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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 AND EXCHANGE ACT OF 1934
For the fiscal year ended 1-1910
December 31, 1996 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
------------------- ---------------------
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 (Section 229.405 of this chapter) 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. [X]
Aggregate market value of Common Stock, without par value, held by
non-affiliates as of February 28, 1997 was approximately $4,045,549,228 based
upon New York Stock Exchange composite transaction closing price.
COMMON STOCK, WITHOUT PAR VALUE -- 147,667,114 SHARES OUTSTANDING ON
FEBRUARY 28, 1997.
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........................................................................ 6
Electric Load Management, Energy, and Capacity Purchases.................................. 7
Fuel for Electric Generation.............................................................. 8
Electric Operating Statistics............................................................. 10
Gas Business
Gas Operating Statistics.................................................................. 11
Gas Regulatory Matters and Competition.................................................... 12
Gas Operations............................................................................ 12
Gas Rate Matters.......................................................................... 13
Franchises.................................................................................. 13
Diversified Businesses...................................................................... 13
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
PART II
Item 5 -- Market for Registrant's Common Equity and Related Stockholder Matters....................... 22
Item 6 -- Selected Financial Data..................................................................... 23
Item 7 -- Management's Discussion and Analysis of Financial Condition and Results of
Operations................................................................................. 24
Item 8 -- Financial Statements and Supplementary Data................................................. 34
Item 9 -- Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure................................................................................. 58
PART III
Item 10 -- Directors and Executive Officers of the Registrant.......................................... 58
Item 11 -- Executive Compensation...................................................................... 62
Item 12 -- Security Ownership of Certain Beneficial Owners and Management.............................. 69
Item 13 -- Certain Relationships and Related Transactions.............................................. 69
PART IV
Item 14 -- Exhibits, Financial Statement Schedules and Reports on Form 8-K............................. 70
Signatures................................................................................................. 74
PART I
ITEM 1. BUSINESS
OVERVIEW OF CONSOLIDATED BUSINESS
Baltimore Gas and Electric Company and Subsidiaries together are called the
Company in this Report. The Company conducts utility operations through
Baltimore Gas and Electric Company, called BGE in this Report. The Company is
engaged in a number of diversified businesses through subsidiaries.
BGE was incorporated under the laws of the State of Maryland on June 20,
1906. BGE is qualified to do business in the District of Columbia where its
federal affairs office is located. BGE is qualified to do business in the
Commonwealth of Pennsylvania where it is participating in the ownership and
operation of two electric generating plants as described under ITEM 2.
PROPERTIES. BGE also owns two-thirds of the outstanding capital stock, including
one-half of the voting securities, of Safe Harbor Water Power Corporation, a
hydroelectric producer on the Susquehanna River at Safe Harbor, Pennsylvania.
(SEE ITEM 2. PROPERTIES -- ELECTRIC.)
OVERVIEW OF UTILITY BUSINESS
Our utility business consists primarily of generating, purchasing, and
selling electricity and purchasing, transporting, and selling natural gas. The
focus of these activities is serving customers in BGE's service territory.
BGE furnishes electric and gas retail services in the City of Baltimore and
in all or part of ten counties in Central Maryland. The electric service
territory includes an area of approximately 2,300 square miles with an estimated
population of 2,650,000. The gas service territory includes an area of more than
600 square miles with an estimated population of 2,000,000. There are no
municipal or cooperative bulk power markets within BGE's service territory.
As discussed throughout this report, the two units at BGE's Calvert Cliffs
Nuclear Power Plant are its principal generating facilities and have the lowest
fuel cost in BGE's system. An extended shutdown of either of these Units could
have a substantial adverse effect on the Company's business and financial
condition. (See NUCLEAR OPERATIONS and NOTE 12 TO CONSOLIDATED FINANCIAL
STATEMENTS for information regarding prior outages at the Plant.) For further
information about utility operations see five other sections in this report --
ELECTRIC BUSINESS, ELECTRIC OPERATING STATISTICS, GAS OPERATING STATISTICS, GAS
BUSINESS, and FRANCHISES.
Competition and the Pending Merger
The utility industry is facing potentially substantial regulatory change
designed to foster competition in the provision of gas and electric services.
The restructuring of the industry was a key consideration for BGE and Potomac
Electric Power Company (PEPCO) agreeing to merge (the Merger). PEPCO is a
neighboring electric utility serving Washington, D.C. and major portions of
Montgomery and Prince George's Counties in Maryland. It is currently anticipated
that the Merger will be completed during the first six months of 1997. The
reasons for the Merger and other information about the Merger are discussed in
more detail under ELECTRIC REGULATORY MATTERS AND COMPETITION and in the
Registration Statement on Form S-4 (Registration No. 33-64799) which is included
as an exhibit to this report by incorporation by reference.
In response to the competitive forces and regulatory changes in the utility
industry, BGE (and after the Merger the new company to be named Constellation
EnergyTM Corporation) from time to time will consider various strategies
designed to enhance its competitive position and to increase its ability to
adapt to and anticipate regulatory changes in its utility business. These
strategies may include internal restructurings involving the complete or partial
separation of its generation, transmission and distribution businesses, other
internal restructurings, mergers or acquisitions of utility or non-utility
businesses, additions to or dispositions of portions of its franchised service
territories, and spin-off or distribution of one or more businesses. BGE and its
subsidiaries may from time to time be engaged in preliminary discussions, either
internally or with third parties, about one or more of these potential
strategies. It is not possible to predict the ultimate effect competition will
have on BGE's earnings in future years. These matters are discussed under
ELECTRIC REGULATORY MATTERS AND COMPETITION and GAS REGULATORY MATTERS AND
COMPETITION.
1
OVERVIEW OF DIVERSIFIED BUSINESSES
The Company is engaged in diversified businesses through three groups of
subsidiaries:
BGE Corp. and its subsidiaries -- these businesses include energy marketing
activities, specifically power marketing, natural gas brokering, energy
services, and district heating and cooling projects;
Constellation(TM) Holdings and its subsidiaries (called the "Constellation
Companies" in this report) -- these businesses include power generation outside
BGE's service territory, investment activities, real estate, and senior-living
facilities; and
BGE Home Products & Services, Inc. and its subsidiary -- these businesses
include appliance sales and service, heating and air conditioning sales and
service, and home improvement.
Our diversified businesses are described in more detail under the heading
DIVERSIFIED BUSINESSES.
OPERATING REVENUES AND INCOME
The percentages of Operating Revenues and Operating Income attributable to
electric, gas, and diversified operations are set forth below:
OPERATING REVENUES OPERATING INCOME*
------------------ -----------------
ELECTRIC GAS DIVERSIFIED ELECTRIC GAS DIVERSIFIED
-------- --- ----------- -------- --- -----------
1996.......................................... 70% 16 % 14% 75% 10 % 15%
1995.......................................... 76 14 10 83 7 10
1994.......................................... 76 15 9 85 4 11
1993.......................................... 77 16 7 87 6 7
1992.......................................... 77 16 7 82 8 10
*Net of income taxes.
BGE currently derives approximately 22% of electric revenues and 40% of gas
revenues from customers located in the City of Baltimore and 78% and 60%,
respectively, from outside the City of Baltimore. No single customer's electric
revenues exceed 4% of total electric revenues and no single customer's gas
revenues exceed 4% of total gas revenues. The disparity between the percentage
of gas operating revenues in relation to the percentage of gas operating income
as compared to the same percentages for electric operations is due to BGE's
level of investment and its fuel costs in each of these segments. BGE's
operating revenue amounts represent recovery of all fuel and operating expenses
plus a return on its investment in the business. BGE's net investment for
ratemaking purposes in the electric business is $4.8 billion while the
comparable investment in its gas business is approximately $605 million. Thus,
operating revenues include a much greater return component for electric
operations than gas operations. Also, as can be seen by referring to ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA, CONSOLIDATED STATEMENTS OF INCOME,
gas purchased for resale as a percentage of gas revenues (55%) is greater than
electric fuel and purchased energy as a percentage of electric revenues (25%).
It should be noted that both purchased gas costs (prior to October 1996) and
electric fuel costs are passed through to the customer with no mark-up for
profit. Effective October 1996, the Maryland Commission approved a Market Based
Rates incentive mechanism for pricing gas. This mechanism is discussed in GAS
REGULATORY MATTERS AND COMPETITION. The combined effects of these factors yield
the observed relationship between operating revenues and income for electric
operations.
2
CONSOLIDATED CAPITAL REQUIREMENTS
The Company's actual capital requirements for 1994 through 1996, along with
estimated amounts for 1997 through 1999, are set forth below.
1994 1995 1996 1997 1998 1999
---- ---- ---- ---- ---- ----
(IN MILLIONS)
Utility Business Capital Requirements
Construction expenditures (excluding AFC)
Electric.................................................... $ 345 $ 223 $ 219 $ 230 $ 216 $ 215
Gas......................................................... 68 70 84 72 70 73
Common...................................................... 42 51 46 33 39 37
----- ----- ----- ----- ----- -------
Total construction expenditures........................... 455 344 349 335 325 325
AFC (a)........................................................ 34 22 10 7 7 7
Nuclear fuel (uranium purchases and processing charges)........ 42 46 47 49 50 50
Deferred energy conservation expenditures (b).................. 41 46 31 24 19 18
Deferred nuclear expenditures (b).............................. 8 -- -- -- -- --
Retirement of long-term debt and redemption of preference
stock....................................................... 203 279 184 173 117 270
----- ----- ----- ----- ----- -------
Total utility business capital requirements............... 783 737 621 588 518 670
----- ----- ----- ----- ----- -------
Diversified Business Capital Requirements........................ 88 173 170 322 345 391
----- ----- ----- ----- ----- -------
Total capital requirements................................ $ 871 $ 910 $ 791 $ 910 $ 863 $ 1,061
===== ===== ===== ===== ===== =======
(a) Allowance for Funds Used During Construction (AFC) is accrued for all
construction projects with a construction period of more than one month.
(See NOTE 1 TO CONSOLIDATED FINANCIAL STATEMENTS for a discussion of AFC.)
(b) See NOTE 5 TO CONSOLIDATED FINANCIAL STATEMENTS for a discussion of deferred
nuclear expenditures and deferred energy conservation expenditures.
Utility business capital requirements do not reflect costs to complete the
pending Merger with PEPCO. These costs, currently estimated to be $150 million,
are discussed in NOTE 12 TO CONSOLIDATED FINANCIAL STATEMENTS.
BGE's actual capital requirements may vary from the estimates set forth
above because of a number of factors such as inflation, economic conditions,
regulation, legislation, load growth, environmental protection standards, and
the cost and availability of capital. Additionally, actual capital requirements
may vary from the estimates set forth above because adjustments which may result
from the pending Merger with PEPCO have not been reflected in those estimates.
The capital requirements for diversified businesses may vary from the estimates
set forth above due to a number of factors including market and economic
conditions. The capital requirements for these businesses are discussed in
detail in two sections of this report: DIVERSIFIED BUSINESS CAPITAL REQUIREMENTS
and ITEM 7. MD&A -- CAPITAL REQUIREMENTS OF OUR DIVERSIFIED BUSINESSES.
BGE's estimated construction, nuclear fuel, and deferred energy
conservation expenditures are expected to amount to approximately $1.6 billion,
$245 million, and $100 million, respectively, for the five-year period
1997-2001. Electric construction expenditures reflect improvements in BGE's
existing generating plants and its transmission and distribution facilities.
Future electric construction expenditures do not include additional generating
units. During the period January 1, 1992 through December 31, 1996, BGE expended
$2.0 billion for gross additions to utility plant or approximately 25% of its
total utility plant (exclusive of nuclear fuel) at December 31, 1996. During the
same period, a total of $423 million of utility plant was retired. Nuclear fuel
expenditures include uranium purchases and processing charges.
BGE presently estimates that approximately $1.1 billion will be required
for retirements and redemptions of long-term debt (including sinking fund
payments) and BGE preference stock during the five-year period 1997-2001. This
estimate does not consider the proposed Merger with PEPCO.
For further information with respect to capital requirements and for a
discussion of internal generation of cash, see ITEM 7. MD&A -- LIQUIDITY AND
CAPITAL RESOURCES.
3
ELECTRIC BUSINESS
BGE's electric utility business in Maryland provides the major portion of
revenues and earnings to the consolidated company. This business is discussed
below in six sections titled ELECTRIC REGULATORY MATTERS AND COMPETITION;
ELECTRIC RATE MATTERS; NUCLEAR OPERATIONS; ELECTRIC LOAD MANAGEMENT, ENERGY, AND
CAPACITY PURCHASES; FUEL FOR ELECTRIC GENERATION; AND ELECTRIC OPERATING
STATISTICS. BGE recently announced its intention to enter the electric power
marketing business through a subsidiary, which is discussed under the heading
DIVERSIFIED BUSINESSES.
ELECTRIC REGULATORY MATTERS AND COMPETITION
In recent years BGE focused strategic attention to developments in federal
regulatory policy which are designed to increase competition in the wholesale
market for bulk power and expand competition in the market for generation. In
1993, the BGE Board of Directors formed the Long Range Strategy Committee to
provide an oversight role in the development of BGE's long range strategic goals
and to consider strategic initiatives which Management wished to present to the
BGE Board.
Many of these developments were prompted by the Energy Policy Act of 1992
(the 1992 Act), which granted the Federal Energy Regulatory Commission (FERC)
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. The 1992 Act also created a new class of power producers, 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
developments resulted from policies at the Securities and Exchange Commission
(SEC), 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. Moreover,
state regulatory bodies in certain states had initiated proceedings to review
the basic structure of the industry.
Against this background, BGE and PEPCO agreed to merge in September 1995.
Each company independently reached the conclusion that key factors contributing
to success in a more competitive environment will be maintaining low-cost
production and achieving a size that will enable it to continue to provide high
quality customer service, enhancing its competitive position and attaining a
greater level of financial strength.
BGE, PEPCO, and Constellation Energy Corporation (formerly named R.H.
Acquisition Corp.) entered into the Agreement and Plan of Merger dated as of
September 22, 1995 (the Merger Agreement). The Merger Agreement provides that
upon the receipt of all necessary approvals (including shareholder approval --
obtained in 1996 -- and a number of regulatory approvals -- several of which are
still pending) BGE and PEPCO will be merged into Constellation Energy
Corporation (the Merger). Constellation Energy Corporation is a shell
corporation formed for the sole purpose of accomplishing the Merger. It is
currently anticipated that all such approvals will be obtained during the first
six months of 1997. The status of these approvals through the date of this
report is found in NOTE 12 TO CONSOLIDATED FINANCIAL STATEMENTS.
Preliminary estimates by the managements of PEPCO and BGE indicate that the
synergies resulting from the combination of their utility operations could
generate net cost savings of up to $1.3 billion over a period of 10 years
following the Merger. These estimates indicate that about two-thirds of the
savings will come from reduced labor costs, with the remaining savings split
between nonfuel purchasing and corporate and administrative programs. These
savings are expected to be allocated among shareholders and customers. This
allocation will depend upon the results of regulatory proceedings in the various
jurisdictions in which BGE and PEPCO operate their utility businesses. The
reasons for the Merger, the terms and conditions contained in the Merger
Agreement, and other matters concerning the Merger, PEPCO, and Constellation
Energy Corporation are discussed in more detail in the Registration Statement on
Form S-4 (Registration No. 33-64799) which is included as an exhibit to this
Report on Form 10-K by incorporation by reference. The analyses employed in
order to develop estimates of potential savings as a result of the Merger were
necessarily based upon various assumptions which involve judgments with respect
to, among other things, future national and regional economic and competitive
conditions, inflation rates, regulatory treatment, weather conditions, financial
market conditions, interest rates, future business decisions and other
uncertainties, all of which are difficult to predict and many of which are
beyond the control of BGE and PEPCO. Accordingly, while BGE believes that such
assumptions are reasonable for purposes of the development of estimates of
4
potential savings, there can be no assurance that such assumptions will
approximate actual experience or that all such savings will be realized.
State regulators around the United States are also redefining the
regulatory scheme for the electric utility industry. The Maryland Public Service
Commission (Maryland Commission), after hearings in 1995 to consider electric
utility restructuring, the impact of competition, regulatory reform and possible
scenarios ranging from limited to full competition, had concluded that wholesale
competition remains in the best interests of the state's energy consumers in
view of the availability of efficient, reliable, comparatively low-cost power.
During 1996 the pace of other states' actions to allow retail competition
accelerated and two neighboring states, Pennsylvania and New Jersey, initiated
retail competition schemes. In light of these activities, in 1996 the Maryland
Commission started a new inquiry on retail competition and requested during 1997
both:
(Bullet) recommendations from its staff, and
(Bullet) filings from electric utilities with customers in Maryland to show
how unbundled electric rates might be structured.
The first analysis of retail competition by the District of Columbia Public
Service Commission is currently in progress. At the date of this report, we do
not expect any final action from the Maryland or District of Columbia
Commissions regarding retail competition during 1997.
It is not possible to predict the ultimate effect competition will have on
BGE's earnings in the future.
ELECTRIC RATE MATTERS
ENERGY CONSERVATION SURCHARGE
The Maryland Commission approved a base rate surcharge effective July 1,
1992 which provides for the recovery of deferred energy conservation
expenditures, a return thereon, lost revenues, and incentives for achievement of
predetermined goals for certain conservation programs subject to an earnings
test. Effective April 1996 this earnings test is performed on an annual basis.
All or a portion of the compensation for foregone sales due to conservation
programs and the incentives for achieving conservation goals must be refunded to
customers if BGE is earning in excess of its authorized rate of return, as
determined by the Maryland Commission. (See discussion in ITEM 7. MD&A --
RESULTS OF OPERATIONS.) The surcharge is reset on July 1 of each year.
ELECTRIC FUEL RATE PROCEEDINGS
By statute, electric fuel costs are recoverable if the Maryland Commission
finds that BGE demonstrates that, among other things, it has maintained the
productive capacity of its generating plants at a reasonable level. The Maryland
Commission and Maryland's highest appellate court have interpreted this as
permitting a subjective evaluation of each unplanned outage at BGE's generating
plants to determine whether or not BGE had implemented all reasonable and cost
effective maintenance and operating control procedures appropriate for
preventing the outage. The Maryland Commission has established a Generating Unit
Performance Program (GUPP) to measure annual utility compliance with maintaining
the productive capacity of generating plants at reasonable levels by
establishing a system-wide generating performance target and individual
performance targets for each base load generating unit. As a result, actual
generating performance, after adjustment for planned outages, is compared to the
system-wide target and, if met, should signify compliance with the requirements
of Maryland law. Failure to meet the system-wide target will result in review of
each unit's adjusted actual generating performance versus its performance target
in determining compliance with the law, and the basis for possibly imposing a
penalty on BGE. Failure to meet these targets requires BGE to demonstrate that
the outages causing the failure are not the result of mismanagement. Parties to
fuel rate hearings may still question the prudence of BGE's actions or inactions
with respect to any given generating plant outage, which could result in a
disallowance of replacement energy costs. BGE is involved in fuel rate
proceedings annually where issues concerning individual plant outages can be
raised. Recovery of a portion of replacement energy costs has been denied in
past proceedings and BGE cannot estimate the amount that could be denied in
future fuel rate proceedings, but such amounts could be material. (See NUCLEAR
OPERATIONS.)
5
BGE is required to submit to the Maryland Commission the actual generating
performance data for each calendar year 45 days after year end. The Maryland
Commission reviews BGE's performance for each calen-
dar year in the first fuel rate proceeding initiated following the submission of
the actual generating performance data for that year. 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
Discussed below are certain events relating to the operations of the
Calvert Cliffs Nuclear Power Plant (the Plant) during the period 1987 to the
present, including issues involving the possible disallowance of replacement
energy costs incurred during unplanned outages at the Plant. All outstanding
issues will be resolved in fuel rate proceedings before the Maryland Commission
which are conducted in accordance with the procedures outlined above under
ELECTRIC RATE MATTERS -- ELECTRIC FUEL RATE PROCEEDINGS.
OPERATIONS IN 1987
The Plant generated 10,069,576 megawatt hours (MWH) in 1987 which resulted
in a capacity factor of 70%. In October 1988, BGE filed a fuel rate application
for a change in its electric fuel rate under GUPP, which covered BGE's operating
performance in 1987. This was the first proceeding filed under this program and
BGE's filing demonstrated that it met the system-wide and individual plant
performance targets for 1987, including the performance target for the Plant.
BGE believed, therefore, it was entitled to recover all fuel costs incurred in
1987 without any disallowances. However, People's Counsel alleged that a number
of the outages at the Plant, including the 66-day outage to document compliance
with NRC mandated environmental qualification requirements, were due to
management imprudence and requested that the Maryland Commission disallow
recovery of the associated replacement energy costs which BGE estimated to be
approximately $33 million. On January 23, 1995, the Hearing Examiner issued his
decision in the 1987 fuel rate proceeding and found that the Company had met the
GUPP standard which establishes a presumption that BGE had operated the Plant at
a reasonably productive capacity level. However, the Order found that the
presumption of reasonableness could be overcome by a showing of mismanagement
and that such a showing was made with respect to the environmental
qualifications outage time. In mitigation for meeting the GUPP standard, the
Hearing Examiner disallowed replacement energy costs recovery for 15.5 days of
the 66-day outage time. The Hearing Examiner's Order was appealed to the
Maryland Commission by both BGE and People's Counsel. The Maryland Commission
upheld the Hearing Examiner's findings with respect to the environmental
qualification related outage time, but disagreed with certain methodologies
applied by the Hearing Examiner. The impact of the Maryland Commission's
decision on the Company's 1996 earnings was approximately $4.5 million. People's
Counsel has filed a motion for rehearing.
OPERATIONS IN 1988
The Plant generated 11,733,900 MWH in 1988 which resulted in a capacity
factor of 81%. BGE filed a fuel rate application under GUPP in May, 1989 in
which it demonstrated that it met the system-wide and individual plant
performance targets for 1988. People's Counsel alleged that BGE imprudently
managed several outages at the Plant and requested that the Maryland Commission
disallow recovery of $2 million of replacement energy costs. On November 14,
1991, a Hearing Examiner at the Maryland Commission issued a proposed Order,
which became final on December 17, 1991 and concluded that no disallowance was
warranted. The Hearing Examiner found that BGE maintained the productive
capacity of the Plant at a reasonable level, noting that it produced a near
record amount of power and exceeded the GUPP standard. Based on this record, the
Order concluded there was sufficient cause to excuse any avoidable failures to
maintain productive capacity at higher levels.
OPERATIONS IN 1989 TO 1991 -- EXTENDED OUTAGE
The Plant generated 2,719,197 MWH in 1989 and 1,251,416 MWH in 1990. In the
Spring of 1989, a leak was discovered around the Unit 2 pressurizer heater
sleeves during a refueling outage. BGE shut down Unit 1 as a precautionary
measure on May 6, 1989 to inspect for similar leaks and none were found at that
time. However, Unit 1 was out of service for the remainder of 1989 and 285 days
of 1990 to undergo maintenance and modification work to enhance the reliability
of various safety systems, to repair equipment, and to perform required periodic
surveillance tests. Unit 2 remained out of service until May 4, 1991 to
6
complete repair of the pressurizer, perform maintenance and modification work,
and complete the refueling. The replacement energy costs associated with these
extended outages for both Units at Calvert Cliffs, concluding with the return to
service of Unit 2, were estimated at $458 million. This estimate was based on a
computer simulation comparing the actual operating conditions during the
extended outages with operating conditions assuming the Plant ran at its
targeted capacity factor.
The extended outages experienced at the Plant were reviewed by the Maryland
Commission in the 1989-1991 fuel rate proceeding, and People's Counsel and
others challenged recovery of some part of the associated replacement energy
costs. Extended litigation followed about the amount of replacement energy costs
BGE should be permitted to recover.
In December 1996, BGE entered into a settlement agreement with People's
Counsel and the Maryland Commission Staff proposing a resolution to all fuel
rate issues during the 1989-1991 period. The Maryland Commission approved the
settlement agreement in early 1997. BGE agreed that ratepayers will not fund a
total of $118 million of electric replacement energy costs associated with the
extended outages. This represents $83 million in addition to the $35 million
reserve for possible disallowance of replacement energy costs recorded in 1990.
Therefore, in December 1996, BGE increased the provision for the disallowance of
such costs by $83 million. Additionally, in 1996, BGE wrote off $5.6 million of
accrued carrying charges related to the deferred fuel balances. The remainder of
the replacement energy costs associated with the extended outage had already
been recovered from customers through the fuel rate.
OPERATIONS SUBSEQUENT TO 1991
The Plant generated 10,663,950 MWH in 1992, which resulted in a capacity
factor of 74%. There were no contested performance issues based on 1992
performance and BGE's GUPP filings were approved as filed. The Plant generated
12,300,816 MWH in 1993, which resulted in a capacity factor of 85%. In 1994, the
Plant generated 11,225,977 MWH achieving a capacity factor of 77%. Review of the
GUPP filings in 1993 and 1994 have been completed. There were no significant
performance issues in either of these years and BGE's GUPP filings were approved
as filed. The plant generated 12,940,496 MWH in 1995, which resulted in a
capacity factor of 88%. The plant generated 12,069,937 MWH in 1996, which
resulted in a capacity factor of 82%. A review of 1995 and 1996 performance will
be initiated with BGE's next fuel rate application.
ELECTRIC LOAD MANAGEMENT, ENERGY, AND CAPACITY PURCHASES
BGE has implemented various active load management programs designed to be
used when system operating conditions require a reduction in load. These
programs include customer-owned generation and curtailable service for large
commercial and industrial customers, air conditioning control which is available
to residential and commercial customers, and residential water heater control.
The load reductions typically have been invoked on peak summer days; potential
reduction in the Summer 1997 peak load from active load management is
approximately 475 megawatts (MW). Cost recovery for these load management
programs is attainable through the inclusion in rate base of capital investments
and the appropriate expenses (including credits on customer bills) for recovery
in base rate proceedings.
The generating and transmission facilities of BGE are interconnected with
those of neighboring utility systems to form the Pennsylvania-New
Jersey-Maryland Interconnection (PJM). Under the PJM agreement, the
interconnected facilities are used for substantial energy interchange and
capacity transactions as well as emergency assistance. In addition, BGE enters
into short-term capacity transactions at various times to meet PJM obligations.
BGE has an agreement with Pennsylvania Power & Light Company (PP&L) to
purchase a mix of energy and capacity from June 1, 1990 through May 31, 2001.
This agreement, which has been accepted by the FERC, is designed to help
maintain adequate reserve margins through this decade and provide flexibility in
meeting capacity obligations. The PP&L agreement entitles BGE to 5.94% of the
energy 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 also
enables BGE to treat a portion of PP&L's capacity as BGE's capacity for purposes
of satisfying BGE's installed capacity requirements as a member of the PJM. BGE
is 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. BGE's firm capacity purchases at
7
December 31, 1996 represented 170 MW of rated capacity of Bethlehem Steel
Corporation's Sparrows Point complex, 57 MW of rated capacity of the Baltimore
Refuse Energy Systems Company, and the 130 MW of Susquehanna capacity from PP&L.
In 1994 PECO Energy won a competitive bidding program to supply 140 MW for
firm electric capacity and associated energy for 25 years beginning June 1,
1998. This contract has been accepted by both FERC and the Maryland Commission.
FUEL FOR ELECTRIC GENERATION
Information regarding BGE's electric generation by fuel type and the cost
of fuels in the five-year period 1992-1996 is set forth in the following tables:
AVERAGE COST OF FUEL CONSUMED
GENERATION BY FUEL TYPE ((CENTS) PER MILLION BTU)
------------------------------------ ----------------------------------------------
1996 1995 1994 1993 1992 1996 1995 1994 1993 1992
---- ---- ---- ---- ---- ---- ---- ---- ---- ----
Nuclear (a)................... 40% 43% 39% 43% 40% 47.29 47.22 52.06 53.01 45.54
Coal.......................... 58 57 56 55 54 143.80 148.64 148.64 151.85 154.76
Oil........................... 1 1 3 3 1 313.33 267.59 245.28 253.36 254.19
Hydro & Gas................... 4 3 3 3 3 -- -- -- -- --
--- --- --- --- ---
103 104 101 104 98
Interchange/
Purchases (b)............... (3) (4) (1) (4) 2
--- --- --- --- ---
100% 100% 100% 100% 100%
=== === === === ===
(a) Nuclear fuel costs provide for disposal costs associated with long-term
off-site spent fuel storage and shipping, currently set by law at one mill
per kilowatt-hour of nuclear generation (approximately 10 cents per million
Btu) and for contributions to a fund for decommissioning and decontaminating
the Department of Energy's uranium enrichment facility. (See FUEL FOR
ELECTRIC GENERATION -- NUCLEAR.)
(b) Net purchases from (sales to) others.
COAL: BGE obtains a large amount of its coal under supply contracts with
mining operators. The remainder of its coal requirements are obtained through
spot purchases. BGE believes that it will be able to renew such contracts as
they expire or enter into similar contractual arrangements with other coal
suppliers. BGE's Brandon Shores Units 1 and 2 have a total annual requirement of
approximately 3,500,000 tons of coal (combined) with a sulfur content of less
than approximately 0.8%. BGE's Crane Units 1 and 2 have a total annual
requirement of about 700,000 tons of coal (combined) with a low ash melting
temperature. BGE's Wagner Units 2 and 3 have a total annual requirement of
approximately 900,000 tons of coal (combined) with a sulfur content of no more
than 1%.
Coal deliveries to BGE's coal burning facilities are made by rail and
barge. The coal used by BGE is produced from mines located in central and
northern Appalachia.
BGE has 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. 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.
8
NUCLEAR: The supply of fuel for nuclear generating stations involves the
acquisition of uranium concentrates, its conversion to uranium hexafluoride,
enrichment of uranium hexafluoride, and the fabrication of nuclear fuel
assemblies. Information is set forth below with respect to fuel for Calvert
Cliffs Units 1 and 2:
Uranium Concentrates: BGE has, either in inventory or under contract, sufficient quantities of
uranium to meet at least 90% of its requirements through 2000 and
approximately 70% of its requirements between 2001 and 2004.
Conversion: BGE has contractual commitments providing for the conversion of uranium
concentrates into uranium hexafluoride which will meet approximately 90%
of its requirements through 2000 and approximately 65% between 2001 and
2004.
Enrichment: BGE has a contract with the U.S. Energy Corporation for the enrichment of
100% of BGE's enrichment requirements through 1998, declining to
approximately 50% by 2004.
Fuel Assembly Fabrication: BGE has contracted for the fabrication of fuel assemblies for reloads it
requires through 2000.
The nuclear fuel market is very competitive and BGE does not anticipate any
problem in meeting its requirements beyond the periods noted above. Expenditures
for nuclear fuel are discussed 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), spent fuel discharged from nuclear power plants, including
Calvert Cliffs, is required to be placed into a federal repository. Such
facilities do not currently exist, and, consequently, must be developed and
licensed. BGE cannot now predict when such facilities will be available,
although the 1982 Act obligates the federal government to accept spent fuel
starting in 1998. While BGE cannot now predict what the ultimate cost will be,
the 1982 Act assesses a one mill per kilowatt-hour fee on nuclear electricity
generated and sold. At anticipated operating levels, it is expected that this
fee will be approximately $13 million for Calvert Cliffs each year.
In December 1996, the United States Department of Energy (DOE) notified BGE
and other nuclear utilities that it is unable to meet the 1998 deadline for
accepting spent fuel. BGE is 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 are requesting that the court allow them to pay fees, that formerly
went directly to DOE, into escrow instead. Among other remedies, they seek to
force DOE to submit a program with milestones illustrating how DOE will meet the
deadline for accepting spent nuclear fuel and a monthly report to allow the
utilities to monitor DOE's progress.
Maryland law makes it unlawful to establish within the State a facility for
the permanent storage of high-level nuclear waste, unless otherwise expressly
required by federal law. BGE has received a license from the NRC to operate its
on-site independent spent fuel storage facility. BGE now has storage capacity at
Calvert Cliffs that will accommodate spent fuel from operations through the year
2006. In addition, BGE can expand its 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."
GAS: BGE has a firm natural gas transportation entitlement of 3,500
dekatherms a day to provide ignition and banking at certain power plants. Gas
for electric generation is purchased as needed in the spot market using
interruptible transportation arrangements. Certain gas fired units can use
residual fuel oil as an alternative.
9
ELECTRIC OPERATING STATISTICS
YEAR ENDED DECEMBER 31,
------------------------------------------------------------------
1996 1995 1994 1993 1992
---- ---- ---- ---- ----
Electric Output (In Thousands) -- MWH:
Generated................................ 30,107 30,548 28,413 28,907 25,626
Purchased (A)............................ 7,560 7,403 6,270 3,643 4,323
---------- ---------- ---------- ---------- ----------
Subtotal............................ 37,667 37,951 34,683 32,550 29,949
Less Interchange and Other Sales......... 7,580 8,149 5,684 4,149 3,180
---------- ---------- ---------- ---------- ----------
Total Output........................ 30,087 29,802 28,999 28,401 26,769
========== ========== ========== ========== ==========
Power Generated and Purchased at
Times of Peak Load (MW) (one hour):
Generated by Company..................... 4,789 5,162 3,384 5,245 3,679
Net Purchased (A)........................ 1,166 785 2,654 631 1,879
---------- ---------- ---------- ---------- ----------
Peak Load (B)............................ 5,955 5,947 6,038 5,876 5,558
========== ========== ========== ========== ==========
Annual System Load Factor (%).............. 57.5 57.2 54.7 55.2 54.8
Revenues (In Thousands)
Residential.............................. $ 958,736 $ 955,239 $ 931,711 $ 931,643 $ 839,954
Commercial............................... 861,343 879,438 852,989 869,829 842,694
Industrial............................... 207,579 208,441 205,611 199,042 201,950
---------- ---------- ---------- ---------- ----------
System Sales............................. 2,027,658 2,043,118 1,990,311 2,000,514 1,884,598
Interchange and Other Sales.............. 155,877 166,964 118,027 91,543 64,323
Other.................................... 25,492 21,029 19,083 20,090 16,611
---------- ---------- ---------- ---------- ----------
Total............................... $2,209,027 $2,231,111 $2,127,421 $2,112,147 $1,965,532
========== ========== ========== ========== ==========
Sales (In Thousands) -- MWH:
Residential.............................. 11,243 10,966 10,670 10,614 9,735
Commercial............................... 12,591 12,635 12,351 12,395 11,909
Industrial............................... 4,596 4,591 4,433 3,763 3,663
---------- ---------- ---------- ---------- ----------
System Sales............................. 28,430 28,192 27,454 26,772 25,307
Interchange and Other Sales.............. 7,580 8,149 5,684 4,149 3,180
---------- ---------- ---------- ---------- ----------
Total............................... 36,010 36,341 33,138 30,921 28,487
========== ========== ========== ========== ==========
Customers
Residential.............................. 995,197 988,179 978,591 968,212 956,570
Commercial............................... 104,501 103,399 101,957 100,820 99,673
Industrial............................... 4,261 4,161 3,967 3,800 3,761
---------- ---------- ---------- ---------- ----------
Total............................... 1,103,959 1,095,739 1,084,515 1,072,832 1,060,004
========== ========== ========== ========== ==========
Average Cost of Fuel Consumed ((cents) per
million Btu)............................. 108.05 104.78 112.44 112.77 110.20
========== ========== ========== ========== ==========
BGE 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 the Company owns two-thirds of the capital stock.
(B) See ELECTRIC LOAD MANAGEMENT, ENERGY, AND CAPACITY PURCHASES for a
discussion of active load management programs which may be activated at
times of peak load.
10
GAS OPERATING STATISTICS
YEAR ENDED DECEMBER 31,
--------------------------------------------------------
1996 1995 1994 1993 1992
---- ---- ---- ---- ----
Gas Output (In Thousands) -- DTH:
Purchased.......................................... 70,260 70,391 68,541 71,221 70,211
LNG Withdrawn from Storage......................... 904 815 698 725 742
Produced........................................... 784 528 828 259 92
-------- -------- -------- -------- --------
Total Output.................................. 71,948 71,734 70,067 72,205 71,045
Delivery service gas (A)........................... 45,964 43,854 41,897 38,521 41,048
Off-system sales (B)............................... 10,204 -- -- -- --
-------- -------- -------- -------- --------
Total......................................... 128,116 115,588 111,964 110,726 112,093
======== ======== ======== ======== ========
Peak Day Sendout (DTH)............................... 708,966 706,287 761,900 657,700 609,200
======== ======== ======== ======== ========
Capability on Peak Day (DTH)......................... 870,000 847,000 847,000 847,000 847,000
Revenues (In Thousands)
Residential........................................ $320,105 $248,283 $262,736 $265,601 $242,737
Commercial
Excluding Delivery Service...................... 125,052 109,859 121,005 121,832 112,147
Delivery Service................................ 7,217 3,696 2,285 3,287 3,591
Industrial
Excluding Delivery Service...................... 17,064 16,730 20,140 22,250 21,123
Delivery Service................................ 14,598 16,332 9,635 12,920 14,290
-------- -------- -------- -------- --------
System sales....................................... 484,036 394,900 415,801 425,890 393,888
Off-system sales................................... 26,600 -- -- -- --
Other.............................................. 6,656 5,604 5,448 7,273 6,511
-------- -------- -------- -------- --------
Total......................................... $517,292 $400,504 $421,249 $433,163 $400,399
======== ======== ======== ======== ========
Sales (In Thousands) -- DTH:
Residential........................................ 43,784 40,211 40,279 40,029 39,042
Commercial
Excluding Delivery Service...................... 22,698 23,612 23,712 23,830 23,478
Delivery Service................................ 8,755 6,982 6,490 7,428 7,102
Industrial
Excluding Delivery Service...................... 2,887 4,102 4,410 5,298 5,314
Delivery Service................................ 36,201 35,925 33,837 31,390 33,638
-------- -------- -------- -------- --------
System sales....................................... 114,325 110,832 108,728 107,975 108,574
Off-system sales................................... 10,204 -- -- -- --
-------- -------- -------- -------- --------
Total......................................... 124,529 110,832 108,728 107,975 108,574
======== ======== ======== ======== ========
Customers
Residential........................................ 516,523 506,739 498,152 491,165 486,863
Commercial......................................... 38,861 38,422 37,891 37,518 37,000
Industrial......................................... 1,350 1,334 1,354 1,353 1,412
-------- -------- -------- -------- --------
Total......................................... 556,734 546,495 537,397 530,036 525,275
======== ======== ======== ======== ========
BGE achieved an all-time peak day sendout of 761,900 DTH on January 19,
1994.
(A) Represents gas purchased by customers directly from suppliers for which BGE
receives a fee for transportation through its system ("delivery service").
(See ITEM 7. MD&A -- RESULTS OF OPERATIONS.)
(B) Represents gas sold to suppliers and end users of natural gas outside BGE's
service territory (beginning first quarter 1996). (See ITEM 7.
MD&A -- RESULTS OF OPERATIONS).
Certain prior year amounts have been reclassified to conform with the
current year's presentation.
11
GAS BUSINESS
BGE's gas utility business in Maryland is discussed on the previous page
under GAS OPERATING STATISTICS and below in three sections titled REGULATORY
MATTERS AND COMPETITION; GAS OPERATIONS; AND GAS RATE MATTERS. BGE also has a
subsidiary that is active in the gas marketing business, which is discussed
under the heading DIVERSIFIED BUSINESSES.
GAS REGULATORY MATTERS AND COMPETITION
Regulatory changes in the natural gas business are well under way. In 1992,
the Federal Energy Regulatory Commission (FERC) issued Order 636, which
unbundled gas-service elements. This gave gas users the ability to choose
various gas purchasing, transportation, brokering, and storage options. Prior to
Order 636, BGE purchased gas, transportation and storage services primarily from
pipeline companies. Now, BGE and other local distribution companies buy gas
directly from various suppliers and arrange separately for transportation and
storage. BGE's large gas customers are arranging for their own gas supplies and
are contracting with BGE for transportation. The Maryland Commission continues
to encourage BGE and other utilities to offer options for unbundling the gas
services offered by local distribution companies and allowing smaller customers
to arrange for their own gas supplies.
As part of its response to the increase in competition in the natural gas
business, BGE has obtained approval from the Maryland Commission to utilize
profit sharing for earnings from off-system gas sales and capacity release
revenues, and to implement a Market Based Rates (MBR) incentive gas purchasing
mechanism. Off-system gas sales are direct sales to suppliers and end users of
natural gas outside BGE's service territory. BGE makes these sales as part of a
program to balance its supply of, and cost of, natural gas. Under the MBR
mechanism, differences between a market index and BGE's actual cost of gas are
shared equally between BGE's customers and shareholders.
GAS OPERATIONS
BGE distributes natural gas purchased directly from several producers and
marketers. Transportation to BGE's city gate for these purchases is provided by
Columbia Gas Transmission Corporation (Columbia), CNG Transmission Corporation
(CNG), and Transcontinental Gas Pipe Line Corporation under various
transportation agreements. BGE has upstream transportation capacity under
contract on Tennessee Gas Pipeline Company, Texas Eastern Transmission
Corporation, Columbia Gulf Transmission Company and ANR Pipeline Company (ANR).
BGE has storage service agreements with Columbia, CNG and ANR. The
transportation and storage agreements are on file with the Federal Energy
Regulatory Commission (FERC).
BGE's current pipeline firm transportation entitlements to serve its firm
loads are 291,731 dekatherms (DTH) per day during the winter period and 266,731
DTH per day during the summer period. BGE uses the firm transportation capacity
to move gas from the Gulf of Mexico, Louisiana, south central regions of Texas
and Canada to BGE's 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. Additional short-term contracts or exchange agreements with other gas
companies can be arranged in the event of short-term emergencies.
BGE has two market area storage contracts to manage weather sensitive gas
demand during the winter period. Current maximum storage entitlements are
181,866 DTH per day. To supplement BGE's gas supply at times of heavy winter
demands and to be available in temporary emergencies affecting gas supply, BGE
has propane air and liquefied natural gas facilities. The liquefied natural gas
facility consists of a plant 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. The propane air facility consists of a plant 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. BGE has under contract
sufficient volumes of propane for the operation of the propane air facility and
is capable of liquefying sufficient volumes of natural gas during the summer
months for operation of its liquefied natural gas facility during winter
periods.
BGE offers gas for sale to its residential, commercial and industrial
customers on a firm and interruptible basis.
BGE also provides its commercial and industrial customers with a
transportation service across its distribution system so that these customers
may make direct purchase and transportation arrangements with
12
suppliers and pipelines. Customers with 250 DTH or more of annual gas
consumption may make direct purchase and transportation arrangements. BGE also
plans to conduct a pilot transportation program for up to 25,000 residential
customers beginning in November 1997. A transportation fee is charged by BGE
that is equivalent to its operating margin on gas it sells to similar customers
for the service from the city gate to the customer's facility. This program
enables BGE to maintain throughput at a level which assures that fixed costs are
spread over the maximum number of DTH. BGE is authorized by the Maryland
Commission to provide balancing and gas brokering services for its
transportation customers and to bundle pipeline capacity with gas for off-system
sales.
GAS RATE MATTERS
On November 20, 1995, the Maryland Commission issued an Order (the 1995
Rate Order) authorizing BGE an annualized gas base rate increase of $19.3
million, including $2.4 million to recover higher depreciation expense. The
increase is equivalent to approximately 3.7% of total 1996 gas revenues. In
granting the increase, the Commission provided a return on BGE's higher level of
gas rate base associated with system expansion and improvement and recognized
increases in gas operating expenses associated with maintaining the expanded gas
distribution system. This was partially offset by a reduction in the authorized
gas rate of return to 9.04% from the 9.40% gas rate of return previously
authorized.
The 1995 Rate Order also provided for the recognition of the remaining
portion of postretirement benefits costs not currently included in gas rates and
authorized the Company, effective January 1, 1998, to begin amortizing over a
fifteen-year period the gas portion of postretirement and postemployment benefit
costs deferred prior to December 1995. In addition, the Maryland Commission
authorized the Company to amortize certain environmental costs incurred through
October 1995 over a ten-year period and to defer for future recovery additional
environmental costs incurred after that date.
FRANCHISES
BGE has nonexclusive electric and gas franchises to use streets and other
highways which are adequate and sufficient to permit BGE to engage in its
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 BGE's gas properties in that municipality. Conditions
of the franchises are satisfactory. BGE also has 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 the last year thereof 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
The Company is engaged in diversified businesses through three groups of
subsidiaries.
BGE CORP. AND SUBSIDIARIES -- OUR ENERGY MARKETING COMPANIES INCLUDING OUR NEW
POWER MARKETING BUSINESS
BGE Corp. is a wholly owned subsidiary of BGE that serves as the holding
company for our three energy marketing businesses:
(Bullet) Power Marketing -- We recently formed a new subsidiary,
CONSTELLATION POWER SOURCE, INC., for the purpose of entering the
power marketing business. This new business involves the purchase
and sale of electric power and electric power derivatives, and
related activities including power brokering, marketing, risk
management activities, and derivative trading. Goldman Sachs
Power, LLC, an affiliate of Goldman Sachs & Co., the investment
banking firm, is the exclusive advisor to Constellation Power
Source, Inc. for risk management and power marketing.
13
(Bullet) Natural Gas Brokering -- During 1996 we expanded the activities of
CONSTELLATION ENERGY SOURCE, INC. (formerly named BNG, Inc.). This
subsidiary provides natural gas brokering and related services for
wholesale and retail customers.
(Bullet) Energy Services -- In 1995, we created BGE ENERGY PROJECTS &
SERVICES, INC., which provides energy services including private
electric and gas distribution systems, energy consulting, power
quality, and campus energy systems. We provide district cooling
and heating systems through that subsidiary and through our
partnership with the Poole & Kent Company, called COMFORTLINKTM.
We also sell power quality equipment through another subsidiary,
POWERDIGM SYSTEMS, INC.; and perform energy services contracting
work though a subsidiary SKILES ENERGY CORP.
THE CONSTELLATION COMPANIES -- POWER GENERATION, REAL ESTATE, AND FINANCIAL
INVESTMENTS
The Constellation Companies' businesses are concentrated in three major
areas -- power generation projects, financial investments, and real estate
projects (including senior-living facilities). A significant portion of the
Constellation Companies' activities are conducted through joint ventures in
which they hold varying ownership interests.
The Constellation Companies hold up to a 50% ownership interest in 26 power
generating projects in operation or under construction and indirect ownership of
minority interests in several power generation and distribution projects
accounting for $373 million of the Constellation 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: coal 160 MW, solar 170 MW, geothermal 126 MW, waste coal 182 MW,
wood burning 70 MW, hydro 30 MW, and natural gas 182 MW. In addition, another $4
million has been spent on projects in development. The Constellation Companies
also participate in the operation and maintenance of 15 power generation
projects existing or under construction, 12 of which are projects in which the
Constellation Companies hold an ownership interest. Financial investments
account for $204 million of the Constellation Companies' assets. These assets
include $94 million in internally and externally managed securities portfolios,
$77 million in a monoline financial guaranty (credit enhancement) company, and
$33 million in tax-oriented transactions. Real estate and senior-living projects
account for $562 million of the Constellation Companies' assets. These projects
include raw land, office buildings, retail projects, distribution facility
projects, an entertainment, dining, and retail complex in Orlando, Florida
(which we may sell as discussed below), a mixed-use planned-unit development,
and senior-living facilities. The majority of the real estate projects are in
the Baltimore-Washington area and have been adversely affected by the depressed
real estate and economic market.
The Constellation Companies' investment in wholesale power generating
projects includes $227 million representing ownership interests in 16 projects
that sell electricity in California under Interim Standard Offer No. 4 (SO4)
power purchase agreements. Under these agreements, the projects supply
electricity to purchasing utilities at a fixed rate for the first ten years of
the agreements and thereafter at fixed capacity payments plus variable energy
rates based on the utilities' avoided cost for the remaining term of the
agreements. Avoided cost generally represents a utility's lowest-cost
next-available source of generation to service the demands on its system. These
power generation projects began the conversion to supplying electricity at
avoided cost rates in 1996 and will continue to convert through the end of 2000.
As a result of declines in purchasing utilities' avoided costs subsequent to the
inception of these agreements, revenues at these projects based on current
avoided cost levels would be substantially lower than revenues presently being
realized under the fixed price terms of the agreements. At current avoided cost
levels, the Constellation Companies would experience reduced earnings or incur
losses associated with these projects, which could be significant. While eight
projects transition from fixed to variable energy rates in 1997 and 1998,
revenues from the other projects having SO4 contracts are expected to continue
to increase during this period tending to offset revenue declines on those
projects. Six of the seven largest revenue producing projects will not make the
transition to variable energy rates until the 1999-2000 timeframe such that any
material reductions in revenues would not be anticipated before 2000.
During the second quarter of 1996, the Constellation Companies determined
that successful mitigation measures for two of these plants are now unlikely and
that the investment in these plants was impaired. Accordingly, the Constellation
Companies recorded a $7.0 million after-tax write off of the investment in these
plants.
14
The Constellation Companies are investigating and pursuing alternatives for
certain of these power generation projects including, but not limited to,
repowering the projects to reduce operating costs, changing fuels to reduce
operating costs, renegotiating the power purchase agreements to improve the
terms, restructuring financings to improve the financing terms, and selling its
ownership interests in the projects.
The Company cannot predict the financial impact that these matters
regarding any of these projects may have on the Constellation Companies or BGE,
but the impact could be material.
FIRST QUARTER EVENT WILL RESULT IN AN ESTIMATED $12 MILLION AFTER TAX WRITEDOWN
AT THE CONSTELLATION COMPANIES
In ITEM 7. MD&A -- CONSTELLATION COMPANIES' OPERATIONS AND NOTE 12 TO
CONSOLIDATED FINANCIAL STATEMENTS, we discuss the real estate market and
financial matters about the Constellation Companies' real estate projects
including:
(Bullet) our current real estate strategy is to hold each real estate
project until we can realize a reasonable value for it,
(Bullet) depending on market conditions, we could have losses on
future sales,
(Bullet) accounting rules require a writedown to market value if either of
two things occurs:
-- we change our intent to hold a project to an intent to sell,
or
-- expected cash flow from a project is less than the investment
in the project.
In mid-March we received an unsolicited offer to buy the Constellation
Companies' Church Street Station, which is an entertainment, dining, and retail
complex in Orlando, Florida. Because of the unique character of Church Street
Station and the geographic distance of this project from our other real estate
holdings in the Baltimore-Washington corridor, we decided that considering a
sale is the appropriate strategy. We plan to negotiate with this potential
purchaser and also to explore whether there are others who are interested in
purchasing the project on better terms.
Based on the accounting rules mentioned above, our decision is a change of
intent, and we are required to write down our investment to the market value.
Determining the market value for such a unique project is difficult, but the
unsolicited offer is the best indication available to us and we used it to
determine the amount of the writedown.
Although all financial data for the first quarter is not yet available,
this means we expect the Constellation Companies' earnings for the first quarter
of 1997 to be generally flat compared to 1996 in spite of this writedown.
BGE HOME PRODUCTS & SERVICES, INC. AND ITS SUBSIDIARY -- OUR HOME PRODUCTS AND
COMMERCIAL BUILDING SYSTEMS BUSINESSES
For many years, BGE sold and serviced appliances and provided home
improvements. In 1994, BGE moved this business into a subsidiary, BGE Home
Products & Services, Inc. This company sells and services appliances, including
televisions, stereo and sound equipment, video cassette recorders, videocameras,
washers, dryers, ranges, refrigerators, microwaves, and other appliances
primarily used by customers at home. It has an active home improvement business
including kitchen and bathroom remodeling, replacement doors and windows,
siding, and roofing. Its subsidiary, Maryland Environmental Systems, Inc.
specializes in the installation and service of commercial and residential
heating, air conditioning, plumbing, and electrical systems.
15
DIVERSIFIED BUSINESS CAPITAL REQUIREMENTS
Capital requirements for diversified businesses for 1994 through 1996,
along with estimated amounts for 1997 through 1999, are set forth below:
1994 1995 1996 1997 1998 1999
---- ---- ---- ---- ---- ----
(IN MILLIONS)
Diversified Business Capital Requirements
- -----------------------------------------
Investment requirements................................ $51 $118 $118 $214 $180 $205
Retirement of long-term debt........................... 37 55 52 108 165 186
--- ---- ---- ---- ---- ----
Total diversified business capital requirements...... $88 $173 $170 $322 $345 $391
=== ==== ==== ==== ==== ====
In the past, capital requirements of our diversified businesses only
included the Constellation Companies because they had the only significant
capital requirements. However, we anticipate Constellation Power Source, Inc.
will have significant capital requirements and these are included in the table
for future years. As discussed below under "Investment Requirements," capital
requirements for 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 shown above include the Constellation
Companies' investments in financial limited partnerships and funding for the
development and acquisition of projects, as well as net loans made to project
partnerships, ComfortLink's funding for construction of district energy
projects, and funding for growing Constellation Power Source's power marketing
business. Investment requirements for the years 1997 through 1999 reflect
estimates of funding during such periods for ongoing and anticipated projects.
Also, guarantees of $47 million may be called which are not included above.
Estimates of our diversified businesses' investment requirements are
subject to continuous review and modification. Actual investment requirements
may vary significantly from the amounts above due to the type and number of
projects selected for development, the impact of market conditions on those
projects, the ability to obtain financing, and the availability of internally
generated cash.
DIVERSIFIED BUSINESS DEBT AND LIQUIDITY
Our diversified businesses plan to meet capital requirements by refinancing
debt as it comes due, by additional borrowing, and with cash generated by the
businesses. This includes cash from operations, sale of assets, and earned tax
benefits. BGE Home Products & Services may also meet capital requirements
through sales of receivables as discussed in NOTE 12 TO CONSOLIDATED FINANCIAL
STATEMENTS.
If the Constellation Companies can get a reasonable value for real estate,
additional cash may be obtained by selling real estate projects. The
Constellation 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.
In addition, the Constellation Companies have a $75 million revolving
credit agreement and ComfortLink has a $50 million revolving credit agreement to
provide additional cash for short-term financial needs.
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.
16
ENVIRONMENTAL MATTERS
The Company is subject to regulation with regard to air and water quality,
waste disposal, and other environmental matters by various federal, state, and
local authorities. Certain of these regulations require substantial expenditures
for additions to utility plant and the use of more expensive low-sulfur fuels.
While the Company cannot now precisely estimate the total effect of existing and
future environmental regulations and standards upon its existing and proposed
facilities and operations, the necessity for compliance with existing standards
and regulations has caused BGE to increase capital expenditures by approximately
$138 million during the five-year period 1992-1996. It is estimated that the
capital expenditures necessary to comply with such standards and regulations
will be approximately $16 million, $38 million, and $14 million for 1997, 1998,
and 1999, respectively.
AIR: The Federal Clean Air Act (the Act) mandates health and welfare
standards for concentrations of air pollutants. The State of Maryland is charged
by the Act with the responsibility for setting limits on all major sources of
these pollutants in the State so that these standards are not exceeded. Except
for Crane Units 1 and 2, BGE's generating units are limited to burning fuel
(coal or oil) with sulfur content of 1% or below. All units are limited to
emitting 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. 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 Crane Units must meet limits of 3.5 pounds per
million Btu for sulfur dioxide, which is equivalent to a coal sulfur content of
approximately 2.4%. BGE is in compliance with existing air quality regulations.
The Clean Air Act Amendments of 1990 contain two titles designed to reduce
emissions of sulfur dioxide and nitrogen oxide (NOx) from electric generating
stations. Title IV contains provisions for compliance in two phases. Phase I of
Title IV became effective January 1, 1995, and Phase II of Title IV must be
implemented by 2000. BGE met the requirements of Phase I by installing flue gas
desulfurization systems and through fuel switching and unit retirements. BGE is
currently examining what actions will be required in order to comply with Phase
II. However, BGE anticipates that compliance will be attained by some
combination of fuel switching, flue gas desulfurization, unit retirements, or
allowance trading.
At this time, plans for complying with NOx control requirements under Title
I of the Act are less certain because all implementation regulations have not
yet been finalized by the government. It is expected that by the year 1999 these
regulations will require additional NOx controls for ozone attainment at BGE's
generating plants and other BGE facilities. The controls will result in
additional expenditures that are difficult to predict prior to the issuance of
such regulations. Based on existing and proposed ozone nonattainment
regulations, BGE currently estimates that the NOx controls at BGE's generating
plants will cost approximately $90 million. BGE is currently unable to predict
the cost of compliance with the additional requirements at other BGE facilities.
WATER: The discharge of effluents into the waters of the State of Maryland
is regulated by the Maryland Department of the Environment (MDE), in accordance
with the National Pollutant Discharge Elimination System (NPDES) permit program,
established pursuant to the Federal Clean Water Act. At the present time, all of
BGE's steam electric generating plants have the required NPDES permits.
MDE water quality regulations require, among other things, specifying
procedures for determining 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. At this time BGE continually performs studies to
determine whether any modifications will be required to comply with these
regulations.
WASTE DISPOSAL: The United States Environmental Protection Agency (EPA) has
promulgated regulations implementing those portions of the Resource Conservation
and Recovery Act which deal with management of hazardous wastes. These
regulations, and the Hazardous and Solid Waste Amendments of 1984, designate
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 similar regulations governing the
management of hazardous wastes, which closely parallel the federal regulations.
BGE has implemented procedures for compliance with all applicable federal and
state regulations governing the management of hazardous wastes. Certain high
volume utility wastes such as fly ash and bottom ash have been exempted from
these regulations. The Company currently utilizes almost all of its coal fly ash
and bottom
17
ash as structural fill material in a manner approved by the State of Maryland.
The remainder of the coal ash is sold to the construction industry for a number
of approved applications.
The Federal Comprehensive Environmental Response, Compensation and
Liability Act (Superfund statute) establishes liability for the cleanup of
hazardous wastes found contaminating 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 their predecessors in title at the time of the contamination.
In addition, many states have enacted 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 BGE and seven
other defendants to recover past and future expenditures associated with cleanup
of a site located at Kane and Lombard Streets in Baltimore. The EPA complaint
was dismissed in November 1995. The State of Maryland intervened by filing a
similar complaint in the same case and court on February 12, 1990. The
complaints allege that BGE arranged for its fly ash to be deposited on the site.
Settlement discussions continue among all parties. Additional investigation was
initiated on the remainder of the site by the MDE for the EPA but was never
completed. BGE and 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, neither the total site cleanup costs, nor BGE's share, can presently
be estimated.
In the early 1970's, BGE 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 (PCBs are hazardous chemicals frequently used as a fire-resistant
coolant in electrical equipment). On December 7, 1987, the EPA notified BGE and
nine other utilities that they are considered potentially responsible parties
(PRPs) with respect to the cleanup of the site. A remedial investigation and
feasibility study (RI/FS) by BGE and the other PRPs was submitted to the EPA on
October 14, 1994. Estimated costs for the various remedies included in the RI/FS
range greatly (from $15 million to $45 million). Until a specific remedy is
chosen, BGE is not able to predict the actual cleanup costs. BGE's share of the
cleanup costs, estimated to be approximately 15.79%, could be material.
From 1985 until 1989, BGE 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 BGE on
August 15, 1990, that it and approximately 1,000 other entities were PRPs with
respect to the cost of all remedial activities to be conducted at the site. The
PRPs have agreed to perform waste characterization, remove and dispose of all
tanks and drums of waste, and perform a remedial investigation at the site.
BGE's share of the liability at this site currently is estimated to be
approximately 2.39%, but this may change as additional information about the
site is obtained. The actual cost of remedial activities has not been
determined. As a result of these factors, BGE's potential liability cannot
presently be estimated. However, such liability is not expected to be material.
On August 30, 1994, BGE was named as a defendant in UNITED STATES V.
KEYSTONE SANITATION COMPANY, ET AL. The litigation was instituted by EPA in the
United States District Court for the Middle District of Pennsylvania involving
contamination of the Keystone Sanitation Company landfill Superfund site located
in Adams County, Pennsylvania. BGE was named as a third party defendant based
upon allegations that BGE had drums of asbestos shipped to the site. There are
eleven original defendants, approximately 150 other third party defendants, and
approximately 570 fourth party defendants. Neither the costs of future site
remediation, nor the extent of BGE's potential liability can be estimated at
this time. However, such liability is not expected to be material.
In December 1995, BGE was notified by the EPA that it is 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. BGE, through its 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. To date the EPA has processed
approximately one third of the drums and incurred expenses of about $2.2
million. After the EPA completes its drum removal phase of the clean up it will
investigate potential soil and groundwater contamination.
18
Although BGE's potential liability cannot be estimated, it is believed that such
liability is not likely to be substantial based on the limited amount of waste
shipped to the site from BGE facilities.
In September, 1996, BGE received an information request from the EPA
concerning 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 EPA has sent information requests to approximately 17 other
parties. BGE's records indicate that it sold empty drums to Drumco, Inc. from
approximately 1983-1990. BGE is currently reviewing all relevant documents and
interviewing employees involved in selling the drums to Drumco. BGE's potential
liability cannot be estimated at this time. However we believe that any
liability is not likely to be material based on BGE's records showing that only
empty storage drums were sold to Drumco, Inc.
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. BGE is coordinating an investigation of these former
coal gas plant sites, including exploration of corrective action options to
remove coal tar, with the MDE. In late December 1996, the Maryland Department of
the Environment and BGE signed a consent order that requires BGE to implement
remedial action plans addressing contamination at and related to the Spring
Gardens site. The specific remedial actions for this site will be developed in
the future. As explained in NOTE 12 TO CONSOLIDATED FINANCIAL STATEMENTS, BGE
has recognized estimated environmental costs at all former gas manufacturing
plant sites (based on remedial action options) which are considered probable
totaling $50 million in nominal dollars. These costs, net of accumulated
amortization, have been deferred as a regulatory asset (see NOTE 5 TO
CONSOLIDATED FINANCIAL STATEMENTS). Accounting rules also require BGE to
disclose additional costs deemed by BGE to be less likely than probable costs,
but still "reasonably possible" of being incurred at these sites. Because of the
results of recent studies at these sites, it is reasonably possible that these
additional costs could exceed the amount recognized by approximately $48 million
in nominal dollars ($11 million in current dollars, plus the impact of inflation
at 3.1% over a period of up to 60 years).
As previously disclosed, on May 3, 1994 Constellation Power, Inc. (formerly
"Constellation Energy, Inc.") (CPI) was named as a defendant in REPUBLIC
IMPERIAL ACQUISITION V. STOCKMAR ENERGY, INC., ET AL. Civil No. 940120R(LSP)
(Dist. Ct., So. Dist. California), litigation concerning a waste landfill. In
December 1996, CPI was dismissed from this proceeding.
EMPLOYEES
As of December 31, 1996, BGE employed 7,032 people.
19
ITEM 2. PROPERTIES
ELECTRIC: The principal electric generating plants of BGE are as follows:
GENERATION
INSTALLED ----------
PLANT LOCATION CAPACITY (MW) PRIMARY FUEL 1996 1995
----- -------- ------------- ------------ ---- ----
(AT DECEMBER 31, 1996)
Steam
Calvert Cliffs Calvert County, MD 1,675 Nuclear 12,069,937 12,937,965
Brandon Shores Anne Arundel County, MD 1,291 Coal 8,849,357 9,091,443
Herbert A. Wagner Anne Arundel County, MD 1,006 Coal/Oil/Gas 3,149,334 3,002,183
Charles P. Crane Baltimore County, MD 380 Coal 2,000,992 1,631,798
Gould Street Baltimore City, MD 104 Oil 49,583 66,851
Riverside Baltimore County, MD 78 Oil/Gas 15,356 40,229
Jointly Owned -- Steam
Keystone Armstrong and 359(A) Coal 2,650,786 2,429,568
Indiana Counties, PA
Conemaugh Indiana County, PA 181(A) Coal 1,202,914 1,244,060
Combustion Turbine
Notch Cliff Baltimore County, MD 128 Gas 12,470 27,702
Perryman Harford County, MD 350 Oil/Gas 91,197 42,875
Westport Baltimore City, MD 121 Gas 6,420 19,133
Riverside Baltimore County, MD 173 Oil/Gas 5,450 7,118
Philadelphia Road Baltimore City, MD 64 Oil 1,829 4,813
Charles P. Crane Baltimore County, MD 14 Oil 707 1,237
Herbert A. Wagner Anne Arundel County, MD 14 Oil 513 971
----- ---------- ----------
Totals 5,938 30,106,845 30,547,946
===== ========== ==========
(A) BGE-owned proportionate interest and entitlement. These totals include
diesel capacity of 2 megawatts and 1 megawatt for Keystone and Conemaugh,
respectively.
BGE also owns two-thirds of the outstanding capital stock of Safe Harbor Water
Power Corporation, and is currently entitled to 277 megawatts of the rated
capacity of the Safe Harbor Hydroelectric Project. Safe Harbor is operated under
a FERC license which expires in the year 2030.
GAS: BGE has propane air and liquefied natural gas facilities as described in
GAS OPERATIONS.
GENERAL: All of the principal plants and other important units of BGE located
in Maryland are held in fee except that several properties (not including any
principal electric or gas generating plant or the principal headquarters
building owned by BGE in downtown Baltimore) in BGE's service area are held
under lease arrangements. The leased spaces are used for various offices and
service. Electric transmission and electric and gas distribution lines are
constructed principally (a) in public streets and highways pursuant to
franchises or (b) on permanent fee simple or easement rights-of-way secured for
the most part by grants from record owners and to a relatively small part by
condemnation.
BGE's undivided interests as a tenant-in-common in the properties acquired for
the Keystone and Conemaugh Plants located in Pennsylvania are held in fee by
BGE, subject to minor defects and encumbrances which do not materially interfere
with the use of the properties by BGE.
All of BGE's property referred to above is subject to the lien of the Mortgage
securing BGE's First Refunding Mortgage Bonds.
20
ITEM 3. LEGAL PROCEEDINGS
ASBESTOS
Since 1993, BGE has been served in several actions concerning asbestos. The
actions are collectively 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 BGE knew of and exposed
individuals to an asbestos hazard. The actions relate to two types of claims.
The first type, direct claims by individuals exposed to asbestos, were
described in a Report on Form 8-K filed August 20, 1993. BGE and approximately
70 other defendants are involved. Approximately 520 non-employee plaintiffs each
claim $6 million in damages ($2 million compensatory and $4 million punitive).
BGE does not know the specific facts necessary for BGE to assess its potential
liability for these type claims, such as the identity of the BGE facilities at
which the plaintiffs allegedly worked as contractors, the names of the
plaintiffs' employers, and the date on which the exposure allegedly occurred.
The second type are claims made by one manufacturer -- Pittsburgh Corning
Corp. -- against BGE and approximately eight others, as third-party defendants.
These claims relate to approximately 1,500 individual plaintiffs. BGE does not
know the specific facts necessary for BGE to assess its potential liability for
these type claims, such as the identity of BGE facilities containing asbestos
manufactured by the manufacturer, the relationship (if any) of each of the
individual plaintiffs to BGE, the settlement amounts for any individual
plaintiffs who are shown to have had a relationship to BGE, and the dates on
which/places at which the exposure allegedly occurred.
Until the relevant facts for both type claims are determined, BGE is unable
to estimate what its liability, if any, might be. Although insurance and hold
harmless agreements from contractors who employed the plaintiffs may cover a
portion of any ultimate awards in the actions, BGE's 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 legal or regulatory proceedings involving BGE.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not Applicable.
21
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
STOCK TRADING
BGE's 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, 1997, there were 76,929 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, the financial condition of the
Company and other factors. Quarterly dividends were declared on the Common Stock
during 1996 and 1995 in the amounts set forth below.
COMMON STOCK DIVIDENDS AND PRICE RANGES
1996 1995
----------------------------- ----------------------------
PRICE* PRICE*
DIVIDEND ------------- DIVIDEND ----------------
DECLARED HIGH LOW DECLARED HIGH LOW
-------- ---- --- -------- ---- ---
First Quarter......................................... $ .39 $ 29-1/2 $ 26-1/8 $ .38 $ 25 $ 22
Second Quarter........................................ .40 28-5/8 25-1/2 .39 26-1/2 23-1/8
Third Quarter......................................... .40 28-5/8 25 .39 26-5/8 24-3/8
Fourth Quarter........................................ .40 28-3/4 25-3/4 .39 29 25-1/2
------ -----
Total............................................... $ 1.59 $1.55
====== =====
*Based on New York Stock Exchange Composite Transactions as reported in the
eastern edition of THE WALL STREET JOURNAL.
22
Item 6. Selected Financial Data
Compound
1996 1995 1994 1993 1992 Growth
- -----------------------------------------------------------------------------------------------------------------------------
(Dollar amounts in thousands, except per share amounts) 5-Year 10-Year
Summary of Operations
Total Revenues $3,153,247 $2,934,799 $2,782,985 $2,741,385 $2,559,536 4.63% 4.63%
Expenses Other Than Interest and Income
Taxes 2,483,782 2,239,107 2,147,726 2,124,993 2,024,227 4.15 5.21
-------------------------------------------------------------
Income From Operations 669,465 695,692 635,259 616,392 535,309 6.54 2.73
Other Income 6,130 8,819 32,365 20,310 22,132 (26.25) (9.83)
-------------------------------------------------------------
Income Before Interest and Income Taxes 675,595 704,511 667,624 636,702 557,441 5.55 2.49
Net Interest Expense 198,438 196,977 190,154 188,764 189,747 0.19 5.82
-------------------------------------------------------------
Income Before Income Taxes 477,157 507,534 477,470 447,938 367,694 8.37 1.39
Income Taxes 166,333 169,527 153,853 138,072 103,347 14.22 1.65
-------------------------------------------------------------
Net Income 310,824 338,007 323,617 309,866 264,347 4.17 1.25
Preferred and Preference Stock Dividends 38,536 40,578 39,922 41,839 42,247 (2.05) 3.67
-------------------------------------------------------------
Earnings Applicable to Common Stock $ 272,288 $ 297,429 $ 283,695 $ 268,027 $ 222,100 5.26 0.95
=============================================================
Earnings Per Share of Common Stock $1.85 $2.02 $1.93 $1.85 $1.63 2.07 (1.26)
Dividends Declared Per Share of Common
Stock $1.59 $1.55 $1.51 $1.47 $1.43 2.58 3.03
Ratio of Earnings to Fixed Charges 3.10 3.21 3.14 3.00 2.65 6.43 (2.97)
Ratio of Earnings to Fixed Charges and
Preferred and Preference Stock Dividends
Combined 2.44 2.52 2.47 2.34 2.08 6.04 (2.68)
Financial Statistics at Year End
Total Assets $8,550,970 $8,316,663 $8,037,502 $7,829,613 $7,208,660 3.68 6.44
=============================================================
Capitalization
Long-term debt $2,758,769 $2,598,254 $2,584,932 $2,823,144 $2,376,950 2.91 5.62
Preferred stock -- 59,185 59,185 59,185 59,185 -- --
Redeemable preference stock 134,500 242,000 279,500 342,500 395,500 (19.53) 10.40
Preference stock not subject to mandatory
redemption 210,000 210,000 150,000 150,000 110,000 13.81 6.68
Common shareholders' equity 2,857,113 2,812,682 2,717,866 2,620,511 2,534,639 5.82 5.77
-------------------------------------------------------------
Total Capitalization $5,960,382 $5,922,121 $5,791,483 $5,995,340 $5,476,274 3.12 5.63
=============================================================
Book Value Per Share of Common Stock $19.35 $19.07 $18.42 $17.94 $17.63 2.62 3.43
Number of Common Shareholders 77,550 79,811 81,505 82,287 80,371 1.74 0.07
Baltimore Gas and Electric Company and Subsidiaries
23
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations
Introduction
In Management's Discussion and Analysis we explain the general financial
condition and the results of operations for BGE and its diversified business
subsidiaries including:
(bullet) what factors affect our business,
(bullet) what our earnings and costs were in 1996 and 1995,
(bullet) why those earnings and costs were different from the year before,
(bullet) where our earnings came from,
(bullet) how all of this affects our overall financial condition,
(bullet) what our expenditures for capital projects were in 1994 through 1996
and what we expect them to be in 1997 through 1999, and
(bullet) where cash will come from to pay for future capital expenditures.
As you read Management's Discussion and Analysis, it may be helpful to refer to
our Consolidated Statements of Income on page 35, which present the results of
our operations for 1996, 1995, and 1994. In Management's Discussion and
Analysis, we analyze and explain the annual changes in the specific line items
in the Consolidated Statements of Income. Our analysis may be important to you
in making decisions about your investments in BGE.
You may notice some changes in this year's discussion, compared to past years.
This is because we volunteered to participate in a pilot program with the
Securities and Exchange Commission to write financial documents in plain
English. As a result, we have re-written our entire Management's Discussion and
Analysis section. Our goal is to discuss our financial condition in language
that is more easily understood.
BGE and Potomac Electric Power Company have agreed to merge into a new company
named Constellation Energy Corporation. We plan to complete the merger as soon
as we obtain all regulatory approvals. These matters are discussed in more
detail in Note 12 beginning on page 52 and in a Registration Statement on
Form S-4 (Registration No. 33-64799). The merger may impact many of the matters
discussed in Management's Discussion and Analysis including earnings, results of
electric operations, expenses, liquidity, and capital resources.
The electric utility industry is undergoing rapid and substantial change.
Competition is increasing. The regulatory environment (federal and state) is
shifting. These matters are discussed briefly in the "Competition and Response
to Regulatory Change" section on page 26 in Management's Discussion and
Analysis. They are discussed in detail in this Annual Report on Form 10-K. BGE
continuously evaluates these changes. Based on the evaluations, BGE refines
short and long term business plans with the primary goal of protecting our
security holders' investments and providing them with superior returns on their
investment in BGE. In order to support this primary goal, we also focus on other
groups who impact our primary goal. For example, we stress providing low cost,
reliable power to our electric customers. As you read Management's Discussion
and Analysis, many BGE initiatives to support our primary goal are mentioned.
These include the proposed merger with Potomac Electric Power Company, designed
to position us to remain competitive as the industry changes, and our
diversification effort. We enter new businesses which we believe will support
our primary goal. For example, new businesses may be opportunities to:
(bullet) provide customers of our core energy business additional services, or
(bullet) attract new customers for our core energy business, or
(bullet) expand our diversified stream of revenues.
We believe our newest subsidiary, Constellation Power Source, Inc., will satisfy
all three criteria. Its proposed power marketing business is described in detail
in the front of this report.
- --------------------------------------------------------------------------------
Results of Operations
In this section, we discuss our 1996 and 1995 earnings and the factors affecting
them. We begin with a general overview, then separately discuss earnings for the
utility business and for diversified businesses.
Overview
Total Earnings per Share of Common Stock
1996 1995 1994
- --------------------------------------------------------------------------------
Earnings per share from
current-year operations:
Utility business $1.96 $1.84 $1.81
Diversified businesses (subsidiaries) .31 .18 .12
----------------------
Total earnings per share from
current-year operations 2.27 2.02 1.93
Disallowed replacement
energy costs (see Note 12) (.42) -- --
----------------------
Total earnings per share $1.85 $2.02 $1.93
======================
1996
Our 1996 total earnings decreased $25.1 million, or $.17 per share, from 1995.
Our total earnings decreased because we reserved for disallowed replacement
energy costs. We discuss this in detail in the "Disallowed Replacement Energy
Costs" section on page 27.
In 1996, we had higher utility earnings from current-year operations due to
three factors: we sold more electricity and gas due to colder winter weather
(people use more gas and electricity to heat their homes in colder weather),
there was an increase in the number of customers, and we had lower operations
and maintenance expenses. We would have had even higher utility earnings from
current-year operations except we sold less electricity in the third quarter due
to milder summer weather. We discuss our utility earnings in more detail
beginning on page 26.
Baltimore Gas and Electric Company and Subsidiaries
24
In 1996, we had higher earnings from our diversified business subsidiaries
mostly because the Constellation Companies had higher earnings from power
generation projects and financial investments. We discuss our diversified
business earnings in more detail beginning on page 30.
1995
Our 1995 total earnings increased $13.7 million, or $.09 per share, from 1994.
In 1995, we had higher utility earnings mostly due to greater sales of
electricity during an extremely hot summer and higher electricity and gas sales
resulting from colder fall weather. We would have had even higher utility
earnings except for the mild weather in the first half of the year, lower net
other income and deductions (miscellaneous non-operating income and expenses),
and lower allowance for funds used during construction (an accounting procedure
used to exclude the cost of capital from expense and include it as part of the
cost of utility plant construction).
In 1995, we had higher earnings from our diversified businesses mostly because
the Constellation Companies had higher earnings from power generation projects
and financial investments.
Utility Business
Before we go into the details of our electric and gas operations, we believe it
is important to discuss four factors that have a strong influence on our utility
business performance: regulation, the weather, other factors including the
condition of the economy in our service territory, and competition.
Regulation by the Maryland Public Service Commission
The Maryland Public Service Commission (Maryland Commission) determines the
rates we can charge our customers. Our rates consist of a "base rate" and a
"fuel rate". The base rate is the rate the Maryland Commission allows us to
charge our customers for the cost of providing them service, plus a profit. We
have both an electric base rate and a gas base rate. Higher electric base rates
apply during the summer when the demand for electricity is the highest. Gas base
rates are not affected by seasonal changes.
The M