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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended 1-1910
DECEMBER 31, 1997 Commission file number
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BALTIMORE GAS AND ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
MARYLAND 52-0280210
(State of incorporation) (I.R.S. Employer Identification No.)
39 W. LEXINGTON STREET,
BALTIMORE, MARYLAND 21201
(Address of principal executive offices) (Zip Code)
410-783-5920
(Registrant's telephone number, including area code)
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
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New York Stock Exchange, Inc.
Common Stock -- Without Par Value Chicago Stock Exchange, Inc.
Pacific Stock Exchange, Inc.
Preference Stock, Cumulative, $100 Par Value:
7.78%, 1973 Series
7.50%, 1986 Series Philadelphia Stock Exchange, Inc.
6.75%, 1987 Series
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
Not Applicable
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months, and (2) has been subject to such filing
requirements for the past 90 days. Yes _x_ No ___.
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
Aggregate market value of Common Stock, without par value, held by
non-affiliates as of February 28, 1998 was approximately $4,645,485 based upon
New York Stock Exchange composite transaction closing price.
COMMON STOCK, WITHOUT PAR VALUE -- 147,867,114 SHARES OUTSTANDING ON
FEBRUARY 28, 1998.
DOCUMENTS INCORPORATED BY REFERENCE
PART OF FORM 10-K DOCUMENT INCORPORATED BY REFERENCE
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III Definitive Proxy Statement for the Annual Meeting of Shareholders of Baltimore Gas and
Electric Company to be held on April 24, 1998 (Proxy Statement).
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TABLE OF CONTENTS
PAGE
----
PART I
Item 1 -- Business
Overview of Consolidated
Business......................... 1
Consolidated Capital
Requirements..................... 3
Electric Business
Electric Regulatory Matters and
Competition.................... 4
Electric Rate Matters............ 5
Nuclear Operations............... 5
Electric Load Management, Energy,
and Capacity
Purchases...................... 6
Fuel for Electric Generation..... 7
Electric Operating Statistics.... 9
Gas Business
Gas Operating Statistics......... 10
Gas Regulatory Matters and
Competition.................... 11
Gas Operations................... 11
Gas Rate Matters................. 12
Franchises......................... 12
Diversified Businesses............. 12
Environmental Matters.............. 17
Employees.......................... 19
Item 2 -- Properties......................... 20
Item 3 -- Legal Proceedings.................. 21
Item 4 -- Submission of Matters to a Vote of
Security Holders................. 21
Item 10 -- Executive Officers of the
Registrant (Instruction 3 to Item
401(b) of Regulation S-K)........ 22
PART II
Item 5 -- Market for Registrant's Common
Equity and Related Stockholder
Matters.......................... 24
Item 6 -- Selected Financial Data............ 25
Item 7 -- Management's Discussion and
Analysis of Financial Condition
and Results of
Operations......................... 26
Item 7A -- Quantitative and Qualitative
Disclosures About Market Risk.... 36
Item 8 -- Financial Statements and
Supplementary Data............... 37
Item 9 -- Changes in and Disagreements with
Accountants on Accounting and
Financial
Disclosure......................... 63
PART III
Item 10 -- Directors and Executive Officers of
the Registrant..................... 63
Item 11 -- Executive Compensation............. 63
Item 12 -- Security Ownership of Certain
Beneficial Owners and
Management....................... 63
Item 13 -- Certain Relationships and Related
Transactions..................... 63
PART IV
Item 14 -- Exhibits, Financial Statement
Schedules and Reports on
Form 8-K......................... 64
Signatures....................................... 68
PART I
ITEM 1. BUSINESS
OVERVIEW OF CONSOLIDATED BUSINESS
Baltimore Gas and Electric Company (BGE) is the parent company and conducts
our primary business -- the electric and gas utility business. We also conduct
diversified businesses in subsidiary companies.
BGE was incorporated under the laws of the State of Maryland on June 20,
1906.
BGE owns two-thirds of the outstanding capital stock, including one-half of
the voting stock, of Safe Harbor Water Power Corporation. Safe Harbor is a
producer of hydroelectric power on the Susquehanna River at Safe Harbor,
Pennsylvania. We discuss this further in ITEM 2. PROPERTIES -- ELECTRIC.
OVERVIEW OF UTILITY BUSINESS
Our utility business includes our electric and gas businesses. Our electric
business generates, purchases, and sells electricity. Our gas business
purchases, transports, and sells natural gas. The focus of these activities is
serving customers in our service territory.
We furnish electric and gas retail services in the City of Baltimore and in
all or part of ten counties in Central Maryland. Our electric service territory
includes an area of approximately 2,300 square miles with an estimated
population of 2.6 million. Our gas service territory includes an area of more
than 600 square miles with an estimated population of 2.0 million. There are no
municipal or cooperative wholesale customers within our service territory.
As discussed throughout this report, the two units at our Calvert Cliffs
Nuclear Power Plant (Calvert Cliffs) are our principal generating facilities and
have the lowest fuel cost in our system. An extended shutdown of either of these
Units could have a substantial adverse effect on our business and financial
condition. We describe prior outages at our nuclear plant in the NUCLEAR
OPERATIONS section and in NOTE 12 TO CONSOLIDATED FINANCIAL STATEMENTS.
We describe our utility business further in five other sections of this
report -- ELECTRIC BUSINESS, ELECTRIC OPERATING STATISTICS, GAS OPERATING
STATISTICS, GAS BUSINESS, and FRANCHISES.
COMPETITION AND RESPONSE TO REGULATORY CHANGE
The utility industry is facing substantial regulatory change designed to
encourage competition in the sale of gas and electric services. To prepare for
this change, we regularly reevaluate our strategies.
We reevaluate our strategies with two goals in mind: to improve our
competitive position, and to anticipate and adapt to regulatory changes. We will
continue to develop strategies to keep us competitive. These strategies might
include one or more of the following:
o complete or partial separation of our generation, transmission and
distribution functions,
o purchase or sale of generation assets,
o mergers or acquisitions of utility or non-utility businesses,
o spin-off or sale of one or more businesses,
o growth of revenues from diversified businesses.
We cannot predict whether any transactions of the types described above may
actually occur, nor can we predict what their effect on our financial condition
or competitive position might be.
We discuss competition in our electric and gas businesses in more detail in
the ELECTRIC REGULATORY MATTERS AND COMPETITION and GAS REGULATORY MATTERS AND
COMPETITION sections.
OVERVIEW OF DIVERSIFIED BUSINESSES
Our diversified businesses are organized in three groups:
o Constellation(TM) Holdings, Inc. and Subsidiaries, together known as
the Constellation Holdings Companies -- our power generation,
financial investments, and real estate businesses,
o Constellation Energy Solutions(TM), Inc. and Subsidiaries -- our
energy marketing businesses, and
o BGE Home Products & Services, Inc. and Subsidiaries -- our home
products and commercial building systems businesses.
We describe our diversified businesses in more detail in the DIVERSIFIED
BUSINESSES section.
1
OPERATING REVENUES AND INCOME
The percentages of Operating Revenues and Operating Income attributable to
our electric, gas, and diversified businesses are shown in the tables below. We
present other information about these segments in NOTE 2 TO CONSOLIDATED
FINANCIAL STATEMENTS.
OPERATING REVENUES
------------------------------
ELECTRIC GAS DIVERSIFIED
-------- --- -----------
1997...................... 66% 16% 18%
1996...................... 70 16 14
1995...................... 76 14 10
1994...................... 76 15 9
1993...................... 77 16 7
OPERATING INCOME*
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ELECTRIC GAS DIVERSIFIED
-------- --- -----------
1997...................... 82% 9% 9%
1996...................... 75 10 15
1995...................... 83 7 10
1994...................... 85 4 11
1993...................... 87 6 7
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*Excluding the effect of income taxes.
The percentages for our gas and electric business differ due to two
factors:
o our level of investment in each business, and
o our fuel costs in each business.
Our electric and gas operating revenues reflect amounts collected for fuel
and other operating expenses plus a return on our investment. Our investment for
ratemaking purposes in the electric business is $4.8 billion, but our investment
for ratemaking purposes in the gas business is approximately $676 million. As a
result, our electric operating revenues include a much higher return component
than our gas operating revenues.
Also, as shown in our Consolidated Statements of Income in ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA, our electric fuel costs ("electric
fuel and purchased energy") were 24% of electric revenues in 1997, and our
purchased gas costs ("gas purchased for resale") were 56% of gas revenues in
1997. This means our cost of fuel in relation to our revenues is lower in the
electric business than in the gas business.
We charge the actual cost of the fuel we use to generate electricity to
customers with no profit to us. The price we charge for natural gas is based on
a market based rates incentive mechanism approved by the Maryland Public Service
Commission (Maryland PSC). We discuss market based rates further in the GAS
REGULATORY MATTERS AND COMPETITION section.
Our revenues come from many customers -- residential, commercial, and
industrial. Our largest electric customer provides 2.4% of our total electric
revenues. Our largest gas customer provides 1.3% of our total gas revenues.
As shown in the tables, the percentages for operating revenues and
operating income have historically been about the same for diversified
businesses. However, in 1997 the percentages differ because the Constellation
Holdings Companies wrote down their investments in two real estate projects.
These write-downs reduced diversified business operating income by about $71
million. We discuss these write-downs further in the DIVERSIFIED BUSINESSES
Section.
2
CONSOLIDATED CAPITAL REQUIREMENTS
Our business requires a great deal of capital. Our actual capital
requirements for the years 1995 through 1997, along with estimated amounts for
the years 1998 through 2000, are shown below:
1995 1996 1997 1998 1999 2000
---- ---- ------ ---- ------ ------
(IN MILLIONS)
Utility Business Capital Requirements
Construction expenditures (excluding AFC)
Electric................................................... $223 $219 $ 238 $236 $ 260 $ 273
Gas........................................................ 70 84 89 77 76 72
Common..................................................... 51 46 38 34 27 24
---- ---- ------ ---- ------ ------
Total construction expenditures......................... 344 349 365 347 363 369
AFC (a)...................................................... 22 10 8 8 11 14
Nuclear fuel (uranium purchases and
processing charges)........................................ 46 47 44 50 50 48
Deferred energy conservation expenditures (b)................ 46 31 27 12 10 10
Retirement of long-term debt and redemption of preference
stock...................................................... 279 184 243 117 344 264
---- ---- ------ ---- ------ ------
Total utility business capital requirements............. 737 621 687 534 778 705
---- ---- ------ ---- ------ ------
Diversified Business Capital Requirements.................... 173 170 344 333 271 403
---- ---- ------ ---- ------ ------
Total capital requirements.............................. $910 $791 $1,031 $867 $1,049 $1,108
==== ==== ====== ==== ====== ======
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(a) Allowance for Funds Used During Construction (AFC) is recorded for all
construction projects with a construction period of more than one month. We
discuss AFC further in NOTE 1 TO CONSOLIDATED FINANCIAL STATEMENTS.
(b) We discuss deferred energy conservation expenditures further in NOTE 5 TO
CONSOLIDATED FINANCIAL STATEMENTS.
CAPITAL REQUIREMENTS OF OUR UTILITY BUSINESS
We continuously review and change our construction program, so actual
expenditures may vary from the estimates for the years 1998 through 2000 in the
capital requirements chart. Our actual capital requirements may vary from the
estimates set forth in the table because of a number of factors such as:
o inflation and economic conditions,
o regulation and legislation,
o load growth,
o environmental protection standards, and
o the cost and availability of capital.
During the five-year period 1998 through 2002, we expect to spend about:
o $1.8 billion for construction projects,
o $240 million for nuclear fuel, and
o $50 million for deferred energy conservation programs.
Our projections of future electric construction expenditures do not include
costs to build more generating units. Electric construction expenditures include
improvements to our generating plants and transmission and distribution
facilities. They also include estimated costs for replacing the steam generators
and extending the operating licenses at Calvert Cliffs. The operating licenses
expire in 2014 for Unit 1 and in 2016 for Unit 2. We estimate these Calvert
Cliffs costs to be:
o $27 million in 1998,
o $38 million in 1999, and
o $44 million in 2000.
We estimate that during the three-year period 2001 through 2003, we will spend
an additional $175 million to complete the replacement of the steam generators
and extend the operating licenses at Calvert Cliffs.
If we do not replace the steam generators, we estimate that Calvert Cliffs
could not operate beyond the 2004-2006 time period. We expect the steam
generator replacements to occur during the 2002 refueling outage for Unit 1 and
during the 2003 outage for Unit 2.
During the period January 1, 1993 through December 31, 1997 we:
o spent about $2.0 billion for additions to our utility plant, which
is about 24% of our total utility plant (excluding nuclear fuel)
at December 31, 1997, and
o retired $414 million of our utility plant.
We estimate that we will need about $1.1 billion to retire long-term debt
(including sinking fund payments) and redeem preference stock during the
five-year period 1998-2002.
We discuss our capital requirements further in ITEM 7. MD&A -- LIQUIDITY
AND CAPITAL RESOURCES.
3
CAPITAL REQUIREMENTS OF OUR DIVERSIFIED
BUSINESSES
The capital requirements for our diversified businesses may vary from the
estimates set forth in the table due to a number of factors including market and
economic conditions. We discuss the capital requirements for these businesses
further in two sections of this report: DIVERSIFIED BUSINESS CAPITAL
REQUIREMENTS and ITEM 7. MD&A -- CAPITAL REQUIREMENTS OF OUR DIVERSIFIED
BUSINESSES.
ELECTRIC BUSINESS
We get most of our revenues and operating income from our electric utility
business. We describe this business in several paragraphs below. We discuss our
electric power marketing business separately under the heading DIVERSIFIED
BUSINESSES.
ELECTRIC REGULATORY MATTERS
AND COMPETITION
In recent years we have focused strategic attention on federal regulatory
changes that have increased competition in the wholesale market for bulk power
and expanded competition in the market for generation. Our board of directors
has a Long Range Strategy Committee to oversee the development of our long range
strategic goals, and to consider strategic initiatives presented by management.
Many of these changes were prompted by the Energy Policy Act of 1992 (the
1992 Act). The 1992 Act:
o granted the Federal Energy Regulatory Commission the authority to
order electric utilities to provide transmission service to other
utilities and to other buyers and sellers of electricity in the
wholesale market, and
o created a new class of power producers called exempt wholesale
generators, which are exempt from regulation under the Public
Utility Holding Company Act of 1935, as amended (the 1935 Act).
This exemption has increased the number of entrants into the
electric generation market.
Other changes resulted from policies at the Securities and Exchange
Commission, which has liberalized its interpretation and administration of the
1935 Act in ways that have made mergers between utility companies less
burdensome, thereby facilitating the creation of larger industry competitors.
In addition to the above changes, state legislators and regulators around
the United States are redefining regulatory plans for the electric utility
industry.
In Maryland, the State Legislature established a task force in 1997 to
examine the structure of the electric utility industry. The task force met
several times starting in September 1997 to explore whether all Maryland retail
customers should be allowed to choose any electricity supplier. Presently each
retail customer in Maryland is served by the single electric utility company
that holds the franchise in the area where the customer lives. Under customer
choice, the local electric utility would continue to transmit and deliver
electricity; however, the customer could contract to buy the electricity from
any willing supplier. From the perspective of the electric utility, this means
that transmission and distribution of electricity will remain regulated services
and the generation of electricity will become a competitive service.
There are many issues associated with moving from a regulated generation
market to a competitive generation market. These issues include, among others:
o the recovery of stranded costs(1) by electric utilities,
o adjusting the tax burden so as not to penalize electric utilities'
current generating assets in a competitive market,
o how to address the needs of low income customers, and
o the need to maintain reliable electric service.
The Maryland task force has determined that these issues are complex and
that comprehensive legislation cannot be enacted in the 1998 legislative
session. The Maryland legislature meets annually from mid-January to mid-April.
The task force may continue its work during 1998 and recommend legislation for
enactment in the 1999 legislative session. It appears the task force believes
that the issues can be fully evaluated so that implementation of customer choice
should begin not later than October 1, 2000.
- ---------------
(1) What are stranded costs? They are costs a utility would recover under a
regulated pricing system, but not a competitive one. Traditionally, utilities
have been required to serve all customers in their franchised area while
regulators have set the rates customers pay for that service. To meet customers'
demand for electricity, utilities have had to build facilities, including
generating plants, and enter into contracts to buy power, among other things.
While regulators have approved these investments, they have tried to keep prices
low for consumers by setting rates that defer recovery of these costs over
longer than normal time periods.
Under customer choice, however, electric supply rates will be set by the
market, not by regulators. That means if the market price drops below the
current regulated price, the utility would not recover its investments in
facilities or costs under contracts to buy power and, therefore, the costs would
be "stranded'.
4
The Maryland Public Service Commission (Maryland PSC) has also addressed
the customer choice issues. In its order issued in December 1997, the Maryland
PSC required the phase-in of customer choice in three increments, with one third
of the customers being offered customer choice in each increment. The three
increments are phased in over two years from July 1, 2000 to July 1, 2002. The
Maryland PSC order contemplates a series of hearings and meetings to address the
issues surrounding customer choice. The Maryland PSC also recognizes the need
for legislation to deal with certain issues. BGE will be participating in the
hearings and meetings to be held by the Maryland PSC. We will quantify our
stranded costs and argue for recovery of these costs over a reasonable period of
time. Based on similar proceedings in other states, including neighboring
Pennsylvania, we can expect opposition to the recovery of stranded costs.
It is not possible to predict the ultimate effect competition will have on
our earnings in the future.
ELECTRIC RATE MATTERS
ENERGY CONSERVATION SURCHARGE
The Maryland PSC allows us to include in base rates a component to recover
money we have spent on conservation programs. This component is called an
"energy conservation surcharge" and was approved by the Maryland PSC effective
July 1, 1992. Under this surcharge the Maryland PSC limits what our electric
business profit can be. If, at the end of the year, we have exceeded our allowed
profit, we lower the amount of future surcharges to our customers to correct the
amount of overage, plus interest. The surcharge is reset on July 1 of each year.
We also discuss the surcharge in ITEM 7. MD&A -- RESULTS OF OPERATIONS.
POSTRETIREMENT AND POSTEMPLOYMENT BENEFIT
COSTS
Beginning in 1998, the Maryland PSC authorized us to make some changes in
the way we account for postretirement and other postemployment benefit costs.
The Maryland PSC authorized us to:
o expense all of the increase in annual postretirement benefit costs
related to our electric business, and
o amortize deferred postretirement and other postemployment benefit
costs related to our utility business over 15 years.
The Maryland PSC authorized us to reflect these changes in our current
electric base rates and will adjust our gas base rates to recover the higher
costs that will be recognized in 1998. We discuss this also in the GAS RATE
MATTERS section and in NOTE 6 TO CONSOLIDATED FINANCIAL STATEMENTS.
ELECTRIC FUEL RATE PROCEEDINGS
By law, we are allowed to recover our cost of electric fuel if the Maryland
PSC finds that, among other things, we have kept the productive capacity of our
generating plants at a reasonable level. To do this, the Maryland PSC will
perform an evaluation of each outage (other than regular maintenance outages) at
our generating plants. The evaluation will determine if we used all reasonable
and cost-effective maintenance and operating control procedures to try to
prevent the outage.
The Maryland PSC, under the Generating Unit Performance Program, measures
annually whether we have maintained the productive capacity of our generating
plants at reasonable levels. To do this, the program uses a system-wide
generating performance target and an individual performance target for each base
load generating unit. In fuel rate hearings, actual generating performance
adjusted for planned outages will be compared first to the system-wide target.
If that target is met, it should mean that the requirements of Maryland law have
been met. If the system-wide target is not met, each unit's adjusted actual
generating performance will be compared to its individual performance target to
determine if the requirements of Maryland law have been met and, if not, to
determine the basis for possibly imposing a penalty on BGE. Even if we meet
these targets, other parties to fuel rate hearings may still question whether we
used all reasonable and cost-effective procedures to try to prevent an outage.
If the Maryland PSC decides we were deficient in some way, the Maryland PSC may
not allow us to recover the cost of replacement energy.
BGE is required to submit to the Maryland PSC the actual generating
performance data for each calendar year 45 days after year end. The Maryland PSC
reviews the performance for each calendar year in the first fuel rate proceeding
that is initiated after the data is submitted. BGE must initiate fuel rate
proceedings in any month following a month during which the calculated fuel rate
decreased by more than 5% and may initiate fuel rate proceedings in any month
following a month during which the calculated fuel rate increased by more than
5%.
NUCLEAR OPERATIONS
The two units at Calvert Cliffs use the cheapest fuel. As a result, the
costs of replacement energy associated with outages at these units can be
significant.
5
Before the Generating Unit Performance Program became effective, we were
unable to recover a total of $9.6 million in replacement energy costs for
outages at Calvert Cliffs.
Since 1987 when the Generating Unit Performance Program became effective,
we have been able to recover all replacement energy costs for Calvert Cliffs
outages in 1988, 1992, 1993 and 1994. However, for a 66-day outage at Calvert
Cliffs during 1987 we were unable to recover approximately $4.5 million of our
replacement energy costs. Although we met the system-wide and Calvert Cliffs
performance targets, the Maryland PSC found that the presumption of
reasonableness was overcome by a showing that the outage was caused by
mismanagement.
As a result of the settlement of litigation surrounding an extended outage
at Calvert Cliffs during 1989 to 1991, we wrote off a total of $118 million of
replacement energy costs ($35 million in 1990 and $83 million in 1996), plus
$5.6 million of related financing charges (written off in 1996).
Our performance in 1995 and 1996 is currently being reviewed in a fuel rate
proceeding. We established that we exceeded the system-wide target for those
years as well as the performance target for Calvert Cliffs for 1995. Performance
for 1997 will be reviewed when we submit our next fuel rate application. We
cannot estimate the amount of replacement energy costs that could be challenged
or disallowed in future fuel rate proceedings, but such amounts could be
material.
The following is a summary of Calvert Cliffs' performance over the last 5
years:
GENERATION (MWH) CAPACITY FACTOR
---------------- ---------------
1993............. 12,300,816 85%
1994............. 11,225,977 77%
1995............. 12,940,496 88%
1996............. 12,069,937 82%
1997............. 13,133,441 90%
ELECTRIC LOAD MANAGEMENT, ENERGY,
AND CAPACITY PURCHASES
We have implemented various programs for use when system operating
conditions require a reduction in load. We refer to these programs as active
load management programs. These programs include:
o customer-owned generation and curtailable service for large
commercial and industrial customers,
o air conditioning control which is available to residential and
commercial customers, and
o residential water heater control.
We have generally activated these programs on peak summer days. The
potential reduction in the Summer 1998 peak load from active load management is
approximately 540 megawatts (MW). We recover the costs of these load management
programs from our customers.
Our generation and transmission facilities are connected to those of
neighboring utility systems to form the Pennsylvania-New Jersey-Maryland
Interconnection (PJM). Under the PJM agreement, we use the interconnected
facilities for substantial energy interchange and capacity transactions as well
as emergency assistance. In addition, sometimes we enter into short-term
capacity transactions to meet PJM obligations.
We have an agreement with Pennsylvania Power & Light Company (PP&L) to
purchase electricity and capacity (availability to supply electricity) from June
1, 1990 through May 31, 2001. This agreement, which has been accepted by the
Federal Energy Regulatory Commission, is designed to help maintain adequate
reserve margins through this decade and provide flexibility in meeting capacity
obligations. The PP&L agreement:
o entitles us to 5.94% of the electricity output, and net capacity
(currently 130 MW), of PP&L's nuclear Susquehanna Steam Electric
Station from October 1, 1991 to May 31, 2001, and
o enables us to treat a portion of PP&L's capacity as our capacity
for purposes of satisfying our installed capacity requirements as
a member of the PJM.
We are not acquiring an ownership interest in any of PP&L's generating
units. PP&L will continue to control, manage, operate, and maintain that station
and all other PP&L-owned generating facilities.
Our firm capacity purchases at December 31, 1997 represented:
o 170 MW of rated capacity of Bethlehem Steel Corporation's Sparrows
Point complex,
o 57 MW of rated capacity of the Baltimore Refuse Energy Systems
Company, and
o 130 MW of Susquehanna capacity from PP&L.
In 1994 PECO Energy won a competitive bidding program to supply us 140 MW
of firm electric capacity and associated energy for 25 years beginning June 1,
1998. The Federal Energy Regulatory Commission and the Maryland PSC have both
accepted this contract.
6
FUEL FOR ELECTRIC GENERATION
Our electric generation by type of fuel and the cost of each fuel in the
five-year period 1993-1997 are shown below:
AVERAGE COST OF FUEL CONSUMED
GENERATION BY FUEL TYPE ((CENTS) PER MILLION BTU)
------------------------------------ ----------------------------------------------
1997 1996 1995 1994 1993 1997 1996 1995 1994 1993
---- ---- ---- ---- ---- ------ ------ ------ ------ ------
Nuclear (a)................... 44% 40% 43% 39% 43% 46.51 47.29 47.22 52.06 53.01
Coal.......................... 59 58 57 56 55 140.41 143.80 148.64 148.64 151.85
Oil........................... 1 1 1 3 3 283.61 313.33 267.59 245.28 253.36
Hydro & Gas................... 3 4 3 3 3 -- -- -- -- --
---- ---- ---- ---- ----
107 103 104 101 104
Net Interchange Purchases
(Sales)....................... (7) (3) (4) (1) (4)
---- ---- ---- ---- ----
100% 100% 100% 100% 100%
==== ==== ==== ==== ====
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(a) Nuclear fuel costs include disposal costs associated with long-term off-site
spent fuel storage and shipping, which is currently set by law at one mill
per kilowatt-hour of nuclear generation (approximately 10 cents per million
Btu), and contributions to a fund for decommissioning and decontaminating
the Department of Energy's uranium enrichment facility. We discuss this
further below.
NUCLEAR
The supply of fuel for nuclear generating stations includes the:
o purchase of uranium concentrates,
o conversion to uranium hexafluoride,
o enrichment of uranium hexafluoride, and
o fabrication of nuclear fuel assemblies.
Information is shown below about fuel requirements for Calvert Cliffs Units 1
and 2:
Uranium We have, either in inventory or under
Concentrates: contract, sufficient quantities of
uranium to meet 70 to 80% of our
requirements through 2004.
Conversion: We have contractual commitments
providing for the conversion of
uranium concentrates into uranium
hexafluoride which will meet
approximately 75% of our requirements
through 2004.
Enrichment: We have a contract with the U.S.
Enrichment Corporation for the
enrichment of 100% of our enrichment
requirements through 1998, declining
to approximately 50% by 2004.
Fuel Assembly We have contracted for the
Fabrication: fabrication of fuel assemblies for
reloads required through 2013.
The nuclear fuel market is very competitive and we do not anticipate any
problem in meeting our requirements beyond the periods noted above. We discuss
our expenditures for nuclear fuel in ITEM 7. MD&A -- LIQUIDITY AND CAPITAL
RESOURCES.
STORAGE OF SPENT NUCLEAR FUEL: Under the Nuclear Waste Policy Act of 1982
(the 1982 Act), we are required to place spent fuel discharged from Calvert
Cliffs into a federal repository. Such facilities do not currently exist, and,
consequently, must be developed and licensed. We cannot predict when such
facilities will be available. However, the 1982 Act requires the federal
government to accept spent fuel starting in 1998. We cannot predict what the
ultimate cost to dispose of the spent fuel will be. However, the 1982 Act
assesses a one mill per kilowatt-hour fee on nuclear electricity generated and
sold. We estimate this fee to be approximately $13 million for Calvert Cliffs
each year based on expected operating levels. Fees are deposited into the
Nuclear Waste Fund.
In December 1996, the United States Department of Energy (DOE) notified us
and other nuclear utilities that it is unable to meet the 1998 deadline for
accepting spent fuel. We are participating in litigation, along with 36 other
utilities, against the DOE. The litigation, titled NORTHERN STATES POWER, ET AL.
V. DOE, was filed January 31, 1997 in the United States Court of Appeals for the
D.C. Circuit. That court has original jurisdiction under the 1982 Act. The
utilities asked the court to allow them to pay fees, that formerly went directly
to DOE for deposit into the Nuclear Waste Fund, into escrow instead. Among other
remedies, the utilities also asked the court to force DOE to submit a program
with milestones illustrating how it would meet the deadline for accepting spent
nuclear fuel, and a monthly report to allow the utilities to monitor DOE's
progress.
7
On November 14, 1997 the court ordered DOE to comply with its unconditional
obligation under the 1982 Act to dispose of spent fuel. The court did not grant
the utilities the remedies sought, stating that adequate contractual and
statutory remedies already existed. The DOE and one utility have filed separate
motions for reconsideration with the court. In its motion for reconsideration,
DOE has advised the court that damage claims for breach of its spent fuel
disposal contracts would be paid from the Nuclear Waste Fund. Any shortfall in
funding would be replenished by increasing utility fees. This would render the
utilities' contract remedies meaningless. On February 19, 1998 the 36 utilities,
including BGE, filed a joint motion to enforce the court's order. Similar
motions were filed by six additional utilities. These 42 utilities represent
virtually the entire nuclear industry. The motions request:
o that the damages for breach not be paid by DOE from the Nuclear
Waste Fund,
o that DOE establish, in good faith, a program for immediate
disposal of spent fuel, specifying milestones,
o that the utilities be allowed to withhold future payment into the
Nuclear Waste Fund unless and until DOE complies with its obligations to
dispose of spent fuel, and
o that utilities not be penalized by DOE for withholding future
payments.
BGE is currently evaluating its contract options in light of the court's
decision. BGE cannot currently estimate the total amount of the costs it will
incur as a result of DOE's failure to meet the 1998 deadline.
Maryland law makes it unlawful to establish within the State a facility for
the permanent storage of high-level nuclear waste, unless required by federal
law. We received a license from the Nuclear Regulatory Commission to operate our
on-site independent spent fuel storage facility. We now have storage capacity at
Calvert Cliffs that will accommodate spent fuel from operations through the year
2006. In addition, we can expand our temporary storage capacity to meet future
requirements until federal storage is available.
COSTS FOR DECOMMISSIONING URANIUM ENRICHMENT FACILITIES: The Energy Policy
Act of 1992 (the 1992 Act) contains provisions requiring domestic utilities to
contribute to a fund for decommissioning and decontaminating the Department of
Energy's (DOE) uranium enrichment facilities. These contributions are generally
payable over a fifteen-year period with escalation for inflation and are based
upon the amount of uranium enriched by DOE for each utility through 1992. The
1992 Act provides that these costs are recoverable through utility service rates
as a cost of fuel. Information about the cost of decommissioning is discussed in
NOTE 1 TO CONSOLIDATED FINANCIAL STATEMENTS under the heading "UTILITY PLANT,
DEPRECIATION AND AMORTIZATION, AND DECOMMISSIONING."
COAL
We get most of our coal under supply contracts with mining operators, and
we get the rest through spot purchases. We believe that we will be able to renew
supply contracts as they expire or enter into similar contracts with other coal
suppliers. Our coal-burning facilities have the following requirements:
ANNUAL COAL
REQUIREMENT
(TONS)
------------------
Brandon Shores (a)
Units 1 and 2 (combined)........ 3,500,000
Crane (b)
Units 1 and 2 (combined)........ 700,000
Wagner (c)
Units 2 and 3 (combined)........ 900,000
- ---------------
Special Coal Restrictions:
(a) Sulfur content less than 0.8%
(b) Low ash melting temperature
(c) Sulfur content no more than 1%
Coal deliveries to our coal burning facilities are made by rail and barge.
The coal we use is produced from mines located in central and northern
Appalachia.
We have a 20.99% undivided interest in the Keystone coal-fired generating
plant and a 10.56% undivided interest in the Conemaugh coal-fired generating
plant. Both of these plants are located in Pennsylvania. The bulk of the annual
coal requirements for the Keystone plant is under contract from Rochester and
Pittsburgh Coal Company. The Conemaugh plant purchases coal from local suppliers
on the open market.
OIL
Under normal burn practices, BGE's requirements for residual fuel oil
amount to approximately 1,000,000 barrels of low-sulfur oil per year. Deliveries
of residual fuel oil are made directly into BGE barges from the suppliers'
Baltimore Harbor marine terminal for distribution to the various generating
plant locations.
GAS
We have a firm natural gas transportation entitlement of 3,500 dekatherms a
day to provide ignition and banking at certain power plants. We purchase gas for
electric generation as needed in the spot market using interruptible
transportation arrangements. Some of our gas fired units can use residual fuel
oil instead of gas.
8
ELECTRIC OPERATING STATISTICS
YEAR ENDED DECEMBER 31,
--------------------------------------------------------
1997 1996 1995 1994 1993
-------- -------- -------- -------- --------
Electric Output (In Thousands) -- MWH:
Generated............................................. 31,289 30,107 30,548 28,413 28,907
Purchased (A)......................................... 4,737 7,560 7,403 6,270 3,643
-------- -------- -------- -------- --------
Subtotal......................................... 36,026 37,667 37,951 34,683 32,550
Less Interchange and Other Sales...................... 6,224 7,580 8,149 5,684 4,149
-------- -------- -------- -------- --------
Total Output..................................... 29,802 30,087 29,802 28,999 28,401
======== ======== ======== ======== ========
Power Generated and Purchased at Times of Peak Load (MW)
(one hour):
Generated by Company.................................. 5,472 4,789 5,162 3,384 5,245
Net Purchased (A)..................................... 508 1,166 785 2,654 631
-------- -------- -------- -------- --------
Peak Load (B)......................................... 5,980 5,955 5,947 6,038 5,876
======== ======== ======== ======== ========
Annual System Load Factor (%)........................... 56.9 57.5 57.2 54.7 55.2
Revenues (In Millions)
Residential........................................... $ 932.5 $ 958.7 $ 955.2 $ 931.7 $ 931.7
Commercial............................................ 892.6 861.3 879.4 853.0 869.8
Industrial............................................ 211.9 207.6 208.5 205.6 199.0
-------- -------- -------- -------- --------
System Sales.......................................... 2,037.0 2,027.6 2,043.1 1,990.3 2,000.5
Interchange and Other Sales........................... 132.7 155.9 167.0 118.0 91.5
Other................................................. 22.3 25.5 21.0 19.1 20.1
-------- -------- -------- -------- --------
Total............................................ $2,192.0 $2,209.0 $2,231.1 $2,127.4 $2,112.1
======== ======== ======== ======== ========
Sales (In Thousands) -- MWH:
Residential........................................... 10,806 11,243 10,966 10,670 10,614
Commercial............................................ 12,718 12,591 12,635 12,351 12,395
Industrial............................................ 4,575 4,596 4,591 4,433 3,763
-------- -------- -------- -------- --------
System Sales.......................................... 28,099 28,430 28,192 27,454 26,772
Interchange and Other Sales........................... 6,224 7,580 8,149 5,684 4,149
-------- -------- -------- -------- --------
Total............................................ 34,323 36,010 36,341 33,138 30,921
======== ======== ======== ======== ========
Customers (In Thousands)
Residential........................................... 1,001.0 995.2 988.2 978.6 968.2
Commercial............................................ 105.9 104.5 103.4 101.9 100.8
Industrial............................................ 4.5 4.3 4.1 4.0 3.8
-------- -------- -------- -------- --------
Total............................................ 1,111.4 1,104.0 1,095.7 1,084.5 1,072.8
======== ======== ======== ======== ========
Average Cost of Fuel Consumed ((cents) per million
BTU).................................................. 105.76 108.05 104.78 112.44 112.77
======== ======== ======== ======== ========
We achieved an all-time peak load of 6,038 megawatts on January 19, 1994.
- ---------------
(A) Includes purchases from Safe Harbor Water Power Corporation, a hydroelectric
company, of which we own two-thirds of the capital stock.
(B) We discuss active load management programs which may be activated at times
of peak load in ELECTRIC LOAD MANAGEMENT, ENERGY, AND CAPACITY PURCHASES.
9
GAS OPERATING STATISTICS
YEAR ENDED DECEMBER 31,
--------------------------------------------------------
1997 1996 1995 1994 1993
-------- -------- -------- -------- --------
Gas Output (In Thousands) -- DTH:
Purchased.......................................... 62,988 70,260 70,391 68,541 71,221
LNG Withdrawn from Storage......................... 484 904 815 698 725
Produced........................................... 541 784 528 828 259
-------- -------- -------- -------- --------
Total Output.................................. 64,013 71,948 71,734 70,067 72,205
Delivery service gas (A)........................... 52,629 45,964 43,854 41,897 38,521
Off-system sales (B)............................... 17,611 10,204 -- -- --
-------- -------- -------- -------- --------
Total......................................... 134,253 128,116 115,588 111,964 110,726
======== ======== ======== ======== ========
Peak Day Sendout (DTH)............................... 765,011 708,966 706,287 761,900 657,700
======== ======== ======== ======== ========
Capability on Peak Day (DTH)......................... 870,000 870,000 847,000 847,000 847,000
Revenues (In Millions)
Residential
Excluding Delivery Service...................... $ 321.7 $ 320.1 $ 248.3 $ 262.7 $ 265.6
Delivery Service (C)............................ 0.5 -- -- -- --
Commercial
Excluding Delivery Service...................... 113.5 125.1 109.9 121.0 121.8
Delivery Service................................ 12.9 7.2 3.7 2.3 3.3
Industrial
Excluding Delivery Service...................... 11.4 17.1 16.7 20.2 22.3
Delivery Service................................ 17.2 14.6 16.3 9.6 12.9
-------- -------- -------- -------- --------
System sales....................................... 477.2 484.1 394.9 415.8 425.9
Off-system sales................................... 37.5 26.6 -- -- --
-------- -------- -------- -------- --------
Other.............................................. 6.9 6.6 5.6 5.4 7.3
-------- -------- -------- -------- --------
Total......................................... $ 521.6 $ 517.3 $ 400.5 $ 421.2 $ 433.2
======== ======== ======== ======== ========
Sales (In Thousands) -- DTH:
Residential
Excluding Delivery Service...................... 39,958 43,784 40,211 40,279 40,029
Delivery Service................................ 205 -- -- -- --
Commercial
Excluding Delivery Service...................... 18,435 22,698 23,612 23,712 23,830
Delivery Service................................ 12,964 8,755 6,982 6,490 7,428
Industrial
Excluding Delivery Service...................... 2,016 2,887 4,102 4,410 5,298
Delivery Service................................ 38,791 36,201 35,925 33,837 31,390
-------- -------- -------- -------- --------
System sales....................................... 112,369 114,325 110,832 108,728 107,975
Off-system sales................................... 17,611 10,204 -- -- --
-------- -------- -------- -------- --------
Total......................................... 129,980 124,529 110,832 108,728 107,975
======== ======== ======== ======== ========
Customers (In Thousands)
Residential........................................ 524.5 516.5 506.8 498.2 491.2
Commercial......................................... 39.3 38.9 38.4 37.9 37.5
Industrial......................................... 1.3 1.3 1.3 1.3 1.3
-------- -------- -------- -------- --------
Total......................................... 565.1 556.7 546.5 537.4 530.0
======== ======== ======== ======== ========
We achieved an all-time peak day sendout of 765,011 DTH on January 18,
1997.
- ---------------
(A) Delivery service gas is gas purchased by customers directly from suppliers
for which we receive a fee for transportation through our system. We discuss
this further in ITEM 7. MD&A -- RESULTS OF OPERATIONS.
(B) Off-system sales are low-margin sales to wholesale suppliers of natural gas
outside our service territory (beginning first quarter 1996). We discuss
this further in ITEM 7. MD&A -- RESULTS OF OPERATIONS.
(C) Residential delivery service represents sales of gas through our Gas Options
pilot program that we began in late 1997. We discuss this program further in
the GAS REGULATORY MATTERS AND COMPETITION section.
10
GAS BUSINESS
We discuss our utility gas business on the previous page under GAS
OPERATING STATISTICS and in three other sections of this report: GAS REGULATORY
MATTERS AND COMPETITION; GAS OPERATIONS; AND GAS RATE MATTERS. We discuss our
gas marketing business separately under the heading DIVERSIFIED BUSINESSES.
GAS REGULATORY MATTERS AND
COMPETITION
To introduce competition, the natural gas industry is being deregulated,
and regulatory changes are well under way.
In 1992, the Federal Energy Regulatory Commission issued Order 636, which
increased gas users' ability to choose various gas purchasing, transportation,
brokering, and storage options. Consequently, we now buy all gas that we resell
directly from various suppliers (rather than pipeline companies) and arrange
separately for transportation and storage. We offer gas for sale to our
residential customers on a firm basis, and to our commercial and industrial
customers on a firm or interruptable basis. Alternatively, we can transport gas
for our customers. We also participate in the interstate markets, by releasing
pipeline capacity or bundling pipeline capacity with gas for off-system sales.
We provide our commercial and industrial customers who annually consume 250
DTH or more of gas with transportation service across our distribution system so
that they may make direct purchase and transportation arrangements with
suppliers and pipelines. Approximately 46% of the gas on our distribution system
is for these customers. We charge a fee for this transportation service. This
per unit charge assures that fixed costs are spread over the maximum number of
DTH. We also provide balancing and gas brokering services for these customers.
The Maryland PSC continues to encourage us and other utilities to offer
options for unbundling gas services and to allow smaller customers to arrange
for their own gas supplies. In response, we began a two-year Gas Options pilot
program for residential customers on November 1, 1997. Under the program:
o all of our residential natural gas customers are eligible, but
only up to 25,000 of them may participate (about 12,000 customers
currently participate).
o participants may shop for a natural gas supplier from a list of
companies, including one of our diversified businesses,
participating in the program.
o we continue to deliver the gas to customers' homes, and provide
customer services such as meter reading, billing, emergency
response, and regular maintenance.
Our Gas Options program is one of many natural gas pilot programs under way
across the country.
The Gas Options program and our delivery service should not significantly
impact our gas business earnings.
As part of our response to the increase in competition in the natural gas
business, we obtained approval from the Maryland PSC to utilize profit sharing
for earnings from off-system gas sales and capacity release revenues, and to
implement a market based rates incentive mechanism for gas sold by BGE on our
system. Off-system gas sales are direct sales to suppliers and end users of
natural gas outside our service territory. We make these sales as part of a
program to balance our supply of, and cost of, natural gas. Under market based
rates our actual cost of gas is compared to a market index (a measure of the
market price of gas in a given period). The difference between our actual cost
and the market index is shared equally between BGE (which benefits shareholders)
and customers.
GAS OPERATIONS
We distribute natural gas purchased directly from many producers and
marketers. We have transportation and storage agreements as shown below. These
agreements are on file with the Federal Energy Regulatory Commission. The gas is
transported to our city gate, under various transportation agreements, by:
o Columbia Gas Transmission Corporation,
o CNG Transmission Corporation, and
o Transcontinental Gas Pipe Line Corporation.
We have upstream transportation capacity under contract with:
o Tennessee Gas Pipeline Company,
o Texas Eastern Transmission Corporation,
o Columbia Gulf Transmission Company, and
o ANR Pipeline Company.
We have storage service agreements with:
o Columbia Gas Transmission Corporation,
o CNG Transmission Corporation, and
o ANR Pipeline Company.
Our current pipeline firm transportation entitlements to serve our firm
loads are 291,731
11
dekatherms (DTH) per day during the winter period and 266,731 DTH per day during
the summer period. We use the firm transportation capacity to move gas from the
Gulf of Mexico, Louisiana, south central regions of Texas and Canada to our city
gate. The gas is subject to a mix of long and short-term contracts that are
managed to provide economic, reliable, and flexible service. We can arrange
additional short-term contracts or exchange agreements with other gas companies
in the event of short-term emergencies.
We have three market area storage contracts to manage weather sensitive gas
demand during the winter period. Our current maximum storage entitlements are
224,435 DTH per day. To supplement our gas supply at times of heavy winter
demands and to be available in temporary emergencies affecting gas supply, we
have:
o a liquified natural gas facility for the liquefaction and storage
of natural gas with a storage capacity of 1,000,000 DTH and a
planned daily capacity of 287,988 DTH, and
o a propane air facility with a mined cavern and refrigerated
storage facilities having a total storage capacity equivalent to
1,000,000 DTH and a daily capacity of 85,000 DTH.
We have under contract sufficient volumes of propane for the operation of
the propane air facility and are capable of liquefying sufficient volumes of
natural gas during the summer months for operation of our liquefied natural gas
facility during winter periods.
GAS RATE MATTERS
POSTRETIREMENT AND POSTEMPLOYMENT BENEFIT
COSTS
Beginning in 1998, the Maryland PSC authorized us to make a change in the
way we account for postretirement and other postemployment benefit costs. The
Maryland PSC authorized us to amortize deferred postretirement and other
postemployment benefit costs related to our utility business over 15 years. The
Maryland PSC will adjust our gas base rates to recover the higher costs that
will be recognized in 1998. We discuss this also in the ELECTRIC RATE MATTERS
section and in NOTE 6 TO CONSOLIDATED FINANCIAL STATEMENTS.
1997 RATE CASE
During 1997, we applied for a $36.7 million increase in our gas base rates.
We applied for the increase to:
o provide a return on a higher level of gas rate base, due to
expansion of our gas distribution system and future capital
expenditures to meet customer growth,
o provide for an overall rate of return of 9.36% versus 9.04% (our
presently authorized rate), and
o to recover future increases in operating expenses that we have
committed to make.
In February 1998, we reached a settlement with the Maryland PSC for a $16
million increase in our gas base rates. The increase became effective March 1,
1998.
FRANCHISES
We have nonexclusive electric and gas franchises to use streets and other
highways which are adequate and sufficient to permit us to engage in our present
business. All such franchises, other than the gas franchises in Manchester,
Hampstead, Perryville, Sykesville, Havre de Grace, Mt. Airy, and Montgomery and
Frederick Counties, are unlimited as to time. The gas franchises for these
jurisdictions expire at various times from 2015 to 2087, except for Havre de
Grace which has the right, exercisable at twenty-year intervals from 1907, to
purchase all of our gas properties in that municipality. Conditions of the
franchises are satisfactory. We also have rights-of-way to maintain 26-inch
natural gas mains across certain Baltimore City owned property (principally
parks) which expire in 1998 and 2004, each subject to renewal during their last
year for an additional period of 25 years on a fair revaluation of the rights so
granted. Conditions of the grants are satisfactory.
Franchise provisions relating to rates have been superseded by the Public
Service Commission Law of Maryland.
DIVERSIFIED BUSINESSES
Our diversified businesses are organized in three groups:
o Our power generation, financial investments, and real estate
businesses,
o Our energy marketing businesses, and
o Our home products and commercial building systems businesses.
12
OUR POWER GENERATION, FINANCIAL INVESTMENTS,
AND REAL ESTATE BUSINESSES
We refer to all of these together as the Constellation Holdings Companies.
Constellation Holdings, Inc. is a subsidiary of BGE and holds all of the stock
of the following three subsidiaries:
o Constellation Power, Inc. -- develops, owns, and operates power
generation projects,
o Constellation Investments, Inc. -- engages in financial
investments, and
o Constellation Real Estate Group, Inc. -- develops, owns, and
manages real estate and senior-living facilities.
The Constellation Holdings Companies' conduct a significant portion of
their activities through joint ventures in which they hold varying ownership
interests.
POWER GENERATION
Domestic
The Constellation Holdings Companies hold up to a 50% ownership interest in
23 power generating projects in operation accounting for $393 million of the
Constellation Holdings Companies' assets. These projects, all of which either
are qualifying facilities under the Public Utility Regulatory Policies Act of
1978 or are otherwise exempt from the Public Utility Holding Company Act of
1935, are of the following types and aggregate generation capacities:
o coal-166 MW o waste coal-185 MW
o solar-90 MW o wood burning-70 MW
o geothermal-126 MW o hydro-33 MW
In addition, the Constellation Holdings Companies:
o have spent another $17 million on projects in development,
o participate in the operation and maintenance of 13 power
generation projects existing or under construction, 12 of which
are projects in which the Constellation Holdings Companies hold an
ownership interest, and
o have invested $10.8 million in a coal processing facility that
they operate.
The Constellation Holdings Companies also invest in international power
projects. These are discussed later in this section.
CALIFORNIA POWER PURCHASE AGREEMENTS
The Constellation Holdings Companies have $261 million invested in 16
projects that sell electricity in California under power purchase agreements
called "Interim Standard Offer No. 4" agreements. Earnings from these projects
were $37.3 million, or $.25 per share, in 1997.
Under these agreements, the electricity rates are scheduled to change from
fixed rates to variable rates during 1996 through 2000. Some of the projects
have already had rate changes and have had lower revenues under variable rates
than they did under fixed rates. When the remaining projects transition to
variable rates, we expect the revenues from those projects to also be lower than
they are under fixed rates. However, the California projects that make the
highest revenues will not transition until 1999 and 2000. As a result, we do not
expect the Constellation Holdings Companies to have significantly lower earnings
due to the transition to variable rates before 2000. We cannot predict the
financial effects of the transition from fixed to variable rates on the
Constellation Holdings Companies or on BGE, but the effects could be material.
We describe these projects and the transition process in detail in NOTE 12
TO CONSOLIDATED FINANCIAL STATEMENTS.
International
The Constellation Holdings Companies' power generation business in Latin
America:
o develops, acquires, owns, and operates power generation projects, and
o acquires and owns distribution systems.
At December 31, 1997, the Constellation Holdings Companies had invested
about $23.1 million and committed another $4.3 million in power projects in
Latin America.
In the future, the Constellation Holdings Companies' power generation
business may be expanding further in both domestic and international projects.
FIRST QUARTER 1998 EVENT INCLUDES CONSTELLATION HOLDINGS COMPANIES' GUARANTEE
OF $73 MILLION
In the first quarter of 1998, affiliates of the Constellation Holdings
Companies entered into a $92.5 million credit facility to finance the
acquisition of
13
existing generating facilities and the development and construction of new
generating facilities in Guatemala. At the date of this report, the
Constellation Holdings Companies' obligation under the facility is $73 million.
FINANCIAL INVESTMENTS
Financial investments account for $197 million of the Constellation
Holdings Companies' assets. These assets include:
o $77 million in internally and externally managed securities portfolios,
o $89 million in a financial guaranty insurance company, and
o $31 million in tax-oriented transactions.
REAL ESTATE
Real estate and senior-living projects account for $509 million of the
Constellation Holdings Companies' assets. These projects include:
o land under development,
o office buildings,
o retail projects,
o distribution facility projects,
o an entertainment, dining, and retail complex in Orlando, Florida,
o a mixed-use planned-unit development,
o and senior-living facilities.
In 1997, the Constellation Holdings Companies recorded:
o a $14.1 million after-tax write-down of the investment in Church
Street Station -- an entertainment, dining, and retail complex in
Orlando, Florida -- because the Constellation Holdings Companies
have now decided to sell rather than keep the project, and
o a $31.9 million after-tax write-down of the investment in Piney
Orchard -- a mixed-use, planned-unit development -- because the
expected cash flow from the project was less than the
Constellation Holdings Companies' investment in the project.
We consider market demand, interest rates, the availability of financing,
and the strength of the economy in general when making decisions about our real
estate investments. If we were to sell our real estate projects in the current
market, we would have losses, although the amount of the losses is hard to
predict. Depending on market conditions in the future, we could also have losses
on any future sales.
We describe the Constellation Holdings Companies' real estate business
further in NOTE 12 TO CONSOLIDATED FINANCIAL STATEMENTS.
OUR ENERGY MARKETING BUSINESSES
Constellation Energy Solutions, Inc. is a subsidiary of BGE and serves as
the holding company for our three energy marketing businesses:
o Constellation Power Source(TM), Inc. -- our power marketing business,
o Constellation Energy Source(TM), Inc. -- our natural gas brokering
business, and
o Constellation Energy Projects and Services(TM), Inc. and Subsidiaries --
our energy services businesses.
POWER MARKETING
We formed CONSTELLATION POWER SOURCE, INC. in February 1997 to enter the
power marketing business. This new business provides power marketing and risk
management services to wholesale customers in North America by purchasing and
selling electric power, other energy commodities, and related derivatives.
Goldman Sachs Power, LLC, an affiliate of Goldman, Sachs & Co., the
investment banking firm, is the exclusive advisor to Constellation Power Source
for these services.
Constellation Power Source's business activities include trading:
o electricity,
o other energy commodities, and
o related derivative contracts.
Constellation Power Source uses the mark-to-market method of accounting for
these activities. Under the mark-to-market method of accounting, Constellation
Power Source:
o records assets and liabilities equal to the fair value of
commodities and derivatives it holds or sells,
o records these assets and liabilities at the time that it executes
contracts for these transactions, and
o records net gains and losses from both realized transactions and
changes in fair value of open commodity and derivative positions
as revenues in its income statement.
As a result of using the mark-to-market method of accounting, Constellation
Power
14
Source's revenue and earnings will fluctuate. The primary factors that cause
these fluctuations are:
o the number and size of new transactions,
o the magnitude and volatility of changes in commodity prices and
interest rates, and
o the number and size of open commodity and derivative positions
Constellation Power Source holds or sells.
Constellation Power Source management uses its best estimates to determine
the fair value of the commodities and derivatives positions it holds and
sells. These estimates consider various factors including closing exchange and
over-the-counter price quotations, time value, and volatility factors. However,
it is possible that future market prices could vary from those used in recording
assets and liabilities from trading activities, and such variations could be
material.
FIRST QUARTER 1998 EVENT INCLUDES BGE COMMITMENT OF
$115 MILLION
In March 1998, Constellation Power Source, Inc. and Goldman, Sachs Capital
Partners II L.P., an affiliate of Goldman, Sachs & Co., formed Orion Power
Holdings, Inc. to acquire electric generating plants in the United States and
Canada. Constellation Power Source owns a minority interest in Orion, and BGE
has committed to contribute up to $115 million in equity to Constellation Power
Source to fund its investment in Orion. Orion has entered into strategic
relationships with Constellation Power Source and Constellation Operating
Services, Inc. Constellation Power Source will be the exclusive provider of
power marketing and risk management services to Orion. Constellation Operating
Services will provide exclusive operating and maintenance services to Orion's
plants.
NATURAL GAS BROKERING
CONSTELLATION ENERGY SOURCE, INC. provides natural gas brokering and
related services for wholesale and retail customers.
ENERGY SERVICES
CONSTELLATION ENERGY PROJECTS & SERVICES, INC. AND ITS SUBSIDIARIES provide
a broad range of customized energy services, including:
o private electric and gas distribution systems,
o energy consulting,
o power quality services and equipment,
o campus and multi-building energy systems, and
o energy services contract work.
COMFORTLINK(REGISTER MARK) (a general partnership in which BGE is a
partner) provides district energy systems.
OUR HOME PRODUCTS AND COMMERCIAL BUILDING
SYSTEMS BUSINESSES
BGE HOME PRODUCTS & SERVICES, INC. provides comprehensive maintenance,
repair and replacement services for heating, air conditioning, plumbing,
electrical, indoor air quality systems, and major home appliances and
electronics. It also operates appliance and electronics retail stores and has a
home improvement business including kitchen and bathroom remodeling, replacement
doors and windows, siding, and roofing. Its subsidiary, BGE COMMERCIAL BUILDING
SYSTEMS, INC. (formerly named Maryland Environmental Systems, Inc.) specializes
in providing total building solutions for the commercial market. These services
include comprehensive maintenance, repair, replacement and new equipment
installation services for heating, ventilation, air conditioning, plumbing,
electrical, and building automation systems in small and large commercial
facilities. In 1997, BGE Home Products & Services, Inc. formed HP&S RECEIVABLES,
INC. -- solely to acquire and finance merchandise and service loans made by BGE
Home Products & Services, Inc.
15
DIVERSIFIED BUSINESS CAPITAL REQUIREMENTS
Capital requirements for our diversified businesses for 1995 through 1997,
along with estimated amounts for 1998 through 2000, are set forth below:
1995 1996 1997 1998 1999 2000
---- ---- ---- ---- ---- ----
(IN MILLIONS)
Diversified Business Capital Requirements
Investment requirements........................................... $118 $118 $156 $169 $134 $157
Retirement of long-term debt...................................... 55 52 188 164 137 246
---- ---- ---- ---- ---- ----
Total diversified business capital requirements................... $173 $170 $344 $333 $271 $403
==== ==== ==== ==== ==== ====
In the past, capital requirements of our diversified businesses only
included the Constellation Holdings Companies because they had the only
significant capital requirements. From time to time, however, our other
diversified businesses may develop significant capital requirements. As that
occurs, we will include the capital requirements of those businesses in the
capital requirements table. As discussed below under "DIVERSIFIED BUSINESS
INVESTMENT REQUIREMENTS," capital requirements for Constellation Power Source
and ComfortLink are also included this year.
Our diversified businesses expect to expand their businesses. This may
include expansion in the energy marketing, power generation, financial
investments, real estate, and senior-living facility businesses. Such expansion
could mean more investments in and acquisition of new projects. Our diversified
businesses have met their capital requirements in the past through borrowing,
cash from their operations, and from time to time, loans or equity contributions
from BGE. Our diversified businesses plan to raise the cash needed to meet
capital requirements in the future through these same methods.
DIVERSIFIED BUSINESS INVESTMENT REQUIREMENTS
The investment requirements of our diversified businesses include:
o the Constellation Holdings Companies' investments in financial
limited partnerships and funding for the development and
acquisition of projects, as well as loans made to project
entities,
o funding for growing Constellation Power Source's power marketing
business, and
o ComfortLink's funding for construction of district energy
projects.
Investment requirements for the years 1998 through 2000 include estimates
of funding for existing and anticipated projects. We continuously review and
modify those estimates. Actual investment requirements could vary a great deal
from the estimates in the table because they would be subject to several
variables, including:
o the type and number of projects selected for development,
o the effect of market conditions on those projects,
o the ability to obtain financing, and
o the availability of cash from operations.
The investment requirements exclude BGE's commitment to contribute up to
$115 million in equity to Constellation Power Source Inc. to fund its investment
in Orion Power Holdings, Inc.
DIVERSIFIED BUSINESS DEBT AND LIQUIDITY
Our diversified businesses plan to meet capital requirements by refinancing
debt as it comes due, by borrowing additional funds, and using cash generated by
the businesses. This includes cash from operations, sale of assets, and earned
tax benefits. BGE Home Products & Services, Inc. may also meet capital
requirements through sales of receivables.
If the Constellation Holdings Companies can get a reasonable value for real
estate, additional cash may be obtained by selling real estate projects. The
Constellation Holdings Companies' ability to sell or liquidate assets will
depend on market conditions, and we cannot give assurances that these sales or
liquidations could be made. For more information, see the discussion of the real
estate business and market in the REAL ESTATE section.
16
In 1997, the Constellation Holdings Companies issued $289 million of three
and four-year notes. In addition, our diversified businesses have the following
revolving credit agreements to provide additional cash for short-term financial
needs:
AMOUNT OF
REVOLVING CREDIT AGREEMENT
--------------------------
Constellation Holdings
Companies................ $75 million
ComfortLink................ $50 million
Constellation Energy
Solutions, Inc. and
Subsidiaries............. $10 million
See NOTES 3 and 4 TO CONSOLIDATED FINANCIAL STATEMENTS AND ITEM 7.
MD&A -- LIQUIDITY AND CAPITAL RESOURCES -- CAPITAL REQUIREMENTS OF OUR
DIVERSIFIED BUSINESSES for additional information about diversified businesses.
ENVIRONMENTAL MATTERS
We are subject to regulation by various federal, state, and local
authorities with regard to:
o air quality,
o water quality,
o waste disposal, and
o other environmental matters.
Some of the regulations require substantial expenditures for additions to
our utility plant and the use of more expensive low-sulfur fuels. We cannot
precisely estimate the total effect on our facilities and operations of current
and future environmental regulations and standards. However, we have increased
capital expenditures by approximately $117 million during the five-year period
1993-1997 to comply with existing standards and regulations, and we estimate
that the future capital expenditures necessary to comply with the standards and
regulations will be approximately:
o $14 million in 1998,
o $17 million in 1999, and
o $36 million in 2000.
CLEAN AIR
The Federal Clean Air Act (the Act) regulates health and welfare standards
for concentrations of air pollutants. Under the Act, the State of Maryland must
set limits on all major sources of these pollutants in the State so that the
standards are not exceeded. We have certain limits on our generating units that
put us in compliance with existing air quality regulations, as follows:
o All of our generating units, except Crane Units 1 and 2, are
limited to burning fuel (coal or oil) with a sulfur content of 1%
or below.
o The Crane Units 1 and 2 are limited to 3.5 pounds per million Btu
for sulfur dioxide, which is equivalent to a coal sulfur content
of approximately 2.4%.
o All units are limited to releasing particulate matter at or below
0.02 grains per standard cubic foot of exhaust gas for oil fired
units and 0.03 grains per standard cubic foot for coal-fired
units.
o Brandon Shores, a newer plant, is subject to more stringent
standards for sulfur dioxide (1.2 pounds per million Btu), and
nitrogen dioxide (0.7 pounds per million Btu).
The Clean Air Act of 1990 contains two titles designed to reduce emissions
of sulfur dioxide and nitrogen oxide (NOx) from electric generating
stations -- Title IV and Title I.
Title IV addresses emissions of sulfur dioxide. Compliance is required in
two separate phases:
o Phase I became effective January 1, 1995. We met the requirements
of this phase by installing flue gas desulfurization systems
(scrubbers), switching fuels, and retiring some units.
o Phase II must be implemented by 2000. We are currently examining
what actions we should take to comply with this phase. We expect
to meet the compliance requirements through some combination of
installing flue gas desulfurization systems (scrubbers), switching
fuels, retiring some units, or allowance trading.
Title I addresses emissions of NOx, but the regulations of this title have
not been finalized by the government. As a result, our plans for complying with
this title are less certain. By 1999 the regulations require more NOx controls
for ozone attainment at our generating plants. The additional controls will
result in more expenditures, but it is difficult to estimate the level of those
expenditures since the regulations have not been finalized. However, based on
existing and proposed regulations, we currently estimate that the additional
controls at our generating plants will cost approximately $90 million.
In July 1997, the federal government published new National Ambient Air
Quality Standards for very fine particulates and revised standards for ozone
attainment. These standards may require increased controls at our fossil
generating plants in the future. We cannot estimate the cost of these increased
controls at this time because the states,
17
including Maryland, still need to determine what reductions in pollutants will
be necessary to meet the new federal standards.
WATER
The Maryland Department of the Environment regulates the discharge of waste
materials into the waters of the State of Maryland under the National Pollutant
Discharge Elimination System permit program. This program was established as
part of the Federal Clean Water Act. At the present time, we have the required
permits under the program for all of our steam electric generating plants.
The Maryland Department of the Environment water quality regulations
require us to, among other things, define procedures to determine compliance
with State water quality standards. These procedures require extensive studies
involving sampling and monitoring of the waters around affected generating
plants. The State of Maryland may require changes in plant operations. We
continually perform studies to determine whether any modifications will be
necessary to comply with these regulations.
WASTE DISPOSAL
The United States Environmental Protection Agency (EPA) has regulations for
implementing the portions of the Resource Conservation and Recovery Act that
deal with the management of hazardous wastes. These regulations, and the
Hazardous and Solid Waste Amendments of 1984, identify certain spent materials
as hazardous wastes and establish standards and permit requirements for those
who generate, transport, store, or dispose of such wastes. The State of Maryland
has adopted regulations governing the management of hazardous wastes that are
similar to the federal regulations. We have procedures in place to comply with
all applicable federal and state regulations governing the management of
hazardous wastes. Some high volume utility wastes, such as fly ash and bottom
ash, are exempt from these regulations. We currently use almost all of our coal
fly ash and bottom ash as structural fill material in a manner approved by the
State of Maryland. We sell the remainder of the coal ash to the construction
industry for a number of approved uses.
The Federal Comprehensive Environmental Response, Compensation and
Liability Act (Superfund statute) establishes liability for the cleanup of
hazardous wastes that contaminate the soil, water, or air. Those who generated,
transported or deposited the waste at the contaminated site are each jointly and
severally liable for the cost of the cleanup, as are the current property owner
and the owner when the contamination occurred. Many states have implemented laws
similar to the Superfund statute.
On October 16, 1989, the EPA filed a complaint in the U.S. District Court
for the District of Maryland under the Superfund statute against us and seven
other defendants to recover past and future expenditures associated with the
cleanup of a site located at Kane and Lombard Streets in Baltimore. The State of
Maryland filed a similar complaint in the same case and court on February 12,
1990. The complaints alleged that we arranged for our fly ash to be deposited on
the site. The Court dismissed these complaints in November 1995. The Maryland
Department of the Environment began additional investigation on the remainder of
the site for the EPA, but never completed the investigation. We, along with
three other defendants, agreed to complete the remedial investigation and
feasibility study of groundwater contamination around the site in a July 1993
consent order. The remedial action, if any, for the remainder of the site will
not be selected until these investigations are concluded. Therefore, we cannot
estimate the total amount or our share of the site cleanup costs.
In the early 1970s, we shipped an unknown number of scrapped transformers
to Metal Bank of America, a metal reclaimer in Philadelphia. Metal Bank's scrap
and storage yard has been found to be contaminated with oil containing high
levels of PCBs (hazardous chemicals frequently used as a fire-resistant coolant
in electrical equipment). On December 7, 1987, the EPA notified us and nine
other utilities that we are considered potentially responsible parties (PRPs)
with respect to the cleanup of the site. We, along with the other PRPs,
submitted a remedial investigation and feasibility study (RI/FS) to the EPA on
October 14, 1994. The estimated costs for the possible remedies range greatly
(from $15 million to $45 million). Until a specific remedy is chosen, we are not
able to predict the actual cleanup costs. Our share of the cleanup costs,
estimated to be approximately 15.79%, could be material.
From 1985 until 1989, we shipped waste oil and other materials to the
Industrial Solvents and Chemical Company in York County, Pennsylvania for
disposal. The Pennsylvania Department of Environmental Resources (Pennsylvania
Department) subsequently investigated this site and found it to be heavily
contaminated by hazardous wastes. The Pennsylvania Department notified us on
August 15, 1990, that we and approximately 1,000 other entities are PRPs with
respect to the cost of all remedial activities to be conducted at the site. The
PRPs have performed waste characterization, removed and disposed of all tanks
and drums of waste, and
18
completed a RI/FS at the site. Our share of the waste sent to this site is
estimated to be approximately 2.7%, but this may change as additional
information about the site is obtained. We have not determined the actual cost
of remedial activities. As a result of these factors, our potential liability
cannot be estimated. However, we do not expect such liability to be material.
On August 30, 1994, we were named as a defendant in UNITED STATES V.
KEYSTONE SANITATION COMPANY, ET AL. The litigation was instituted by the EPA and
involved contamination of the Keystone Sanitation Company landfill Superfund
site located in Adams County, Pennsylvania. In 1997, BGE and other defendants
entered into a settlement with the EPA for an immaterial amount but the court
has not yet approved the settlement.
In December 1995, we were notified by the EPA that we are one of
approximately 650 parties that may have incurred liability under the Superfund
statute for shipments of hazardous wastes to a site in Denver, Colorado known as
the RAMP Industries site. We, through our disposal vendor, shipped a small
amount of low level radioactive waste to the site between 1989 and 1992. The
site, which was found to have been operated improperly, was closed in 1994. That
same year, the EPA began a clean up of the site which will consist of removal of
drums of radioactive and hazardous mixed wastes. After the EPA completes its
drum removal phase of the clean up it will investigate potential soil and
groundwater contamination. Although our potential liability cannot be estimated,
we do not expect such liability to be material based on the limited amount of
waste we shipped to the site.
In September 1996, we received an information request from the EPA about
the Drumco Drum Dump Site, located in the Curtis Bay area of Maryland. This site
was the subject of an emergency drum removal action in 1991, due to a concern
about hazardous substances leaking from drums and posing a threat to human
health and the environment. According to EPA documents, approximately $2 million
dollars was spent on the drum removal action. To our knowledge, no long-term
remediation is planned for this site. In addition, we understand that the EPA
has sent information requests to approximately 17 other parties. Our records
indicate that we sold empty drums to Drumco, Inc. from approximately 1983-1990.
Although our potential liability cannot be estimated, we do not expect such
liability to be material based on our records showing that we sold only empty
storage drums to Drumco, Inc.
In April 1997, we received an information request from the EPA concerning
the 68th Street Dump Site, also known as the Robb Tyler Dump, located in
Baltimore, Maryland. This site is not currently listed as a federal Superfund
site. We understand that the EPA has sent information requests to over 70 other
parties. Our response to the EPA is that our records do not show that we sent
waste to the site. This response is based on reviewing all relevant documents
and interviewing employees involved in waste disposal for the Company from 1950
to 1975, which is the period covered by the EPA's inquiry. Although our
potential liability cannot be estimated, we do not expect such liability to be
material based on our records showing that we did not send waste to the site.
In the early part of the century, predecessor gas companies (which were
later merged into BGE) manufactured coal gas for residential and industrial use.
The residue from this manufacturing process was coal tar, previously thought to
be harmless but now found to contain a number of chemicals designated by the EPA
as hazardous substances. We are coordinating an investigation of these former
manufacturing sites, which includes reviewing possible actions to remove coal
tar. In late December 1996, we signed a consent order with the Maryland
Department of the Environment that requires us to implement remedial action
plans for contamination at and around the Spring Gardens site. We have submitted
the required remedial action plans and the Maryland Department of the
Environment is in the process of reviewing them. Based on several remedial
action options, the costs we consider to be probable to remedy the contamination
are estimated to total $50 million in nominal dollars (including inflation). We
have recorded these costs as a liability on our Consolidated Balance Sheet and
have deferred these costs, net of accumulated amortization and amounts we
recovered from insurance companies, as a regulatory asset (we discuss this
further in NOTE 5 TO CONSOLIDATED FINANCIAL STATEMENTS). We are also required by
accounting rules to disclose additional costs we consider to be less likely than
probable costs, but still "reasonably possible" of being incurred at these
sites. Because of the results of studies at these sites, it is reasonably
possible that these additional costs could exceed the amount we recognized by
approximately $48 million in nominal dollars ($11 million in current dollars,
plus the impact of inflation at 3.1% over a period of up to 60 years).
EMPLOYEES
As of December 31, 1997, we employed about 9,000 people.
19
ITEM 2. PROPERTIES
We describe our electric and gas business properties separately below.
ELECTRIC
Our principal electric generating plants are shown below:
GENERATION (MWH)
INSTALLED PRIMARY -------------------------
PLANT LOCATION CAPACITY (MW) FUEL 1997 1996
- ------------------------- ------------------------ ------------- ------------- ---------- ----------
(AT DECEMBER 31, 1997)
Steam
Calvert Cliffs Calvert County, MD 1,675 Nuclear 13,133,441 12,069,937
Brandon Shores Anne Arundel County, MD 1,296 Coal 8,483,339 8,849,357
Herbert A. Wagner Anne Arundel County, MD 1,006 Coal/Oil/Gas 3,399,601 3,149,334
Charles P. Crane Baltimore County, MD 385 Coal 1,942,621 2,000,992
Gould Street Baltimore City, MD 104 Oil 89,115 49,583
Riverside Baltimore County, MD 78 Oil/Gas 14,480 15,356
Jointly Owned -- Steam
Keystone Armstrong and 359(A) Coal 2,788,081 2,650,786
Indiana Counties, PA
Conemaugh Indiana County, PA 181(A) Coal 1,294,234 1,202,914
Combustion Turbine
Notch Cliff Baltimore County, MD 128 Gas 14,024 12,470
Perryman Harford County, MD 350 Oil/Gas 106,748 91,197
Westport Baltimore City, MD 121 Gas 10,236 6,420
Riverside Baltimore County, MD 173 Oil/Gas 8,197 5,450
Philadelphia Road Baltimore City, MD 64 Oil 3,391 1,829
Charles P. Crane Baltimore County, MD 14 Oil 960 707
Herbert A. Wagner Anne Arundel County, MD 14 Oil 754 513
----- ---------- ----------
Totals 5,948 31,289,222 30,106,845
===== ========== ==========
- ---------------
(A) These totals reflect BGE's proportionate interest and entitlement to
capacity from Keystone and Conemaugh, which are 2 megawatts of diesel
capacity for Keystone and 1 megawatt of diesel capacity for Conemaugh.
We also own two-thirds of the outstanding capital stock of Safe Harbor Water
Power Corporation, and are currently entitled to 277 megawatts of the rated
capacity of the Safe Harbor Hydroelectric Project. Safe Harbor is operated under
a Federal Energy Regulatory Commission license which expires in the year 2030.
GAS
We own the following propane air and liquefied natural gas facilities:
o a liquefied natural gas facility for the liquefication and storage
of natural gas with a total storage capacity of 1,000,000 DTH and
a planned daily capacity of 287,988 DTH, and
o a propane air facility with a mined cavern and refrigerated
storage facilities with a total storage capacity of 1,000,000 DTH
and a planned daily capacity of 85,000 DTH.
GENERAL INFORMATION
We own our principal plants and other important units that are located in
Maryland including our principal headquarters building in downtown Baltimore. We
also lease several properties in our service area which are used for various
offices and services. We have electric transmission and electric and gas
distribution lines located:
o in public streets and highways pursuant to franchises, and
o on permanent rights-of-way secured for the most part by grants
from owners of the property and for a relatively small part by
condemnation.
We share the ownership of the properties for the Keystone and Conemaugh
Plants in Pennsylvania. There are minor liens and easements on the Keystone and
Conemaugh properties, but these encumbrances do not materially interfere with
our use of the properties.
All of our property referred to above is subject to the lien of our
mortgage securing our mortgage bonds.
20
ITEM 3. LEGAL PROCEEDINGS
ASBESTOS
Since 1993, we have been involved in several actions concerning asbestos.
All of the actions together are titled IN RE BALTIMORE CITY PERSONAL INJURIES
ASBESTOS CASES in the Circuit Court for Baltimore City, Maryland. The actions
are based upon the theory of "premises liability," alleging that we knew of and
exposed individuals to an asbestos hazard. The actions relate to two types of
claims.
The first type are direct claims by individuals exposed to asbestos. We
described these claims in a Report on Form 8-K filed August 20, 1993. We are
involved in these claims with approximately 70 other defendants. Approximately
520 individuals that were never employees of the Company each claim $6 million
in damages ($2 million compensatory and $4 million punitive). We do not know the
specific facts necessary to estimate our potential liability for these claims.
The specific facts we do not know include:
o the identity of our facilities at which the plaintiffs allegedly
worked as contractors,
o the names of the plaintiffs' employers, and
o the date on which the exposure allegedly occurred.
In 1997, six of these cases were settled before trial for amounts that were
immaterial. Four more trials are currently scheduled -- two in 1998 and two in
1999.
The second type are claims by one manufacturer -- Pittsburgh Corning
Corp. -- against us and approximately eight others, as third party defendants.
These claims relate to approximately 1,500 individual plaintiffs. We do not know
the specific facts necessary to estimate our potential liability for these
claims. The specific facts we do not know include:
o the identity of our facilities containing asbestos manufactured by
the manufacturer,
o the relationship (if any) of each of the individual plaintiffs to us,
o the settlement amounts for any individual plaintiffs who are shown
to have had a relationship to us, and
o the dates on which/places at which the exposure allegedly occurred.
Until the relevant facts for both type claims are determined, we are unable
to estimate what our liability, if any, might be. Although insurance and hold
harmless agreements from contractors who employed the plaintiffs may cover a
portion of any awards in the actions, our potential liability could be material.
See ITEM 1. BUSINESS -- ELECTRIC RATE MATTERS, NUCLEAR OPERATIONS,
ENVIRONMENTAL MATTERS, and NOTE 12 TO CONSOLIDATED FINANCIAL STATEMENTS for
other information about our legal or regulatory proceedings.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF
SECURITY HOLDERS
Reference is made to the information set forth under Item 4. Submission of
Matters to a Vote of Security Holders on page 35 of our Quarterly Report on Form
10-Q for the quarter ended September 30, 1997.
21
ITEM 10. EXECUTIVE OFFICERS OF THE REGISTRANT
Executive Officers of BGE at the date of this report are:
OTHER OFFICES OR POSITIONS
NAME AGE PRESENT OFFICE HELD DURING PAST FIVE YEARS
- ------------------------ --- --------------------------------- -------------------------------------
Christian H. Poindexter 59 Chairman of the Board and Chairman of the Board and Chief
President (A) Executive Officer
(Since March 1, 1998) Vice Chairman of the Board
Edward A. Crooke 59 Vice Chairman of the Board and President, Chief Operating Officer,
Chairman of the Board - and Chairman of the Board - Subsidiaries
Subsidiaries (B) President, Utility Operations
(Since March 1, 1998)
Bruce M. Ambler 58 President and Chief Executive
Officer
Constellation Holdings, Inc.
(Since August 1, 1989)
Charles W. Shivery 52 President Vice President
Constellation Energy Solutions, Finance and Accounting,
Inc. and President Chief Financial Officer and
and Chief Executive Secretary
Officer Constellation Power Vice President and Treasurer,
Source, Inc. Corporate Finance Group
(Since February 25, 1997)
Robert E. Denton 55 Executive Vice President Senior Vice President, Generation
Generation Vice President, Nuclear Energy
(Since March 1, 1998) Plant General Manager, Calvert
Cliffs Nuclear Power Plant
Frank O. Heintz 53 Executive Vice President Vice President, Gas
Utility Operations and Vice Executive Director, LDC Caucus --
President Gas American Gas Association
(Since March 1, 1998) Chairman, Maryland Public Service
Commission
Thomas F. Brady 48 Vice President Vice President, Customer Service
Customer Service and and Accounting
Distribution Vice President, Accounting and
(Since July 1, 1993) Economics
David A. Brune 57 Vice President General Counsel
Finance and Accounting,
Chief Financial Officer and
Secretary
(Since February 25, 1997)
Charles H. Cruse 53 Vice President Plant General Manager, Calvert
Nuclear Energy Cliffs Nuclear Power Plant
(Since January 1, 1996) Manager, Nuclear Engineering
Carserlo Doyle 55 Vice President Manager, Telecommunications
Electric Interconnection Principal Engineer -- Electric
and Transmission Interconnection
(Since January 1, 1994)
Sharon S. Hostetter 53 Vice President Manager, Marketing
Marketing and Sales Division Manager, Resource
(Since November 1, 1995) Application and Customer
Development Group, Rochester
Gas and Electric Corporation
Ronald W. Lowman 53 Vice President Manager, Fossil Engineering
Fossil Energy Manager, Fossil Engineering
(Since January 1, 1993) Services
Gregory C. Martin 49 Vice President Manager, Customer Service
General Services Manager, Customer Accounts
(Since November 1, 1997)
22
OTHER OFFICES OR POSITIONS
NAME AGE PRESENT OFFICE HELD DURING PAST FIVE YEARS
- ------------------------ --- --------------------------------- --------------------------------------
Linda D. Miller 47 Vice President Manager, Employee Services
Management Services
(Since November 1, 1997)
Stephen F. Wood 45 President Vice President, Marketing and Sales
Constellation Energy Projects Manager, Major Customer Projects
& Services, Inc. Manager, System Engineering
(Since November 1, 1995) and Construction
Vice President Manager, Distribution Engineering
(Since February 16, 1996)
- ---------------
(A) Chief Executive Officer, Director, and member of the Executive Committee.
(B) Director and member of the Executive Committee.
Officers of BGE are elected by, and hold office at the will of, the Board of
Directors and do not serve a "term of office" as such. There is no
arrangement or understanding between any director or officer and any other
person pursuant to which the director or officer was selected.
23
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
STOCK TRADING
Our common stock is traded under the ticker symbol BGE. It is listed on the
New York, Chicago, and Pacific stock exchanges. It has unlisted trading
privileges on the Boston, Cincinnati, and Philadelphia exchanges.
As of February 28, 1998, there were 72,972 common shareholders of record.
DIVIDEND POLICY
We pay dividends on our common stock when our Board of Directors declares
them. There is no limitation on our paying common stock dividends, other than we
must first pay all dividends (and any redemption payments) due on our preference
stock.
Dividends have been paid on the common stock continuously since 1910.
Future dividends depend upon future earnings, our financial condition and other
factors. Quarterly dividends were declared on the common stock during 1997 and
1996 in the amounts set forth below.
COMMON STOCK DIVIDENDS AND PRICE RANGES
1997 1996
----------------------------------------- ------------------------------------
PRICE* PRICE*
DIVIDEND ---------------------------- DIVIDEND --------------------------
DECLARED HIGH LOW DECLARED HIGH LOW
-------- ------------ ----------- -------- ---------- -----------
First Quarter................ $ .40 $28 $26 1/4 $ .39 $29 1/2 $26 1/8
Second Quarter............... .41 27 24 3/4 .40 28 5/8 25 1/2
Third Quarter................ .41 28 1/16 26 .40 28 5/8 25
Fourth Quarter............... .41 34 5/16 25 13/16 .40 28 3/4 25 3/4
----- -----
Total...................... $1.63 $1.59
===== =====
- ---------------
*Based on New York Stock Exchange Composite Transactions as reported in THE WALL
STREET JOURNAL.
24
Item 6. Selected Financial Data
Compound
1997 1996 1995 1994 1993 Growth
- -----------------------------------------------------------------------------------------------------------------------------------
(DOLLAR AMOUNTS IN MILLIONS, EXCEPT PER SHARE AMOUNTS) 5-Year 10-Year
SUMMARY OF OPERATIONS
Total Revenues $3,307.6 $3,153.2 $2,934.8 $2,783.0 $2,741.4 5.26% 5.47%
Expenses Other Than Interest and Income Taxes 2,584.0 2,483.7 2,239.1 2,147.7 2,125.0 5.00 6.22
---------------------------------------------------------------
Income From Operations 723.6 669.5 695.7 635.3 616.4 6.21 3.21
Other Income (Expense) (52.8) 6.1 8.8 32.3 20.3 -- --
---------------------------------------------------------------
Income Before Interest and Income Taxes 670.8 675.6 704.5 667.6 636.7 3.77 2.07
Net Interest Expense 230.0 198.5 197.0 190.1 188.8 3.93 7.10
---------------------------------------------------------------
Income Before Income Taxes 440.8 477.1 507.5 477.5 447.9 3.69 0.24
Income Taxes 158.0 166.3 169.5 153.9 138.1 8.87 1.94
---------------------------------------------------------------
Net Income 282.8 310.8 338.0 323.6 309.8 1.36 (0.59)
Preferred and Preference Stock Dividends 28.7 38.5 40.6 39.9 41.8 (7.42) 0.84
---------------------------------------------------------------
Earnings Applicable to Common Stock $ 254.1 $ 272.3 $ 297.4 $ 283.7 $ 268.0 2.73 (0.74)
- ---------------------------------------------------===============================================================
Earnings Per Share of Common Stock $1.72 $1.85 $2.02 $1.93 $1.85 1.08 (2.91)
Dividends Declared Per Share of Common Stock $1.63 $1.59 $1.55 $1.51 $1.47 2.65 2.69
Ratio of Earnings to Fixed Charges 2.78 3.10 3.21 3.14 3.00 0.96 (3.97)
Ratio of Earnings to Fixed Charges and Preferred
and Preference Stock Dividends Combined 2.35 2.44 2.52 2.47 2.34 2.47 (3.22)
FINANCIAL STATISTICS AT YEAR END
Total Assets $8,773.4 $8,544.3 $8,277.6 $7,995.9 $7,829.6 4.01 6.26
- ---------------------------------------------------===============================================================
Capitalization
Long-term debt $2,988.9 $2,758.8 $2,598.2 $2,584.9 $2,823.1 4.69 5.76
Preferred stock