesses engage primarily in energy services. We list each
of our diversified businesses in the "Introduction" section on page 11. We
describe our diversified businesses in more detail in BGE's 1998 Annual Report
on Form 10-K under "Item 1. Business -- Diversified Businesses."
18
Diversified Business Earnings per Share of Common Stock
- -------------------------------------------------------
Quarter Ended
March 31
----------------------
1999 1998
---- ----
Energy Services
- --------------------------------
Power marketing and
trading................. $ .05 $ .00
Power projects............ .06 .07
Other.................... .00 .00
--------- ---------
Total energy services
earnings per share....... .11 .07
Other diversified
businesses earnings
per share................ (.01) .02
--------- ---------
Total earnings per share... $ .10 $ .09
========= =========
Our total diversified business earnings for the quarter ended March 31, 1999
increased $1.5 million, or $.01 per share, compared to the same period of 1998.
We discuss the factors affecting the earnings of our diversified businesses
below.
Energy Services
- ---------------
Power Marketing and Trading
- ---------------------------
During the quarter ended March 31, 1999, earnings from our power marketing
and trading business increased compared to the same period of 1998 mostly
because of increased transaction margins and volume.
Constellation Power Source uses the mark-to-market method of accounting for
its trading activities. We discuss the mark-to-market method of accounting and
Constellation Power Source's trading activities in more detail in BGE's 1998
Annual Report on Form 10-K.
As a result of the nature of its trading activities, Constellation Power
Source's revenue 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:
o the number and size of new transactions,
o the magnitude and volatility of changes in
commodity prices and interest rates, and
o the number and size of open commodity and
derivative positions Constellation Power Source holds or sells.
Constellation Power Source'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 trading activities, and such
variations could be material. Assets and liabilities from energy trading
activities increased at March 31, 1999 compared to December 31, 1998 because of
greater business activity during the period.
Power Projects
- --------------
During the quarter ended March 31, 1999, earnings from our power projects
business decreased compared to the same period of 1998 mostly because of
slightly lower earnings from various energy projects.
California Power Purchase Agreements
- ------------------------------------
Constellation Power and subsidiaries and Constellation Investments have
$293.6 million invested in 15 projects that sell electricity in California under
power purchase agreements called "Interim Standard Offer No. 4" agreements.
Earnings from these projects were $8.0 million, or $.05 per share, for the
quarter ended March 31, 1999 compared to $10.0 million, or $.07 per share for
the same period of 1998.
Under these agreements, the electricity rates change from fixed rates to
variable rates beginning in 1996 and continuing through 2000. The projects which
already have had rate changes have lower revenues under variable rates than they
did under fixed rates. When the remaining projects transition to variable rates,
we expect their revenues also to be lower than they are under fixed rates.
We describe these projects and the transition process in detail in the Notes
to Consolidated Financial Statements on page 9.
International
- -------------
At March 31, 1999, Constellation Power had invested about $178.9 million in
11 power projects in Latin America compared to $83.7 million invested in Latin
America at March 31, 1998. These investments include:
o the purchase of a 51% interest in a Panamanian electric distribution
company for approximately $90 million in 1998 by an investment group in
which subsidiaries of Constellation Power hold an 80% interest, and
o approximately $98 million for the purchase of existing electric
generation facilities and the construction of an electric generation
facility in Guatemala.
19
In the future, Constellation Power expects to expand its power projects
business further in both domestic and international projects.
Other Energy Services
- ---------------------
During the quarter ended March 31, 1999, earnings from our other energy
services businesses were about the same compared to the same period of 1998.
Other Diversified Businesses
- ----------------------------
During the quarter ended March 31, 1999, earnings from our other diversified
businesses were lower compared to the same period of 1998 mostly because we had
lower earnings from our financial investments business. Earnings from our real
estate and senior-living facilities business were about the same compared to the
same period of 1998.
Constellation Real Estate's projects have continued to incur carrying costs
and depreciation over the years. Additionally, this business 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 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 diversified subsidiaries.
Management's current real estate strategy is to hold each real estate
project until we can realize a reasonable value for it. Management evaluates
strategies for all its businesses, including real estate, on an ongoing basis.
We anticipate that competing demands for our financial resources and changes in
the utility industry will cause us to evaluate thoroughly all diversified
business strategies on a regular basis so we use capital and other resources in
a manner that is most beneficial.
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 projects. If we were to decide to sell our real estate projects, we could
have write-downs. In addition, if we were to sell our real estate 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.
It may be helpful for you to understand when we are required, by accounting
rules, to write down the value of a real estate project to market value. A
write-down is required in either of two cases. The first is if we change our
intent about a project from an intent to hold to an intent to sell and the
market value of that project is below book value. The second is if the expected
cash flow from the project is less than the investment in the project.
In April 1999, we announced our intent to sell our senior-living facilities
business during 1999 to focus on our energy-related businesses. We expect the
proceeds from the sale to be at least equal to book value.
We discuss our real estate and senior-living facilities business further in
the Notes to Consolidated Financial Statements on page 10.
Financial Condition
- -------------------
Cash Flows
- ----------
For the quarter ended March 31, 1999 1998
- ---------------------------------------------------------
(In millions)
Cash provided by (used in):
Operating Activities $320.9 $ 276.0
Investing Activities (67.6) (113.3)
Financing Activities (83.0) (146.0)
During the quarter ended March 31, 1999, we generated more cash from
operations compared to the same period in 1998 mostly because of improved
operating results and changes in working capital requirements.
During the quarter ended March 31, 1999, we used less cash for investing
activities compared to the same period in 1998 mostly because in the first
quarter of 1998, our power projects business invested $60.7 million for the
purchase of a generation facility in Guatemala. We did not have a similar
investment in 1999. We would have used less cash for investing activities except
our utility construction expenditures increased by $10.3 million during the
quarter ended March 31, 1999.
During the quarter ended March 31, 1999, we used less cash for financing
activities compared to the same period of 1998 mostly because we issued more
long-term debt and our net repayments of short-term borrowings were less. We
would have used less cash for financing activities except we repaid more
long-term debt in first quarter 1999.
20
Security Ratings
- ----------------
Independent credit-rating agencies rate Constellation Energy's and BGE's
fixed-income securities. The ratings indicate the agencies' assessment of our
ability to pay interest, distributions, dividends, and principal on these
securities. These ratings affect how much it will cost us to sell these
securities. The better the rating, the lower the cost of the securities to us
when they sell them. Constellation Energy's and BGE's securities ratings at the
date of this report are:
Standard Moody's Duff & Phelps'
& Poors Investors Credit
Rating Group Service Rating Co.
------------ ------- ----------
Constellation Energy
- --------------------
Unsecured Debt Pending A3 Pending
BGE
- ---
Mortgage Bonds AA- A1 AA-
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 capital
requirements for the three months ended March 31, 1999, along with estimated
annual amounts for the years 1999 through 2001, are shown below. For the twelve
months ended March 31, 1999, our ratio of earnings to fixed charges was 2.97 and
our ratio of earnings to combined fixed charges and preferred and preference
dividend requirements was 2.66.
Investment requirements for 1999 through 2001 include estimates of funding
for existing and anticipated projects. We continuously review and modify those
estimates. Actual investment requirements may vary from the estimates included
in the table below because of a number of factors including:
o regulation, legislation, and competition,
o load growth,
o environmental protection standards,
o the type and number of projects selected for development,
o the effect of market conditions on those projects,
o the cost and availability of capital, and
o the availability of cash from operations.
Our estimates are also subject to additional factors. Please see "Forward
Looking Statements" on page 28.
Quarter Ended
March 31, Calendar Year Estimates
1999 1999 2000 2001
--------- ------- -- -------- -- --------
(In millions)
Utility Business Capital Requirements:
- --------------------------------------
Construction expenditures (excluding AFC)
Electric $53 $285 $290 $278
Gas 12 74 70 69
Common 5 25 20 18
-------- ------- ------- -------
Total construction expenditures 70 384 380 365
AFC 3 12 13 19
Nuclear fuel (uranium purchases and processing charges) 2 48 50 48
Deferred energy conservation expenditures - 1 - -
Retirement of long-term debt and redemption of
preference stock 87 254 253 282
-------- ------- ------- -------
Total utility business capital requirements 162 699 696 714
-------- ------- ------- -------
Diversified Business Capital Requirements:
- ------------------------------------------
Investment requirements 17 402 498 556
Retirement of long-term debt 27 200 273 365
-------- ------- ------- -------
Total diversified business capital requirements 44 602 771 921
-------- ------- ------- -------
Total capital requirements $206 $1,301 $1,467 $1,635
======== ======= ======= =======
21
Capital Requirements of Our Utility Business
- --------------------------------------------
Our estimates of future electric construction expenditures do not include
costs to build more generating units. Electric construction expenditures include
improvements to generating plants and to our transmission and distribution
facilities.
Future electric construction expenditures include estimated costs for
replacing the steam generators and renewing the operating licenses at Calvert
Cliffs. The operating licenses expire in 2014 for Unit 1 and in 2016 for Unit 2.
We estimate these Calvert Cliffs costs to be:
o $34 million in 1999,
o $44 million in 2000, and
o $58 million in 2001.
We estimate that during the two-year period 2002 through 2003, we will spend
an additional $151 million to complete the replacement of the steam generators
and extend the operating licenses at Calvert Cliffs. We discuss the license
extension process further in the "Other Matters - Calvert Cliffs License
Extension" section of BGE's 1998 Annual Report on Form 10-K.
If we do not replace the steam generators, we estimate that Calvert Cliffs
could not operate for the full term of its current operating licenses. We expect
the steam generator replacements to occur during the 2002 refueling outage for
Unit 1 and during the 2003 outage for Unit 2.
Additionally, our estimates of future electric construction expenditures
include the costs of complying with Environmental Protection Agency (EPA) and
State of Maryland nitrogen oxides emissions (NOx) reduction regulations as
follows:
o $34 million in 1999,
o $49 million in 2000, and
o $21 million in 2001.
We discuss the NOx regulations in the "Environmental Matters" section of the
Notes to Consolidated Financial Statements on page 7.
During the twelve months ended March 31, 1999, our utility operations
provided about 102% of the cash needed to meet its capital requirements,
excluding cash needed to retire debt and redeem preference stock.
We will continue to have cash requirements for:
o working capital needs including the
payments of interest, distributions, and dividends,
o capital expenditures, and
o the retirement of debt and redemption of preference stock.
During the three years from 1999 through 2001, we expect utility operations
to provide about 115% of the cash needed to meet its capital requirements,
excluding cash needed to retire debt and redeem preference stock.
When BGE cannot meet utility capital requirements internally, BGE sells debt
and preference stock. BGE also sells securities when market conditions permit
them to refinance existing debt or preference stock at a lower cost. The amount
of cash BGE needs and market conditions determine when and how much BGE sells.
Future funding for capital expenditures, the retirement of debt, redemption
of preference stock, and payments of interest and dividends is expected from
internally generated funds, commercial paper issuances, available capacity under
credit facilities, and/or the issuance of long-term debt, trust securities, or
preference stock.
At March 31, 1999 the Federal Energy Regulatory Commission has authorized
BGE to issue up to $700 million of short-term borrowings. In addition, BGE
maintains $113 million in committed bank lines of credit and has $100 million in
bank revolving credit agreements to support its commercial paper program.
Capital Requirements of Our Diversified Businesses
- --------------------------------------------------
We expect to expand certain of our energy services businesses which will
require additional funding for:
o growing our power marketing and trading business,
o the development and acquisition of power
projects, as well as loans made to project entities,
o investments in financial limited partnerships, and
o funding for construction of cooling system projects.
The investment requirements exclude Constellation Power Source, Inc.'s
commitment to contribute up to $175 million in equity to fund its investment in
Orion Power Holdings, Inc. Orion acquires electric generating plants in the
United States and Canada.
22
Our diversified businesses have met their capital requirements in the past
through borrowing, cash from their operations, sales of receivables, and from
time to time, equity contributions from BGE.
Future funding for the expansion of our energy services businesses is
expected from internally generated funds, short-and long-term financing by
Constellation Energy, and from time to time equity contributions from
Constellation Energy. BGE Home Products & Services may also meet capital
requirements through sales of receivables.
If we can get a reasonable value for our real estate projects and our
senior-living facilities, 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.
Our diversified businesses also have revolving credit agreements totaling
$270 million to provide additional liquidity for short-term financial needs,
including the issuance of up to $135 million of letters of credit.
Other Matters
- -------------
Environmental Matters
- ---------------------
We are subject to federal, state, and local laws and regulations that work
to improve or maintain the quality of the environment. If certain substances
were disposed of or released at any of our properties, whether currently
operating or not, these laws and regulations require us to remove or remedy the
effect on the environment. This includes Environmental Protection Agency
Superfund sites. You will find details of our environmental matters in the
"Environmental Matters" section of the Notes to Consolidated Financial
Statements beginning on page 7 and in BGE's 1998 Annual Report on Form 10-K
under "Item 1. Business - Environmental Matters." These details include
financial information. Some of the information is about costs that may be
material.
Year 2000 Readiness Disclosure
- ------------------------------
We have not experienced any significant year 2000 problems to date and we do
not expect any significant problems to impair our operations as we transition to
the new century. However, due to the magnitude and complexity of the year 2000
issue, even the most conscientious efforts cannot guarantee that every problem
will be found and corrected prior to January 1, 2000. We are focusing on
critical operating and business systems and expect to have contingency plans in
place to deal with any problems, if they should occur. Please refer to "Forward
Looking Statements" on page 28.
Utility Business
- ----------------
We established a year 2000 Program Management Office (PMO). Based on a work
plan developed by the PMO, we have targeted the following six key areas:
o digital systems (devices with embedded microprocessors such as power
instrumentation, controls, and meters),
o telecommunications systems,
o major suppliers,
o information technology applications (our customer, business, and human
resources information systems),
o computer hardware and software infrastructure, and
o contingency plans.
Of these areas, digital systems have the most impact on our ability to
provide electric and gas service. Telecommunications, major suppliers, and
certain information technology applications also impact our ability to provide
electric and gas service.
Year 2000 Project Phases
- ------------------------
Our year 2000 project is divided into two phases:
o Phase I - initial assessment and detailed analysis, and
o Phase II - testing, remediation, certification, and contingency
planning.
Phase I involves conducting an inventory of all systems and identifying
appropriate resources. We have identified the following appropriate resources
for each system or piece of equipment:
o BGE employees familiar with each system or piece of equipment,
o specialized contractors, and
o specific vendors.
23
Phase I also includes developing action plans to ensure that the key areas
identified above are year 2000 ready. The action plans for each system or piece
of equipment include:
o our budget,
o schedules for Phase I and II, and
o our remediation approach - repair, upgrade, replace or retire.
In evaluating our risks and estimating our costs, we utilized employees with
expertise in each line of business to perform the activities under Phase I. We
believe our employees are the most familiar with their systems or equipment and
therefore will provide a reliable estimate of our risks and costs.
Phase II includes converting and testing all of our systems. Each system
will be tested by those employees used in Phase I following formal guidelines
developed by the PMO. Each system or piece of equipment will then be certified
by a tester and the PMO, following testing guidelines developed with the help of
outside consultants. We are currently evaluating whether we will have our year
2000 testing independently certified. Phase II also includes identifying our
major suppliers and developing contingency plans. We have identified our major
suppliers and have assessed their year 2000 readiness through surveys. We are
currently following-up with our major suppliers via interviews.
Contingency Planning
- --------------------
Year 2000 operational contingency planning is underway. Staffing and initial
planning was completed in 1998. Contingency plans are expected to be completed,
including company-wide training, by June 1999. We are developing contingency
plans using the contingency guidelines issued by the Nuclear Energy Institute
(which are endorsed by the Nuclear Regulatory Commission), the contingency
guidelines issued by the North American Electric Reliability Council (NERC), and
guidance from consultants.
We are also addressing the impact of electric power grid problems that may
occur outside of our own electric system. We are developing year 2000 electric
power grid impact planning through our various electric interconnection
affiliations. The PJM interconnection has drafted year 2000 operational
preparedness plans and restoration scenarios and will continue to coordinate and
develop these plans during the first half of 1999 in cooperation with NERC. The
NERC performs monthly assessments of the electric utility industry to
communicate the readiness of the national electric grid for year 2000.
On April 9, 1999, we participated in a NERC sponsored drill, along with
other North American electric bulk operating utilities. The drill focused on
testing backup voice and data communications and protocols. The drill was
successful as it demonstrated our ability to operate the bulk power and gas
distribution systems reliably during a partial loss of telephone communications.
The NERC has scheduled a second drill beginning September 8, 1999 to simulate
January 1, 2000. In addition, the PJM has scheduled two drills in May and
December 1999.
Through the Electric Power Research Institute (EPRI), an industry-wide
effort has been established to deal with year 2000 problems affecting digital
systems and equipment used by the nation's electric power companies. Under this
effort, participating utilities assessed specific vendors' system problems and
test plans. The assessment was shared by the industry as a whole to facilitate
year 2000 problem solving.
BGE has joined the American Gas Association (AGA) in an initiative similar
to the one with EPRI to facilitate year 2000 problem solving among gas
utilities. The AGA and its affiliates perform quarterly assessments of the gas
utility industry to communicate the readiness of its members for the year 2000.
Current Status
- --------------
The most reasonably likely worst case scenario faced by our utility business
is a localized interruption in providing electric and gas service to our
customers. We cannot predict the impact of any interruption on our results of
operations, but the impact could be material. The following table shows our
estimate as of the date of this report of the percentage completed for Phases I
and II and our expected year 2000 readiness target dates for the six key areas:
Year 2000
readiness
Phase I Phase II target date
------- -------- -----------
(approximate % complete)
Digital systems 100% 80% June 1999
Telecommunications
system 100% 95% June 1999
Major suppliers 100% 92% June 1999
Information technology
applications 100% 85% June 1999
Computer hardware and
software infrastructure 100% 92% June 1999
Contingency plans - 40% June 1999
24
The completion percentages listed above are reviewed by our PMO in monthly
status meetings with the personnel responsible for each project and their
supervision. Monthly progress is also monitored by senior Constellation Energy
and BGE management.
Costs
- -----
In the following table, we show the breakdown of our total costs between
normal system replacements that will be capitalized (included in the
Consolidated Balance Sheets) and the costs that will be expensed (included in
our Consolidated Statements of Income) through operations and maintenance (O&M)
cost. We also show the breakdown of non-incremental (previously included in our
information technology budget) and incremental O&M cost:
Estimated Total
Actual Costs Costs Costs
------------ ----- -----
Through
1996 - March 31, Remainder
1997 1998 1999 of 1999 2000
---- ---- ---- ------- ----
(In millions)
Total Cost $1.8 $18.9 $5.2 $14.3 $2.0 $42.2
Less: Capital
Cost - 7.3 1.5 4.2 - 13.0
------ ----- ----- ----- ------ ------
O&M cost 1.8 11.6 3.7 10.1 2.0 29.2
Less:
non-incremental
O&M cost 1.8 4.6 1.1 5.9 1.0 14.4
------ ----- ----- ----- ------ ------
Incremental O&M
cost $- $7.0 $2.6 $4.2 $1.0 $14.8
====== ===== ===== ======= ====== ======
The costs incurred in 1996 and 1997 were for Phase I. The costs incurred in
1998 were for Phases I and II. Cost incurred in 1999 and 2000 will be for Phase
II.
In 1998, we had the equivalent of approximately 110 full-time employees
assigned to our year 2000 project. We expect a similar level of commitment of
resources to continue during 1999.
Diversified Businesses
- ----------------------
Overview
- --------
Our diversified businesses have established year 2000 task forces to address
their year 2000 issues. As the initial assessments are completed, the businesses
have developed, and will be developing, action plans to prepare their systems
for the year 2000. Outside consultants have been retained by several of our
diversified businesses to help complete the initial assessment and detailed
analysis phase, and to assist in the testing, remediation, and certification
phase of their year 2000 projects. The action plans developed are similar to
those used by our utility business, including a test certification process. All
systems are expected to be certified by December 1999. Our diversified
businesses are evaluating whether they will have their year 2000 testing
independently certified.
In evaluating their risks and estimating their costs, our diversified
businesses utilized employees with expertise in each line of business to perform
initial assessments. We believe our diversified businesses' employees are the
most familiar with their systems or equipment and therefore will provide a
reliable estimate of our risks and costs.
The progress of our diversified businesses' year 2000 projects are reviewed
by their year 2000 task forces in monthly status meetings with the personnel
responsible for each project and their supervision. Monthly progress is also
monitored by senior management for each business and monthly updates are
provided to Constellation Energy and BGE senior management.
Contingency Planning
- --------------------
Each of our diversified businesses will develop contingency plans, which are
expected to be completed by December 1999.
Current Status
- --------------
The most reasonably likely worst case scenarios faced by our energy services
businesses and our other diversified businesses are discussed below. However, if
any of these scenarios actually occurred, the impact is not expected to be
material to our consolidated financial results.
Energy Services
- ---------------
The most reasonably likely worst case scenarios for any one of our power
projects would be:
o a shutdown of the plant's systems (most of which can be manually
overridden),
o inability of the purchasing utility to take the plant's power, or
o failure of critical suppliers.
Personnel at each plant are currently assessing their particular year 2000
issues and certain plants have started the testing, remediation, and
certification phase of their year 2000 project. In Latin America, personnel are
currently assessing the year 2000 readiness of suppliers and are preparing
contingency plans where necessary.
25
For our power marketing and trading business and our energy products and
services business, the most reasonably likely worst case scenario would be
encountering any Internet access problems with trading partners, transmission
service providers, independent operators, power exchanges, and various
electronic bulletin boards. Each of these businesses has three Internet service
providers for alternate routing to critical Internet sites necessary to perform
day-to-day business functions. Both have completed the assessment and detailed
analysis phase and have started the testing, remediation, and certification
phase of its year 2000 project.
For our home products and commercial building systems business, the most
reasonably likely worst case scenarios would be any interruption in billing
customers or renewing maintenance contracts. This business has substantially
completed the assessment and detailed analysis phase and has started the
testing, remediation, and certification phase of its year 2000 project.
Other Diversified Businesses
- ----------------------------
The most reasonably likely worst case scenarios for our financial
investments business would be a breakdown in the systems of the brokers or
safekeeping banks which it uses to trade, or the failure of its investment
managers' computer programs that set investment strategy. This business is
currently surveying and monitoring the year 2000 readiness of its banks,
brokers, and investment managers.
For our real estate and senior-living facilities business, the most
reasonably likely worst case scenario is a failure of the systems that support
the health, safety, and welfare of residents in the senior-living facilities.
Personnel at each senior-living facility are involved in assessing its
particular year 2000 issues and have a consultant coordinating the overall year
2000 activity.
Costs
- -----
We estimate our total year 2000 costs for our power projects business to be
approximately $4.2 million, of which $1.2 million is related to our year 2000
efforts for our Panamanian electric distribution company. The total estimated
year 2000 costs for our remaining diversified businesses are approximately $2.8
million.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
- ------------------------------------------------------------------
We discuss the following information related to our market risk:
o quarterly financing activities in the Notes to Consolidated Financial
Statements on page 7, and
o trading activities of our power marketing and trading business in the
"Power Marketing and Trading" section of Management's Discussion and
Analysis on page 19.
26
PART II. OTHER INFORMATION
- -------- -----------------
Item 1. Legal Proceedings
- ------- -----------------
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 BGE's Report on Form 8-K filed August 20, 1993. We are
involved in these claims with approximately 70 other defendants. Approximately
520 individuals that were never employees of 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:
o the identity of our facilities at which the
plaintiffs allegedly worked as contractors,
o the names of the plaintiff's employers, and
o the date on which the exposure allegedly occurred.
To date, seven of these cases were settled before trial for amounts that
were immaterial. One trial is currently scheduled for August 1999.
The second type is claims by one manufacturer -- Pittsburgh Corning Corp. --
against us and approximately eight others, as third-party defendants. These
claims relate to approximately 1,500 individual plaintiffs and were filed in the
Circuit Court for Baltimore City, Maryland in the fall 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:
o the identity of our facilities containing asbestos manufactured by the
manufacturer,
o the relationship (if any) of each of the individual plaintiffs to us,
o the settlement amounts for any individual plaintiffs who are shown
to have had a relationship to us, and
o the dates on which/places at which the exposure allegedly occurred.
Until the relevant facts for both 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.
Item 2. Changes in Securities and Use of Proceeds
- ------- -----------------------------------------
Effective April 30, 1999, the outstanding common stock of BGE was exchanged
on a share-for-share basis for shares of common stock of Constellation Energy.
Certain rights of the holders of common stock of Constellation Energy were
modified. We discussed this further in the joint proxy statement / prospectus of
Constellation Energy and BGE in Post-Effective Amendment No. 1 to Form S-4
(Registration No. 33-64799), under the section "Comparative Shareholder Rights,"
attached as an exhibit to this document, and incorporated by reference herein.
27
PART II. OTHER INFORMATION (Continued)
- -------- -----------------------------
Item 5. Other Information
- ------- -----------------
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:
o general economic, business, and regulatory conditions,
o energy supply and demand,
o competition,
o federal and state regulations,
o availability, terms, and use of capital,
o nuclear and environmental issues,
o weather,
o industry restructuring and cost recovery (including the potential effect
of stranded investments),
o commodity price risk, and
o year 2000 readiness.
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.
28
PART II. OTHER INFORMATION (Continued)
- -------- -----------------------------
Item 6. Exhibits and Reports on Form 8-K
- ----------------------------------------
(a) Exhibit No. 10(a) Constellation Energy Group, Inc. Deferred Compensation Plan for
Non-Employee Directors.
Exhibit No. 10(b) Constellation Energy Group, Inc. Long-Term Incentive Plan.
Exhibit No. 10(c) Constellation Energy Group, Inc. 1995 Long-Term Incentive Plan.
Exhibit No. 10(d) Constellation Energy Group, Inc. Nonqualified Deferred Compensation
Plan, as amended and restated.
Exhibit No. 10(e) Grantor Trust Agreement dated as of April 30, 1999 between
Constellation Energy Group, Inc. and T. Rowe Price Trust Company.
Exhibit No. 10(f) Constellation Energy Group, Inc. Executive Benefits Plans.
Exhibit No. 10(g) Grantor Trust Agreement Dated as of April 30, 1999 between
Constellation Energy Group, Inc. and Citibank, N.A.
Exhibit No. 10(h) Executive Incentive Plan of Constellation Energy Group, Inc.
Exhibit No. 10(i) Summary of severance arrangement for a named executive officer.
Exhibit No. 10(j) Form of Severance Agreement between Constellation Energy Group, Inc.
and eight key employees.
Exhibit No. 10(k) Constellation Enterprises, Inc. Deferred Compensation Plan for
Non-Employee Directors.
Exhibit No. 10(l) Summary of enhanced retirement benefits for a named executive
officer.
Exhibit No. 10(m) Baltimore Gas and Electric Company Retirement Plan for Non-Employee
Directors, as amended and restated.
Exhibit No. 12 Computation of Ratio of Earnings to Fixed Charges and
Computation of Ratio of Earnings to Combined Fixed Charges and
Preferred and Preference Dividend Requirements.
Exhibit No. 27 Financial Data Schedule.
Exhibit No. 99(a) Summarized Pro Forma Financial Information Related to the Formation
of a Holding Company.
Exhibit No. 99(b) Comparative Shareholder Rights Section From the Joint Proxy
Statement / Prospectus of Constellation Energy and BGE in
Post-Effective Amendment No. 1 to Form S-4 (Registration No.
33-64799).
(b) Reports on Form 8-K for the quarter ended March 31, 1999:
Date Filed Items Reported
---------- --------------
January 22, 1999 Item 5. Other Events
Item 7. Financial Statements and Exhibits
March 1, 1999 Item 5. Other Events
Item 7. Financial Statements and Exhibits
29
SIGNATURE
---------------------------
Pursuant to the requirements of the Securities Exchange Act of 1934,
each registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
CONSTELLATION ENERGY GROUP, INC.
--------------------------------
(Registrant)
BALTIMORE GAS AND ELECTRIC COMPANY
----------------------------------
(Registrant)
Date: May 14, 1999 /s/ D. A. Brune
---------------- -----------------------------------
D. A. Brune, Vice President on behalf
of each Registrant and as Principal
Financial Officer of each Registrant
30
EXHIBIT INDEX
Exhibit
Number
10(a) Constellation Energy Group, Inc. Deferred Compensation Plan
for Non-Employee Directors.
10(b) Constellation Energy Group, Inc. Long-Term Incentive Plan.
10(c) Constellation Energy Group, Inc. 1995 Long-Term Incentive
Plan.
10(d) Constellation Energy Group, Inc. Nonqualified Deferred
Compensation Plan, as amended and restated.
10(e) Grantor Trust Agreement dated as of April 30, 1999 between
Constellation Energy Group, Inc. and T. Rowe Price Trust
Company.
10(f) Constellation Energy Group, Inc. Executive Benefits Plans.
10(g) Grantor Trust Agreement Dated as of April 30, 1999 between
Constellation Energy Group, Inc. and Citibank, N.A.
10(h) Executive Incentive Plan of Constellation Energy Group, Inc.
10(i) Summary of severance arrangement for a named executive
officer.
10(j) Form of Severance Agreement between Constellation Energy
Group, Inc. and eight key employees.
10(k) Constellation Enterprises, Inc. Deferred Compensation Plan
for Non-Employee Directors.
10(l) Summary of enhanced retirement benefits for a named executive
officer.
10(m) Baltimore Gas and Electric Company Retirement Plan for
Non-Employee Directors, as amended and restated.
12 Computation of Ratio of Earnings to Fixed Charges and
Computation of Ratio of Earnings to Combined Fixed Charges
and Preferred and Preference Dividend Requirements.
27 Financial Data Schedule.
99(a) Summarized Pro Forma Financial Information Related to the
Formation of a Holding Company.
99(b) Comparative Shareholders Rights Section From the Joint Proxy
Statement / Prospectus of Constellation Energy and BGE in
Post-Effective Amendment No. 1 to Form S-4 (Registration No.
33-64799).
31