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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
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, 1995 Commission file number
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 (brace) Chicago Stock Exchange, Inc.
Pacific Stock Exchange, Inc.
Preferred Stock, Series B 4 1/2%, Cumulative,
$100 Par Value (brace) New York Stock Exchange, Inc.
Preferred Stock, Cumulative, $100 Par Value:
Series C 4%
Series D 5.40%
Preference Stock, Cumulative, $100 Par Value: (brace) Philadelphia Stock Exchange, Inc.
7.78%, 1973 Series
7.50%, 1986 Series
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 29, 1996 was approximately $4,171,501,536 based
upon New York Stock Exchange composite transaction closing price.
COMMON STOCK, WITHOUT PAR VALUE -- 147,527,114 SHARES OUTSTANDING ON FEBRUARY
29, 1996.
DOCUMENTS INCORPORATED BY REFERENCE
PART OF FORM 10-K DOCUMENT INCORPORATED BY REFERENCE
III Definitive Proxy Statement for the Annual Meeting of Shareholders of Baltimore Gas and
Electric Company to be held on April 23, 1996 (Proxy Statement).
TABLE OF CONTENTS
PAGE
PART I
Item 1 -- Business
General..................................................................................... 1
Capital Requirements........................................................................ 2
Electric Business
Electric Regulatory Matters and Competition............................................... 3
Electric Rate Matters..................................................................... 4
Nuclear Operations........................................................................ 5
Electric Load Management, Energy, and Capacity Purchases.................................. 7
Fuel for Electric Generation.............................................................. 8
Gas Business
Gas Regulatory Matters and Competition.................................................... 9
Gas Operations............................................................................ 10
Gas Rate Matters.......................................................................... 10
Electric Operating Statistics............................................................... 11
Gas Operating Statistics.................................................................... 12
Franchises.................................................................................. 13
Diversified Businesses...................................................................... 13
Environmental Matters....................................................................... 15
Employees................................................................................... 17
Item 2 -- Properties.................................................................................. 18
Item 3 -- Legal Proceedings........................................................................... 18
Item 4 -- Submission of Matters to a Vote of Security Holders......................................... 19
Item 10 -- Executive Officers of the Registrant (Instruction 3 to Item 401(b) of Regulation S-K)....... 20
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................................................. 32
Item 9 -- Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure.................................................................................. 56
PART III
Item 10 -- Directors and Executive Officers of the Registrant.......................................... 56
Item 11 -- Executive Compensation...................................................................... 56
Item 12 -- Security Ownership of Certain Beneficial Owners and Management.............................. 56
Item 13 -- Certain Relationships and Related Transactions.............................................. 56
PART IV
Item 14 -- Exhibits, Financial Statement Schedules and Reports on Form 8-K............................. 56
Signatures................................................................................................. 60
PART I
ITEM 1. BUSINESS
Baltimore Gas and Electric Company and Subsidiaries are herein collectively
referred to as the Company. The Company is engaged in utility operations and
related businesses through Baltimore Gas and Electric Company (BGE). The Company
is engaged in diversified businesses primarily through four wholly owned
subsidiaries of BGE, Constellation Holdings, Inc. and its subsidiaries
(collectively, the Constellation Companies), BGE Home Products & Services, Inc.
(HP&S) and its subsidiary Maryland Environmental Systems, Inc. (MES), BGE Energy
Projects & Services, Inc. (EP&S), and BNG, Inc. For financial information by
segment of operation see NOTE 2 TO CONSOLIDATED FINANCIAL STATEMENTS.
BGE was incorporated under the laws of the State of Maryland on June 20,
1906, and is primarily engaged in the business of producing, purchasing, and
selling electricity, and purchasing, transporting, and selling natural gas
within the State of Maryland. 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 -- ELECTRIC. BGE also owns two-thirds of the outstanding
capital stock, including one-half of the voting securities, of Safe Harbor Water
Power Corporation (Safe Harbor), a hydroelectric producer on the Susquehanna
River at Safe Harbor, Pennsylvania. (SEE ITEM 2. PROPERTIES -- ELECTRIC.)
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.) Also, the
utility industry is facing potentially substantial regulatory change designed to
foster competition in the provision of gas and electric services. 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 on page 3 and GAS REGULATORY MATTERS AND COMPETITION on page 9.
Diversified businesses conducted by the Constellation Companies, HP&S, MES,
EP&S, and BNG, Inc. are discussed under DIVERSIFIED BUSINESSES on page 13 and
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS (MD&A).
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
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
1991.......................................... 79 14 7 90 6 4
Certain prior-year amounts have been reclassified to conform with the
current year's presentation.
*Net of income taxes.
BGE currently derives approximately 22% of electric revenues and 42% of gas
revenues from customers located in the City of Baltimore and 78% and 58%,
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
1
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 $540 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 on page 33, gas purchased for resale as a
percentage of gas revenues (49%) is greater than electric fuel and purchased
energy as a percentage of electric revenues (26%). It should be noted that both
purchased gas costs and electric fuel costs are passed through to the customer
with no mark-up for profit. The combined effects of these factors yield the
observed relationship between operating revenues and income for electric and gas
operations.
BGE and Potomac Electric Power Company (PEPCO) have agreed to merge. 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 in March 1997. The reasons for the merger and
other information about the merger are discussed in more detail under ELECTRIC
REGULATORY MATTERS AND COMPETITION on pages 3 and 4 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, as discussed in ELECTRIC REGULATORY MATTERS AND COMPETITION on pages 3
and 4 and GAS REGULATORY MATTERS AND COMPETITION on page 9, BGE (and after the
merger the new company to be named Constellation Energy 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, acquisitions of related or unrelated
businesses, business combinations, and additions to or dispositions of portions
of its franchised service territories. BGE and its subsidiaries may from time to
time be engaged in preliminary discussions, either internally or with third
parties, regarding one or more of these potential strategies.
CAPITAL REQUIREMENTS
The Company's actual capital requirements for 1993 through 1995, along with
estimated amounts for 1996 through 1998, are set forth below. Certain prior-year
amounts have been restated to conform with the current year's presentation.
1993 1994 1995 1996 1997 1998
(IN MILLIONS)
Utility Business
Construction expenditures (excluding AFC)
Electric.................................................... $ 365 $ 345 $ 223 $ 231 $ 205 $ 212
Gas......................................................... 52 68 70 68 73 67
Common...................................................... 41 42 51 41 47 46
Total construction expenditures........................... 458 455 344 340 325 325
AFC (a)........................................................ 23 34 22 11 10 10
Nuclear fuel (uranium purchases and processing charges)........ 47 42 46 45 45 44
Deferred energy conservation expenditures (b).................. 33 41 46 34 25 27
Deferred nuclear expenditures (b).............................. 14 8 -- -- -- --
Retirement of long-term debt and redemption of preference
stock....................................................... 907 203 279 98 164 125
Total utility business.................................... 1,482 783 737 528 569 531
Diversified Businesses........................................... 300 88 173 141 206 220
Total..................................................... $ 1,782 $ 871 $ 910 $ 669 $ 775 $ 751
(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.
2
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. The Constellation Companies' capital
requirements for diversified businesses may vary from the estimates set forth
above due to a number of factors including market and economic conditions and
are discussed in detail under MD&A -- DIVERSIFIED BUSINESSES CAPITAL
REQUIREMENTS on page 30.
BGE's estimated construction, nuclear fuel, and deferred energy
conservation expenditures are expected to amount to approximately $1.6 billion,
$220 million, and $145 million, respectively, for the five-year period
1996-2000. Electric construction expenditures reflect the installation of a
5,000-kilowatt diesel generator at the Calvert Cliffs Nuclear Power Plant which
is scheduled to be placed in service in 1996 and 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, 1991 through December 31, 1995, BGE expended
$2,156 million for gross additions to utility plant or approximately 27% of its
total utility plant (exclusive of nuclear fuel) at December 31, 1995. During the
same period, a total of $376 million of utility plant was retired. Nuclear fuel
expenditures include uranium purchases and processing charges.
BGE presently estimates that approximately $930 million will be required
for retirements and redemptions of long-term debt (including sinking fund
payments) and BGE preference stock during the five-year period 1996-2000.
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.
ELECTRIC BUSINESS
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 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
wholesale electric generation market and so increased competition in the
wholesale segment of the electric utility industry. Pursuant to its authority
under the 1992 Act, the FERC issued a number of orders in specific cases
commencing in December 1993 directing utilities to provide transmission
services. The FERC's actions have increased the availability of transmission
services, thus creating significant competition in the wholesale power market.
Other developments resulted from policies at the 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. Each company
independently reached the conclusion that key factors contributing to success in
this 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. The accelerating pace of electric utility mergers
attests to the appropriateness of business combinations between electric utility
companies to address such needs. During 1993, one electric utility company
merger was announced. In 1994, the number was increased to two, and during 1995,
including those following the announcement of the Merger on September 25, 1995,
six such transactions were announced. At the date of this report, there had been
one electric utility company merger announced in 1996.
3
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 and
a number of regulatory approvals) 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 by March
1997.
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
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 (PSC) held hearings in 1995 to consider electric utility
restructuring, the impact of competition, and regulatory reform and considered
possible scenarios ranging from limited to full competition. The PSC issued a
general policy statement in June, 1995 on changes recommended for Maryland's
electric industry. It concluded that wholesale competition remains in the best
interests of the state's energy consumers, but that in view of the availability
of efficient, reliable, comparatively low-cost power, Maryland energy consumers
do not currently need retail competition to capture the benefits of the
competitive energy market. In addition, the PSC mandated competitive bidding for
all new generation and agreed that utilities need flexibility to offer their
customers terms and conditions that meet unique customer needs.
It is not possible to predict the ultimate effect competition will have on
BGE's earnings in the future.
In April 1993, the PSC directed that an independent study be performed
regarding the distribution of costs between BGE's regulated utility operations
and unregulated merchandise and appliance services activities. A coalition of
HVAC contractors had alleged that the unregulated operations were being
subsidized by the utility. A cost allocation proceeding was held to examine the
Company's allocation procedures as well as to deal with the demand by the
coalition that the unregulated activities be required to pay a royalty based on
unregulated revenues to compensate ratepayers for the use of the BGE name and
its goodwill. In August, 1995, the PSC issued an order denying the imposition of
royalty payments and requiring BGE to file a cost allocation manual based upon
the principle of fully distributed cost allocation. BGE filed the manual in
February, 1996.
ELECTRIC RATE MATTERS
ENERGY CONSERVATION SURCHARGE
The PSC 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. 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 PSC. (See discussion in ITEM
7. MANAGEMENT'S DISCUSSION AND ANALYSIS.) The surcharge is reset on July 1 of
each year.
4
ELECTRIC FUEL RATE PROCEEDINGS
By statute, electric fuel costs are recoverable if the PSC finds that BGE
demonstrates that, among other things, it has maintained the productive capacity
of its generating plants at a reasonable level. The PSC 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 PSC 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.)
BGE is required to submit to the PSC the actual generating performance data
for each calendar year 45 days after year end. The PSC reviews BGE's performance
for each calendar 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 PSC which are
conducted in accordance with the procedures outlined above under 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 believes, therefore, it is 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 PSC 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 would 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 PSC by both BGE and People's
Counsel. If the PSC upholds the Hearing Examiner, the Company's earnings would
be impacted by approximately $4.5 million.
5
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 PSC disallow
recovery of $2 million of replacement energy costs. On November 14, 1991, a
Hearing Examiner at the PSC 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 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, are estimated to be $458 million. This estimate is 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 are being reviewed by the PSC
in the 1989-1991 fuel rate proceeding, and People's Counsel and others have
challenged recovery of some part of the associated replacement energy costs. In
the PSC's Rate Order issued in BGE's 1990 Base Rate Case, it found that $4
million of operations and maintenance expenses incurred by BGE during the
1989-1990 outages at the Plant should not be recoverable from customers. The PSC
concluded that the related work, which was performed at Unit 1 during the
1989-1990 outage, was avoidable and caused by Company actions which were
deficient. The work characterized as avoidable had a significant impact on the
duration of the Unit 1 outage. The PSC's Order stated that its conclusions in
this proceeding did not have a binding effect in the fuel rate proceeding on the
recoverability of Calvert Cliffs' replacement energy costs. However, BGE
believes that it is doubtful that the PSC will authorize recovery of the full
amount of replacement energy costs presently under investigation. Based on a
review of the circumstances surrounding the extended outages by BGE personnel as
well as independent consultants, in 1990 BGE recorded a provision of $35 million
against the possible disallowance of such costs. However, BGE cannot determine
whether replacement energy costs may be disallowed in the 1989-1991 fuel rate
proceeding in excess of the provision, but such amounts could be material.
On March 15, 1994, the PSC Staff and the Office of People's Counsel filed
testimony in the 1989-1991 fuel rate proceedings. The PSC Staff concluded that
approximately 46% of the outage time was unreasonably incurred and that
approximately $200 million of replacement energy costs should be disallowed.
People's Counsel concluded that approximately $400 million of the replacement
energy costs should be disallowed. BGE filed rebuttal testimony in January 1995
in which it vigorously contested the findings of Staff and People's Counsel.
Additional testimony was filed by the PSC Staff and People's Counsel in October
1995 and BGE will file its final testimony in May 1996. Further hearings in this
matter are expected to occur in 1996.
As previously reported, in December 1988, the NRC categorized the Plant as
one requiring close monitoring and increased NRC attention. The NRC did so
following certain events that the NRC indicated raised questions about the
effectiveness of past corrective action regarding engineering and technical
areas and the overall approach to safety at the Plant. Details of such events
were described in the Report on Form 10-K for the year ended December 31, 1990
in the section titled "Nuclear Operations" on pages 4 through 7. In February
1992, the NRC removed the Plant from its list of nuclear plants categorized as
requiring close monitoring as a result of improved performance in previously
identified problem areas and the demonstration of a sustained period of safe
operation.
6
OPERATIONS IN 1991 AFTER THE EXTENDED OUTAGE
The Plant generated 9,036,100 MWH in 1991, which resulted in a capacity
factor of 63%. BGE filed a fuel rate application under GUPP in June 1992,
however, the Hearing Examiner has determined that the 1991 case will not be
addressed until the case covering the extended outage has been resolved.
OPERATIONS SUBSEQUENT TO THE EXTENDED OUTAGE
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. 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%. A review of 1995
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; the summer
peak capacity impact for 1996 from active load management is expected to be
approximately 474 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
December 31, 1995 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 PSC.
7
FUEL FOR ELECTRIC GENERATION
Information regarding BGE's electric generation by fuel type and the cost
of fuels in the five-year period 1991-1995 is set forth in the following tables:
AVERAGE COST OF FUEL CONSUMED
GENERATION BY FUEL TYPE ((CENTS) PER MILLION BTU)
1995 1994 1993 1992 1991 1995 1994 1993 1992 1991
Nuclear (a)................... 43 % 39 % 43 % 40 % 33 % 47.22 52.06 53.01 45.54 48.64
Coal.......................... 57 56 55 54 44 148.64 148.64 151.85 154.76 160.74
Oil........................... 1 3 3 1 5 267.59 245.28 253.36 254.19 284.87
Hydro & Gas................... 3 3 3 3 4 -- -- -- -- --
104 101 104 98 86
Interchange/Purchases (b)..... ( 4 ) ( 1 ) ( 4 ) 2 14
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%. The average delivered costs per ton paid by BGE for
Brandon Shores coal for the years 1991 through 1995 were $39.80, $39.98, $39.49,
$37.55 and $37.36, respectively. 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. Coal purchased in 1995 had a sulfur content of less than 1%
compared to approximately 2.4% in prior years to meet the requirements of the
Clean Air Act. The average delivered costs per ton paid by BGE for coal at Crane
for the years 1991 through 1995 were $38.88, $38.37, $37.25, $37.42 and $46.50,
respectively. 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%. The average delivered costs per ton paid by BGE for coal at Wagner for
the years 1991 through 1995 were $44.49, $43.19, $40.62, $37.54 and $37.73,
respectively.
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. The average delivered
costs per ton for coal for these plants for the years 1991 through 1995 were
$33.07, $31.53, $32.42, $33.22 and $32.49, respectively.
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. The average delivered prices per barrel paid by BGE for
residual fuel oil for the years 1991 through 1995 were $15.53, $17.25, $15.69,
$16.30 and $17.41, respectively.
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 concentrates to meet approximately 80% of its requirements
through 1997 and approximately 50% of its requirements for 1998.
8
Conversion: BGE has contractual commitments providing for the conversion of uranium
concentrates into uranium hexafluoride which will meet approximately 40%
of its requirements through 1998.
Enrichment: BGE has a contract with the U.S. Energy Corporation for the enrichment of
70% of BGE's enrichment requirements through 1998.
Fuel Assembly Fabrication: BGE has contracted for the fabrication of fuel assemblies for reloads it
requires through 1996.
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 MD&A -- LIQUIDITY AND CAPITAL RESOURCES on
page 29.
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 $12 million
for Calvert Cliffs each year.
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.
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 THE CONSOLIDATED FINANCIAL
STATEMENTS on page 42 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.
GAS BUSINESS
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 PSC 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. Currently as part of its response to the increase in
competition in the natural gas business, BGE has proposals before the PSC for
profit sharing for capacity release revenues and savings from gas purchases
which are less than a predefined city gate index (called Market Based Rates) for
sales in BGE's gas territory.
9
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 473,597 dekatherms (DTH) per day during the winter period and 291,731
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.
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 suppliers and pipelines. BGE also plans to conduct a pilot
transportation program for residential customers. 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
PSC 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 PSC 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 4.8% of total 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 PSC 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.
10
ELECTRIC OPERATING STATISTICS
YEAR ENDED DECEMBER 31,
1995 1994 1993 1992 1991
Electric Output (In Thousands) -- MWH:
Generated................................ 30,548 28,413 28,907 25,626 22,767
Purchased (A)............................ 7,403 6,270 3,643 4,323 5,522
Subtotal............................ 37,951 34,683 32,550 29,949 28,289
Less Interchange and Other Sales......... 8,149 5,684 4,149 3,180 1,167
Total Output........................ 29,802 28,999 28,401 26,769 27,122
Power Generated and Purchased at
Times of Peak Load (MW) (one hour):
Generated by Company..................... 5,162 3,384 5,245 3,679 4,948
Net Purchased (A)........................ 785 2,654 631 1,879 962
Peak Load (B)............................ 5,947 6,038 5,876 5,558 5,910
Annual System Load Factor (%).............. 57.2 54.7 55.2 54.8 52.4
Revenues (In Thousands)
Residential.............................. $ 955,239 $ 931,711 $ 931,643 $ 839,954 $ 882,591
Commercial............................... 879,438 852,989 869,829 842,694 850,038
Industrial............................... 208,441 205,611 199,042 201,950 212,864
System Sales............................. 2,043,118 1,990,311 2,000,514 1,884,598 1,945,493
Interchange and Other Sales.............. 166,964 118,027 91,543 64,323 23,845
Other.................................... 21,029 19,083 20,090 16,611 21,531
Total............................... $2,231,111 $2,127,421 $2,112,147 $1,965,532 $1,990,869
Sales (In Thousands) -- MWH:
Residential.............................. 10,966 10,670 10,614 9,735 10,097
Commercial............................... 12,635 12,351 12,395 11,909 11,707
Industrial............................... 4,591 4,433 3,763 3,663 3,708
System Sales............................. 28,192 27,454 26,772 25,307 25,512
Interchange and Other Sales.............. 8,149 5,684 4,149 3,180 1,166
Total............................... 36,341 33,138 30,921 28,487 26,678
Customers
Residential.............................. 988,179 978,591 968,212 956,570 939,734
Commercial............................... 103,399 101,957 100,820 99,673 98,254
Industrial............................... 4,161 3,967 3,800 3,761 3,584
Total............................... 1,095,739 1,084,515 1,072,832 1,060,004 1,041,572
Average Cost of Fuel Consumed ((cents) per
million Btu)............................. 104.78 112.44 112.77 110.20 127.89
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 page 7 for a discussion of active load management programs which may be
activated at times of peak load.
Certain prior-year amounts have been reclassified to conform with the
current year's presentation.
11
GAS OPERATING STATISTICS
YEAR ENDED DECEMBER 31,
1995 1994 1993 1992 1991
Gas Output (In Thousands) -- DTH:
Purchased.......................................... 70,391 68,541 71,221 70,211 63,160
LNG Withdrawn from Storage......................... 815 698 725 742 551
Produced........................................... 528 828 259 92 17
Total Output.................................. 71,734 70,067 72,205 71,045 63,728
Delivery Service Gas
Delivered (A)...................................... 44,177 41,897 38,521 41,048 40,503
Total......................................... 115,911 111,964 110,726 112,093 104,231
Peak Day Sendout (DTH)............................... 706,287 761,900 657,700 609,200 610,200
Capability on Peak Day (DTH)......................... 847,000 847,000 847,000 847,000 817,000
Revenues (In Thousands)
Residential........................................ $248,283 $262,736 $265,601 $242,737 $220,653
Commercial
Excluding Delivery Service...................... 109,859 121,005 121,832 112,147 96,189
Delivery Service................................ 3,696 2,285 3,287 3,591 3,031
Industrial
Excluding Delivery Service...................... 16,730 20,140 22,250 21,123 14,855
Delivery Service................................ 16,332 9,635 12,920 14,290 14,288
Other.............................................. 5,604 5,448 7,273 6,511 6,777
Total......................................... $400,504 $421,249 $433,163 $400,399 $355,793
Sales (In Thousands) -- DTH:
Residential........................................ 40,211 40,279 40,029 39,042 36,519
Commercial
Excluding Delivery Service...................... 23,612 23,712 23,830 23,478 20,687
Delivery Service................................ 6,982 6,490 7,428 7,102 6,433
Industrial
Excluding Delivery Service...................... 4,102 4,410 5,298 5,314 3,605
Delivery Service................................ 35,925 33,837 31,390 33,638 34,240
Total......................................... 110,832 108,728 107,975 108,574 101,484
Customers
Residential........................................ 506,739 498,152 491,165 486,863 482,085
Commercial......................................... 38,422 37,891 37,518 37,000 36,561
Industrial......................................... 1,334 1,354 1,353 1,412 1,385
Total......................................... 546,495 537,397 530,036 525,275 520,031
BGE achieved an all-time peak day sendout of 761,900 DTH on January 19,
1994.
(A) Represents gas purchased by alternate fuel customers directly from suppliers
for which BGE receives a fee for transportation through its system
("delivery service"). (SEE MD&A -- RESULTS OF OPERATIONS.)
Certain prior-year amounts have been reclassified to conform with the
current year's presentation.
12
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
GENERAL
Diversified businesses consist of the operations of the Constellation
Companies, HP&S and its subsidiary MES, EP&S, and BNG, Inc.
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 25 power
generating projects in operation or under construction accounting for $345
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 121 MW, waste coal 182 MW, wood burning 70 MW,
hydro 30 MW, and natural gas 182 MW. In addition, another $12 million has been
spent on projects in development. The Constellation Companies also participate
in the operation and maintenance of 14 power generation projects existing or
under construction, 10 of which are projects in which the Constellation
Companies hold an ownership interest. Financial investments account for $206
million of the Constellation Companies' assets. These assets include $92 million
in internally and externally managed securities portfolios, $78 million in a
monoline financial guaranty (credit enhancement) company, and $36 million in
tax-oriented transactions. Real estate and senior living projects account for
$495 million of the Constellation Companies' assets. These projects include raw
land, office buildings, retail, and commercial projects, an entertainment,
dining, and retail complex in Orlando, Florida, 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 $197 million representing ownership interests in 16 projects
which 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 next lowest cost
generation to service the demands on its system. These power generation projects
are scheduled to convert to supplying electricity at avoided cost rates in
various years beginning in late 1996 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 could experience reduced earnings or incur losses
associated with these projects, which could be significant. While nine projects
transition from fixed to variable energy rates in the 1996 through 1998
timeframe, revenues from the other projects having SO4 contracts are expected to
continue to increase during this period tending to offset revenue declines on
the nine projects. Six of the seven largest revenue producing projects will not
make the transition to variable energy rates until the 1999-2000
13
timeframe such that any material reductions in revenues would not be anticipated
until the years 2000 and 2001. 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, renegotiating the power purchase agreements, restructuring financings,
and selling its ownership interests in the projects. Two of these wholesale
power generating projects, in which the Constellation Companies' investment
totals $30 million, have executed agreements with Pacific Gas & Electric (PG&E)
providing for the curtailment of output through the end of the fixed-price
period in return for payments from PG&E. The payments from PG&E during the
curtailment period will be sufficient to fully amortize the existing project
finance debt. However, following the curtailment period, the projects remain
contractually obligated to commence production of electricity at the avoided
cost rates, which could result in reduced earnings or losses for the reasons
described above. The Company cannot predict the impact that these matters
regarding any of the 16 projects may have on the Constellation Companies or the
Company, but the impact could be material.
HP&S was formed in mid 1994. HP&S is engaged in the sales and service of
gas and electric appliances. This business recently was expanded to include
kitchen remodeling and servicing of heating and air conditioning systems. In
December 1994, HP&S acquired MES, a company specializing in installation of
commercial and residential heating, air conditioning, and plumbing.
EP&S was formed in late 1995. EP&S provides a broad range of customized
energy services to major customers including industrial, institutional, and
government customers in commercial office buildings, warehouses, educational,
healthcare, and retail facilities. These energy services include customer
electrical system improvements, lighting and mechanical engineering services,
campus and multi-building systems, brokering and associated financial contracts,
and district chilled water systems.
BNG, Inc. is a wholly owned subsidiary of BGE which engages in natural gas
brokering.
CAPITAL REQUIREMENTS
Capital requirements for diversified businesses for 1993 through 1995,
along with estimated amounts for 1996 through 1998, are set forth below:
1993 1994 1995 1996 1997 1998
(IN MILLIONS)
Retirement of long-term debt............................ $222 $37 $ 55 $ 49 $135 $138
Investment requirements................................. 78 51 118 92 71 82
Total diversified businesses.......................... $300 $88 $173 $141 $206 $220
The investment requirements shown above include the Constellation
Companies' portion of equity funding to committed projects under development as
well as net loans made to project partnerships. The investment requirements for
past periods reflect actual funding of projects, whereas investment requirements
for the years 1996-1998 reflect the Constellation Companies' estimate of funding
during such periods for ongoing and anticipated projects. Also, guarantees of
$35 million may be called which are not included above.
Estimates of the Constellation Companies' 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. The Constellation Companies' investment requirements have been
met in the past through the internal generation of cash and through borrowings
from institutional lenders.
The investment requirements shown above do not include amounts for the
Company's other diversified businesses because to date the investment
requirements of those businesses have been minimal.
See NOTES 3 AND 4 TO CONSOLIDATED FINANCIAL STATEMENTS AND
MD&A -- LIQUIDITY AND CAPITAL RESOURCES -- DIVERSIFIED BUSINESSES CAPITAL
REQUIREMENTS for additional information about diversified activities.
14
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
$174 million during the five-year period 1991-1995. It is estimated that the
capital expenditures necessary to comply with such standards and regulations
will be approximately $9 million, $20 million, and $39 million for 1996, 1997,
and 1998, 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 ash as structural fill material in a
15
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 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. 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.
16
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. No formal legal proceedings have been instituted
against BGE with respect to these sites. The technology for cleaning up such
sites is still developing, and potential remedies for these sites have not been
determined. As explained in NOTE 12 TO THE CONSOLIDATED FINANCIAL STATEMENTS on
page 52, BGE has recognized estimated environmental costs at these sites
totaling $38.6 million as of December 31, 1995. Any cleanup costs for these
sites in excess of the amount accrued, which could be significant in total,
cannot presently be estimated.
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). The plaintiffs are owners of a non-hazardous waste landfill located
in Imperial County, California. The plaintiffs allege that defendants delivered
hazardous materials consisting of spent geothermal filters containing certain
metals used in the operation of four geothermal projects. The claims are made
under the Superfund statute and state and common law against the operators,
project owners and others. Certain CPI subsidiaries have ownership interests in
three of the projects. These Constellation Companies have indemnification rights
from project lessees and operators. Approximately 45 other defendants, in
addition to CPI, have been named to date. The Constellation Companies are
currently evaluating the claims and site investigation is at a preliminary
stage. As a result, total investigation and clean up costs, as well as the
Constellation Companies' share of such costs, cannot presently be estimated.
EMPLOYEES
As of December 31, 1995, BGE employed 7,275 people for its utility
operations and 729 people for its subsidiaries, excluding the Constellation
companies. Five hundred seventy-five people were employed by Constellation
Holdings, Inc., including its subsidiaries involved in the operation of power
projects and senior living facilities. In addition, the Constellation Companies
employ approximately 800 employees at an entertainment, dining, and retail
complex in Orlando, Florida.
17
ITEM 2. PROPERTIES
ELECTRIC: The principal electric generating plants of BGE are as follows:
INSTALLED GENERATION (MWH)
PLANT LOCATION CAPACITY (MW) PRIMARY FUEL 1995 1994
(AT DECEMBER 31, 1995)
Steam
Calvert Cliffs Calvert County, MD 1,675 Nuclear 12,937,965 11,219,516
Brandon Shores Anne Arundel County, MD 1,291 Coal 9,091,443 8,857,557
Herbert A. Wagner Anne Arundel County, MD 1,006 Coal/Oil/Gas 3,002,183 2,940,978
Charles P. Crane Baltimore County, MD 380 Coal 1,631,798 1,847,851
Gould Street Baltimore City, MD 104 Oil 66,851 124,323
Riverside Baltimore County, MD 78 Oil/Gas 40,229 9,146
Jointly Owned -- Steam
Keystone Armstrong and 359(A) Coal 2,429,568 2,188,760
Indiana Counties, PA
Conemaugh Indiana County, PA 181(A) Coal 1,244,060 1,156,109
Combustion Turbine
Notch Cliff Baltimore County, MD 128 Gas 27,702 11,472
Perryman Harford County, MD 350 Oil/Gas 42,875 26,960
Westport Baltimore City, MD 121 Gas 19,133 10,266
Riverside Baltimore County, MD 173 Oil/Gas 7,118 8,711
Philadelphia Road Baltimore City, MD 64 Oil 4,813 8,250
Charles P. Crane Baltimore County, MD 14 Oil 1,237 1,804
Herbert A. Wagner Anne Arundel County, MD 14 Oil 971 1,300
Totals 5,938 30,547,946 28,413,003
(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 on page 10.
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 as 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.
ITEM 3. LEGAL PROCEEDINGS
ASBESTOS
Since 1993, BGE was 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. The 516 non-employee plaintiffs each claim $6
million in damages ($2 million compensatory and $4 million punitive). BGE does
not know
18
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 two manufacturers -- Owens Corning
Fiberglass and Pittsburgh Corning Corp. -- against BGE and approximately eight
others, as third-party defendants. Owens Corning Fiberglass has dismissed its
claims against BGE. The second type 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 two manufacturers, 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.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not Applicable.
19
ITEM 10. EXECUTIVE OFFICERS OF THE REGISTRANT
Executive Officers of the Registrant are:
OTHER OFFICES OR POSITIONS
NAME AGE PRESENT OFFICE HELD DURING PAST FIVE YEARS
Christian H. Poindexter 57 Chairman of the Board (A) Vice Chairman of the Board
(Since January 1, 1993)
Edward A. Crooke 57 Chairman of the Board - President, Utility Operations
Subsidiaries and President (B)
(Since January 1, 1996)
Bruce M. Ambler 56 President and Chief Executive
Officer
Constellation Holdings, Inc.
(Since August 1, 1989)
George C. Creel 62 Executive Vice President Senior Vice President, Generation
and acting Chief Operating Senior Vice President
Officer Vice President, Nuclear Energy
(Since January 1, 1996)
Robert E. Denton 53 Senior Vice President Vice President, Nuclear Energy
Generation Plant General Manager, Calvert
(Since January 1, 1996) Cliffs Nuclear Power Plant
Thomas F. Brady 46 Vice President Vice President, Customer Service
Customer Service and and Accounting
Distribution Vice President, Accounting and
(Since July 1, 1993) Economics
Herbert D. Coss, Jr. 61 Vice President Vice President, Marketing and
Gas Gas Operations
(Since October 1, 1994) Vice President, Electric Intercon-
nection and Transmission
Vice President, Interconnection
and Operations
Charles H. Cruse 51 Vice President Plant General Manager, Calvert
Nuclear Energy Cliffs Nuclear Power Plant
(Since January 1, 1996) Manager, Nuclear Engineering
Carserlo Doyle 53 Vice President Manager, Telecommunications
Electric Interconnection Principal Engineer -- Electric
and Transmission Interconnection
(Since January 1, 1994)
Jon M. Files 60 Vice President
Management Services
(Since September 1, 1981)
Sharon S. Hostetter 51 Vice President Manager, Marketing
Marketing and Sales Division Manager, Resource
(Since November 1, 1995) Application and Customer
Development Group, Rochester
Gas and Electric Corporation
Ronald W. Lowman 51 Vice President Manager, Fossil Engineering
Fossil Energy Manager, Fossil Engineering
(Since January 1, 1993) Services
G. Dowell Schwartz, Jr. 59 Vice President
General Services
(Since April 1, 1990)
Charles W. Shivery 50 Vice President Vice President, Corporate
Finance and Accounting, Finance Group
Chief Financial Officer and Treasurer and Secretary
Secretary
(Since July 1, 1993)
Joseph A. Tiernan 57 Vice President Vice President, Corporate
Corporate Affairs Administration
(Since February 1, 1993)
20
Stephen F. Wood 43 President and Vice President, Marketing and Sales
Chief Executive Officer Manager, Major Customer Projects
BGE Energy Projects & Manager, System Engineering
Services, Inc. and Construction
(Since November 1, 1995) Manager, Distribution Engineering
Manager, Transportation
(A) Chief Executive Officer, Director, and member of the Executive Committee.
(B) Chief Operating Officer, Director, and member of the Executive Committee.
21
Officers of the Registrant are elected by, and hold office at the will of,
the Board of Directors and do not serve a "term of office" as such. There is no
arrangement or understanding between any officer and any other person pursuant
to which the officer was selected.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
STOCK TRADING
BGE's Common Stock, which is traded under the ticker symbol BGE, is listed
on the New York, Chicago, and Pacific stock exchanges, and has unlisted trading
privileges on the Boston, Cincinnati, and Philadelphia exchanges.
As of February 29, 1996, there were 79,507 common shareholders of record.
DIVIDEND POLICY
The Common Stock is entitled to dividends when and as declared by the Board
of Directors. There are no limitations in any indenture or other agreements on
payment of dividends; however, holders of Preferred Stock (first) and holders of
Preference Stock (next) are entitled to receive, when and as declared, from the
surplus or net profits, cumulative yearly dividends at the fixed preferential
rate specified for each series and no more, payable, quarterly, and to receive
when due the applicable Preference Stock redemption payments, before any
dividend on the Common Stock shall be paid or set apart.
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, 1995 and 1994 in the amounts set forth below.
COMMON STOCK DIVIDENDS AND PRICE RANGES
1996 (THROUGH MARCH 12, 1996)
DIVIDEND PRICE*
DECLARED HIGH LOW
First Quarter............. $ .39 $29-1/2 $26-3/8
Second Quarter............
Third Quarter.............
Fourth Quarter............
Total...................
1995
DIVIDEND PRICE*
DECLARED HIGH LOW
First Quarter............. $ .38 $25 $22
Second Quarter............ .39 26-1/2 23-1/8
Third Quarter............. .39 26-5/8 24-3/8
Fourth Quarter............ .39 29 25-1/2
Total................... $1.55
1994
DIVIDEND PRICE*
DECLARED HIGH LOW
First Quarter............. $ .37 $25-1/2 $22-3/8
Second Quarter............ .38 24-3/8 20-1/2
Third Quarter............. .38 23-3/4 20-3/4
Fourth Quarter............ .38 23-5/8 21-1/4
Total................... $1.51
*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
1995 1994 1993 1992 1991 Growth
- ---------------------------------------------------------------------------------------------------------------------------
(Dollar amounts in thousands, except per share amounts) 5-year 10-Year
Summary of Operations
Total Revenues $2,934,799 $2,782,985 $2,741,385 $2,559,536 $2,514,631 5.47% 4.56%
Expenses Other Than Interest and Income
Taxes 2,239,107 2,147,726 2,124,993 2,024,227 2,026,910 3.10 4.93
- ----------------------------------------------------------------------------------------------------------------------------
Income From Operations 695,692 635,259 616,392 535,309 487,721 16.36 3.46
Other Income 8,819 32,365 20,310 22,132 28,095 (23.87) (4.60)
- ---------------------------------------------------------------------------------------------------------------------------
Income Before Interest and Income Taxes 704,511 667,624 636,702 557,441 515,816 14.33 3.30
Net Interest Expense 196,977 190,154 188,764 189,747 196,588 3.58 5.98
- ----------------------------------------------------------------------------------------------------------------------------
Income Before Income Taxes 507,534 477,470 447,938 367,694 319,228 21.03 2.43
Income Taxes 169,527 153,853 138,072 103,347 85,547 53.41 1.11
- ----------------------------------------------------------------------------------------------------------------------------
Income Before Cumulative Effect of
Change in Accounting Method 338,007 323,617 309,866 264,347 233,681 14.01 3.17
Cumulative Effect of Change in the
Method of Accounting for Income Taxes --- --- --- --- 19,745 --- ---
- ----------------------------------------------------------------------------------------------------------------------------
Net Income 338,007 323,617 309,866 264,347 253,426 9.65 3.17
Preferred and Preference Stock Dividends 40,578 39,922 41,839 42,247 42,746 0.16 4.02
- ----------------------------------------------------------------------------------------------------------------------------
Earnings Applicable to Common Stock $ 297,429 $ 283,695 $ 268,027 $ 222,100 $ 210,680 11.45 3.06
============================================================================================================================
Earnings Per Share of Common Stock
Before Cumulative Effect of Change
in Accounting Method $2.02 $1.93 $1.85 $1.63 $1.511 3.13 0.77
Cumulative Effect of Change in the
Method of Accounting for Income
Taxes --- --- --- --- .16 --- ---
- ----------------------------------------------------------------------------------------------------------------------------
Total Earnings Per Share of Common Stock $2.02 $1.93 $1.85 $1.63 $1.67 7.61 0.77
============================================================================================================================
Dividends Declared Per Share of Common
Stock $1.55 $1.51 $1.47 $1.43 $1.40 2.06 3.40
Ratio of Earnings to Fixed Charges 3.21 3.14 3.00 2.65 2.27 12.52 (2.51)
Ratio of Earnings to Fixed Charges and
Preferred and Preference Stock Dividends
Combined 2.52 2.47 2.34 2.08 1.82 11.38 (1.99)
Financial Statistics at Year End
Total Assets $8,316,663 $8,037,502 $7,829,613 $7,208,660 $6,963,547 4.39 6.88
============================================================================================================================
Capitalization
Long-term debt $2,598,254 $2,584,932 $2,823,144 $2,376,950 $2,390,115 3.44 5.69
Preferred stock 59,185 59,185 59,185 59,185 59,185 --- ---
Redeemable preference stock 242,000 279,500 342,500 395,500 398,500 (7.89) 11.70
Preference stock not subject to mandatory
redemption 210,000 150,000 150,000 110,000 110,000 13.81 1.84
Common shareholders' equity 2,812,682 2,717,866 2,620,511 2,534,639 2,153,306 6.29 6.33
- ----------------------------------------------------------------------------------------------------------------------------
Total Capitalization $5,922,121 $5,791,483 $5,995,340 $5,476,274 $5,111,106 4.29 5.92
============================================================================================================================
Book Value Per Share of Common Stock $19.07 $18.42 $17.94 $17.63 $17.00 2.84 3.98
Number of Common Shareholders 79,811 81,505 82,287 80,371 71,131 1.79 0.04
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
23
Baltimore Gas and Electric Company and Subsidiaries
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
This annual report presents the financial condition and results of
operations of Baltimore Gas and Electric Company (BGE) and its
subsidiaries (collectively, the Company). Among other information,
it provides Consolidated Financial Statements, Notes to
Consolidated Financial Statements (Notes), Utility Operating
Statistics, and Selected Financial Data. The following discussion
explains factors that significantly affect the Company's results of
operations, liquidity, and capital resources.
Effective November 1, 1995, BGE formed a wholly owned subsidiary, BGE
Energy Projects & Services, Inc. (EP&S). EP&S' revenues and expenses are
included in diversified businesses revenues and diversified businesses
selling, general, and administrative expenses, respectively.
Results of Operations
Earnings per Share of Common Stock
Consolidated earnings per share were $2.02 for 1995 and $1.93 for
1994, an increase of $.09 and $.08 from prior-year amounts,
respectively. The changes in earnings per share reflect a higher
level of earnings applicable to common stock, offset partially by a
larger number of outstanding common shares. The summary below presents
the earnings-per-share amounts.
1995 1994 1993
- --------------------------------------------------------------------
Utility business $1.84 $1.81 $1.77
Diversified businesses .18 .12 .08
- --------------------------------------------------------------------
Total $2.02 $1.93 $1.85
====================================================================
Earnings Applicable to Common Stock
Earnings applicable to common stock increased $13.7 million in 1995
and $15.7 million in 1994. The increases reflect higher utility and
diversified businesses earnings.
Utility earnings increased in 1995 compared to the prior year due
to higher electric system sales resulting from the extremely hot
summer weather in 1995, and higher electric and gas sales resulting
from the colder fall weather experienced in 1995. These factors were
partially offset by lower electric and gas system sales resulting from
the milder weather experienced during the first half of the year as
compared to last year; lower net other income and deductions in 1995;
and a decrease in the allowance for funds used during construction.
Utility earnings increased in 1994 compared to the prior year due
to three principal factors: lower operations and maintenance expenses;
an increase in the allowance for funds used during construction; and
greater sales of electricity. The higher sales of electricity were
primarily due to an increased number of customers compared to 1993.
Both 1995 and 1994 earnings increases were offset partially by higher
depreciation and amortization expense, which includes the write-off of
certain Perryman costs in both years (see discussion on page 27). The
effect of weather on utility sales is discussed below.
The following factors influence BGE's utility operations earnings:
regulation by the Maryland Public Service Commission (PSC); the effect
of weather and economic conditions on sales; and competition in the
generation and sale of electricity. The gas base rate increase
authorized by the PSC in November 1995 favorably affected utility
earnings beginning in December 1995. The electric and gas base rate
increases authorized by the PSC in April 1993 favorably affected
utility earnings through April 1994. The electric fuel rate cases now
pending before the PSC discussed in Notes 1 and 12 could affect future
years' earnings.
Future competition may also affect earnings in ways that are not
possible to predict (see discussion on page 31).
Earnings from diversified businesses, which primarily represent the
operations of Constellation Holdings, Inc. (CHI) and its subsidiaries
(collectively, the Constellation Companies), BGE Home Products &
Services, Inc. and Subsidiary (HP&S), and EP&S, increased during
both 1995 and 1994. The reasons for these changes are discussed in the
"Diversified Businesses Earnings" section on pages 28 and 29.
Effect of Weather on Utility Sales
Weather conditions affect BGE's utility sales. BGE measures weather
conditions using degree days. A degree day is the difference between
the average daily actual temperature and the baseline temperature of
65 degrees. Hotter weather during the summer, measured by more
cooling degree days, results in greater demand for electricity to
operate cooling systems. Conversely, cooler weather during the
summer, measured by fewer cooling degree days, results in less demand
for electricity to operate cooling systems. Colder weather during the
winter, as measured by greater heating degree days, results in
greater demand for electricity and gas to operate heating systems.
Conversely, warmer weather during the winter, measured by fewer
heating degree days, results in less demand for electricity and gas to
operate heating systems. The degree-days chart below presents
information regarding cooling and heating degree days for 1995 and
1994.
24
Baltimore Gas and Electric Company and Subsidiaries
30-Year
1995 1994 Average
- --------------------------------------------------------------------
Cooling degree days 1,056 949 804
Percentage change
compared to prior year 11.3% 9.7%
Heating degree days 4,601 4,670 4,901
Percentage change
compared to prior year (1.5)% (5.8)%
BGE Utility Revenues and Sales
Electric revenues changed during 1995 and 1994 because of the following
factors:
1995 1994
- --------------------------------------------------------------------
(In millions)
System sales volumes $43.4 $ 9.9
Base rates 23.2 1.4
Fuel rates (13.8) (21.5)
- --------------------------------------------------------------------
Revenues from system sales 52.8 (10.2)
Interchange and other sales 49.0 26.5
Other revenues 1.4 (1.9)
- --------------------------------------------------------------------
Total electric revenues $103.2 $ 14.4
====================================================================
Electric system sales represent volumes sold to customers within BGE's
service territory at rates determined by the PSC. These amounts
exclude interchange sales and sales to other utilities, discussed
separately later. Following is a comparison of the changes in electric
system sales volumes:
1995 1994
- --------------------------------------------------------------------
Residential 2.8% 0.5%
Commercial 2.3 (0.4)
Industrial 3.6 17.8
Total 2.7 2.5
The increase in sales to residential and commercial customers
during 1995 reflects the extremely hot summer and colder fall weather
during 1995 and an increase in the number of customers, offset
partially by milder weather experienced during the first half of the
year as compared to last year. Sales to industrial customers increased
primarily due to an increase in the number of customers and the
increased sale of electricity to Bethlehem Steel, offset partially
by lower usage by other industrial customers. Bethlehem Steel has been
purchasing its full electricity requirements from BGE since March of
1994 and is selling power produced with its own generating
facilities to BGE rather than using the power to reduce its
requirements.
In 1994, sales to residential and commercial customers were
essentially unchanged from the prior year due to three factors: the
number of customers increased; higher sales from extreme weather
conditions early in the year slightly exceeded lower sales from
milder weather in the second half of the year; and usage-per-customer
decreased. Sales to industrial customers reflect primarily an increase
in the sale of electricity to Bethlehem Steel, which purchased more
electricity from BGE due to increased steel production and the fact
that Bethlehem Steel has been purchasing its full electricity
requirements from BGE since March of 1994.
Base rates are affected by two principal items: rate orders by the
PSC and recovery of eligible electric conservation program costs
through the energy conservation surcharge. Base rates increased in
1995 compared to 1994 due to recovery of a higher level of eligible
electric conservation program costs and the ability to collect the
full amount of energy conservation surcharge revenues, portions
of which had been deferred subject to refund in 1994 as discussed
below. Base rates increased slightly during 1994 due to the remaining
effect of the PSC's April 1993 rate order, offset partially by the
deferral of the portion of energy conservation surcharge billings
subject to refund.
Under the energy conservation surcharge, if the PSC determines
that BGE is earning in excess of its authorized rate of return, BGE
will have to refund (by means of lowering future surcharges) a portion
of energy conservation surcharge revenues to its customers. The portion
subject to the refund is compensation for foregone sales from
conservation programs and incentives for achieving conservation
goals and will be refunded to customers with interest beginning in the
ensuing July when the annual resetting of the conservation surcharge
rates occurs. BGE earned in excess of its authorized rate of
return on electric operations for the period July 1, 1993 through June
30, 1994. As a result, BGE deferred the portion of electric energy
conservation revenues subject to refund for the period December 1993
through November 1994. The deferral of these billings totaled $20.1
million.
Changes in fuel rate revenues result from the operation of the
electric fuel rate formula. The fuel rate formula is designed to
recover the actual cost of fuel, net of revenues from interchange
sales and sales to other utilities (see Notes 1 and 12). Changes in
fuel rate revenues and interchange and other sales normally do not
affect earnings. However, if the PSC were to disallow recovery of any
part of these costs, earnings would be reduced as discussed in Note 12.
Fuel rate revenues decreased during both 1995 and 1994 due to a lower
fuel rate, offset partially by increased electric system sales volumes.
The rate was lower in both years because of a less-costly
twenty-four month generation mix resulting from greater generation
at the Calvert Cliffs Nuclear Power Plant and Brandon Shores Power
Plant compared to the previous year, as well as lower fuel costs. BGE
expects electric fuel rate revenues to remain relatively constant
through 1996.
Interchange and other sales represent sales of BGE's energy
to the Pennsylvania-New Jersey-Maryland Interconnection (PJM) and
other utilities. The PJM is a regional power pool of eight member
companies including BGE. These sales occur after BGE has satisfied
the demand for its own system sales of electricity, if BGE's
available generation is the least costly available. Interchange
and other sales increased during 1995 and 1994 because BGE had a
less-costly generation mix than the other utilities. The
less-costly mix reflects greater generation from the Brandon
Shores Power Plant and the continued operation of the Calvert Cliffs
Nuclear Power Plant, which generated a record level of electricity
during 1995.
25
Baltimore Gas and Electric Company and Subsidiaries
Gas revenues changed during 1995 and 1994 because of the following factors:
1995 1994
- --------------------------------------------------------------------
(In millions)
Sales volumes $ 0.2 $ 3.6
Base rates 6.4 2.4
Gas cost adjustment revenues (27.4) (16.1)
Other revenues 0.1 (1.8)
- --------------------------------------------------------------------
Total gas revenues $(20.7) $(11.9)
====================================================================
The changes in gas sales volumes compared to the year before were:
1995 1994
- --------------------------------------------------------------------
Residential (0.2)% 0.6%
Commercial 1.3 (3.4)
Industrial 4.7 4.2
Total 1.9 0.7
Total gas sales increased during 1995 as a result of higher sales to
commercial and industrial customers, while sales to residential
customers were essentially the same as last year. Sales to commercial
customers increased compared to last year due to an increase in the
number of customers, increased usage per customer, and the colder
fall weather in 1995, offset partially by milder weather during
the first half of the year. Sales to industrial customers
increased compared to last year due to greater usage of gas per
customer. Total gas sales increased during 1994 because of higher
sales to residential and industrial customers, offset partially by
lower sales to commercial customers. Sales to industrial customers
reflect primarily greater usage of natural gas by Bethlehem Steel.
Sales to commercial and industrial customers were negatively impacted
because delivery service customers either voluntarily switched their
fuel source from natural gas to alternate fuels, or were
involuntarily interrupted by BGE as a result of extreme winter weather
conditions in the first quarter of 1994. Interruptible customers
maintain alternate fuel sources and pay reduced rates in exchange for
BGE's right to interrupt service during periods of peak demand.
Base rates increased slightly during 1995 and 1994 due to an increased
recovery of eligible gas conservation program costs through the
energy conservation surcharge. In addition, base rates increased
slightly during 1995 as a result of the PSC's November 1995 rate order,
which increased annual base rate revenues by $19.3 million, including
$2.4 million to recover higher depreciation expense. Future gas base
rate revenues are expected to be impacted favorably as a result of this
order.
Changes in gas cost adjustment revenues result primarily from the
operation of the purchased gas adjustment clause, commodity
charge adjustment clause, and the actual cost adjustment clause,
which are designed to recover actual gas costs (see Note 1).
Changes in gas cost adjustment revenues normally do not affect
earnings. Gas cost adjustment revenues decreased during 1995 and
1994 because of lower gas prices for purchased gas and lower sales
volumes subject to gas cost adjustment clauses. Delivery service
sales volumes are not subject to gas cost adjustment clauses because
delivery service customers purchase their gas directly from third
parties.
BGE Utility Fuel and Energy Expenses
Electric fuel and purchased energy expenses were as follows:
1995 1994 1993
- --------------------------------------------------------------------
(In millions)
Actual costs $554.5 $541.2 $483.9
Net recovery of costs
under electric fuel rate
clause (see Note 1) 24.3 1.1 50.7
- --------------------------------------------------------------------
Total expense $578.8 $542.3 $534.6
====================================================================
Total electric fuel and purchased energy expenses increased in 1995 as
a result of the operation of the electric fuel rate clause and increased
actual electric costs. Actual electric fuel and purchased energy costs
increased during 1995 primarily due to a higher net output of
electricity and higher purchased energy and capacity costs, offset
partially by a less costly generation mix resulting primarily from a
shorter refueling and maintenance outage at the Calvert Cliffs Nuclear
Power Plant as compared to the prior year.
Total electric fuel and purchased energy expenses increased in 1994 as
a result of increased actual electric costs and the operation of the
electric fuel rate clause. Actual electric fuel and purchased energy
costs increased during 1994 as a result of a more costly generation
mix and an increase in the net output of electricity generated to meet
the demand of BGE's system and the PJM system. The cost of the
generation mix increased due to higher purchased energy costs and
scheduled outages at the Calvert Cliffs Nuclear Power Plant in 1994.
Purchased gas expenses were as follows:
1995 1994 1993
- --------------------------------------------------------------------
(In millions)
Actual costs $205.9 $222.7 $246.4
Net (deferral) recovery of costs
under purchased gas adjustment
clause (see Note 1) (7.8) 1.9 (3.7)
- --------------------------------------------------------------------
Total expense $198.1 $224.6 $242.7
====================================================================
Total purchased gas expenses decreased in 1995 due to significantly
lower actual purchased gas costs and the operation of the purchased gas
adjustment clause. Actual purchased gas costs
26
Baltimore Gas and Electric Company and Subsidiaries
decreased in 1995 due to lower gas prices which reflect market
conditions. This decrease would have been greater except for a
take-or-pay refund which reduced actual costs in 1994.
Total purchased gas expenses decreased in 1994 due to significantly
lower actual purchased gas costs, offset partially by the operation
of the purchased gas adjustment clause. Actual purchased gas costs
decreased during 1994 for two reasons: lower gas prices and lower
output associated with the decreased demand for BGE gas. The lower gas
prices reflect market conditions and take-or-pay and other supplier
refunds, offset by higher costs related to the implementation of
Federal Energy Regulatory Commission (FERC) Order 636 and higher demand
charges.
Purchased gas costs exclude gas purchased by delivery service
customers, including Bethlehem Steel, who obtain gas directly from third
parties.
Other Operating Expenses
Operations and maintenance expenses were essentially unchanged in
1995 as compared to the prior year. Operations expense decreased
during 1994 primarily due to labor savings achieved as a result of the
Company's employee reduction programs discussed in Note 7 and
continuing cost control efforts. These savings offset $18.1 million of
expense from the amortization of the cost of the 1993 and 1992
Voluntary Special Early Retirement Programs (VSERP) and a $10.0 million
charge for a bonus paid to employees in lieu of a general wage
increase. In addition, operations expense for 1994 decreased because
operations expense for 1993 included a $17.2 million charge for certain
employee reduction programs, offset partially by a credit to expense
equivalent to the $9.8 million cost of termination benefits associated
with the Company's 1992 VSERP. Operations and maintenance expenses are
expected to decline in 1996 due to ongoing cost control efforts of the
Company. Maintenance expense decreased during 1994 due primarily to
lower costs at the Calvert Cliffs Nuclear Power Plant.
Depreciation and amortization expense increased during 1995 because
of higher levels of depreciable plant in service and energy
conservation program costs, and the completion of a facility-specific
study of the cost to decommission the Calvert Cliffs Nuclear Power
Plant. The higher level of depreciable plant in service, which is
primarily due to certain capital additions at the Calvert Cliffs
Nuclear Power Plant, resulted in an increase of approximately $12.9
million in depreciation and amortization expense during 1995.
The facility-specific study resulted in a $9 million increase in
depreciation expense. Depreciation and amortization expense increased
during 1994 because of higher levels of depreciable plant in service and
energy conservation program costs. The increase in depreciable plant
in service resulted from the addition of electric transmission and
distribution plant and certain capital additions at the Calvert Cliffs
Nuclear Power Plant during 1994. Additionally, as discussed below,
depreciation and amortization expense during 1995 and 1994 reflected the
write-off of certain Perryman costs.
Initially, BGE had planned to build two combined cycle generating
units at its Perryman site with each unit consisting of two combustion
turbines and a heat recovery steam generator. However, due to
significant changes in the environment in which utilities operate,
BGE decided in 1994 not to construct the second combined cycle unit
and wrote off the construction work in progress costs associated
with that unit. This write-off reduced after-tax earnings during 1994 by
$11.0 million or 7 cents per share. As a result of the PSC's August
1995 Order requiring all new generation capacity needs to be
competitively bid and BGE's September 1995 announcement that it will
merge with Potomac Electric Power Company (PEPCO) which has some
available generating capacity, BGE determined that it will not build
the second combustion turbine for the first combined cycle unit.
Therefore, during the third quarter of 1995, BGE wrote off the
remaining work in progress costs associated with the first combined
cycle unit. This write-off reduced after-tax earnings during 1995 by
$9.7 million, or 7 cents per share. The construction of the first
140-megawatt combustion turbine at Perryman was completed, and the unit
was placed in service, during June 1995.
Taxes other than income taxes increased slightly during 1995 and
1994 due primarily to higher property taxes resulting from higher levels
of utility plant in service.
Inflation affects the Company through increased operating expenses
and higher replacement costs for utility plant assets. Although timely
rate increases can lessen the effects of inflation, the regulatory
process imposes a time lag which can delay BGE's recovery of increased
costs. There is a regulatory lag primarily because rate increases are
based on historical costs rather than projected costs. The PSC has
historically allowed recovery of the cost of replacing plant assets,
together with the opportunity to earn a fair return on BGE's investment,
beginning at the time of replacement.
Other Income and Expenses
The allowance for equity funds used during construction (AFC)
decreased during 1995 because of a lower level of construction work in
progress resulting from a decrease in new construction activity and
the placement of several projects in service. AFC increased during
1994 because of a higher level of construction work in progress which
was offset partially by the lower AFC rate established by the PSC in the
April 1993 rate order.
27
Baltimore Gas and Electric Company and Subsidiaries
Net other income and deductions decreased in 1995 primarily due to
approximately $12.1 million in lower other interest and finance charge
income, and a decrease of $3.8 million in the gain on the sale of
receivables and property. Net other income and deductions increased
in 1994 primarily due to a lower level of charitable contributions
and $3.9 million of gains on the sale of receivables.
Interest expense increased during 1995 due to a combination of higher
levels of debt outstanding and higher short-term interest rates
compared to 1994, offset partially by increased capitalized interest
on the Constellation Companies' projects. Interest expense increased
slightly during 1994 due primarily to lower capitalized interest on the
Constellation Companies' power generation systems, offset partially by
the accrual by BGE of carrying charges on electric deferred fuel costs
excluded from rate base (see Note 5).
Income tax expense increased during 1995 and 1994 due to higher
taxable income from utility operations and the Constellation Companies.
Diversified Businesses Earnings
Earnings per share from diversified businesses were:
1995 1994 1993
- --------------------------------------------------------------------
Constellation Companies
Power generation systems $ .13 $ .10 $ .07
Financial investments .08 .03 .10
Real estate development and senior
living facilities (.02) (.03) (.04)
Effect of 1993 Tax Act - - (.04)
Other (.01) (.01) (.01)
- --------------------------------------------------------------------
Total Constellation Companies .18 .09 .08
BGE Home Products & Services, Inc.
and Subsidiary .00 .03 -
BGE Energy Projects & Services, Inc. .00 - -
- --------------------------------------------------------------------
Total diversified businesses $ .18 $ .12 $ .08
====================================================================
The Constellation Companies' power generation systems business
includes the development, ownership, management, and operation of
wholesale power generating projects in which the Constellation
Companies hold ownership interests, as well as the provision of services
to power generation projects under operation and maintenance
contracts. Power generation systems earnings increased during 1995 due
primarily to higher equity earnings on the Constellation Companies'
energy projects and a gain on the sale of certain operating and
maintenance contracts. Power generation systems earnings increased
in 1994 primarily due to payments for the curtailment of output at two
wholesale power generating projects as discussed below.
The Constellation Companies' investment in wholesale power generating
projects includes $197 million representing ownership interests in 16
projects which sell electricity in California under Interim Standard
Offer No. 4 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 next lowest cost generation to
service the demands on its system. These power generation projects
are scheduled to convert to supplying electricity at avoided
cost rates in various years beginning in late 1996 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. If current avoided cost levels were to continue
into 1996 and beyond, the Constellation Companies could experience
reduced earnings or incur losses associated with these projects,
which could be significant. 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, renegotiating
the power purchase agreements, restructuring financings, and selling
its ownership interests in the projects. Two of these wholesale power
generating projects, in which the Constellation Companies'
investment totals $30 million, have executed agreements with Pacific
Gas & Electric (PG&E) providing for the curtailment of output
through the end of the fixed price period in return for payments from
PG&E. The payments from PG&E during the curtailment period will be
sufficient to fully amortize the existing project finance debt.
However, following the curtailment period, the projects remain
contractually obligated to commence production of electricity at the
avoided cost rates, which could result in reduced earnings or losses for
the reasons described above. The Company cannot predict the impact
that these matters regarding any of the 16 projects may have
on the Constellation Companies or the Company, but the impact could be
material. See the section titled "Diversified Businesses" on page 13 for a
more recent update of these matters.
Earnings from the Constellation Companies' portfolio of financial
investments include capital gains and losses, dividends, income from
financial limited partnerships, and income from financial guaranty
insurance companies. Financial investment earnings were higher in
1995 due to favorable earnings on the Companies' marketable
securities, increased gains from financial partnerships, and higher
earnings from financial guaranty insurance companies. Financial
investment earnings decreased during 1994 due to reduced earnings
from the investment portfolio. Additionally, 1993 results reflected a
$6.1 million gain from the sale of a portion of an investment in a
financial guaranty insurance company.
The Constellation Companies' real estate development business
includes land under development; office buildings; retail pro-jects;
commercial projects; an entertainment, dining and retail complex in
Orlando, Florida; a mixed-use planned-unit-development; and senior
living facilities. The majority of these projects are in the
Baltimore-Washington corridor. They have been affected adversely by
the oversupply of and limited demand for land and office space due to
modest economic growth and corporate downsizings.
28
Baltimore Gas and Electric Company and Subsidiaries
Earnings from real estate development and senior living facilities in
1995 were essentially unchanged from the prior year. Earnings from real
estate development increased slightly during 1994 due to gains
recognized from the sale of two retail centers, an office building,
and interests in two senior living facilities. The increases in
diversified businesses' revenues and in selling, general, and
administrative expenses during 1994 reflect the proceeds of these sales
and the cost of the facilities sold, respectively.
The Constellation Companies' real estate portfolio has experienced
continuing carrying costs and depreciation. Additionally, the
Constellation Companies have been expensing rather than capitalizing
interest on certain undeveloped land for which substantially all
development activities have been suspended. These factors have
affected earnings negatively and are expected to continue to do so
until the levels of undeveloped land are reduced. Cash flow from
real estate operations has been insufficient to cover the debt
service requirements of certain of these projects. Resulting cash
shortfalls have been satisfied through cash infusions from
Constellation Holdings, Inc., which obtained the funds through a
combination of cash flow generated by other Constellation Companies
and its corporate borrowings. To the extent the real estate market
continues to improve, earnings from real estate activities are expected
to improve also.
The Constellation Companies' continued investment in real estate
projects is a function of market demand, interest rates, credit
availability, and the strength of the economy in general. The
Constellation Companies' Management believes that although the real
estate market has improved, until the economy reflects sustained
growth and the excess inventory in the market in the
Baltimore-Washington corridor goes down, real estate values will not
improve significantly. If the Constellation Companies were to sell
their real estate projects in the current depressed market, losses
would occur in amounts difficult to determine. Depending upon
market conditions, future sales could also result in losses. In
addition, were the Constellation Companies to change their intent
about any project from an intent to hold to an intent to sell,
applicable accounting rules would require a write-down of the project
to market value at the time of such change in intent if market value is
below book value.
BGE Home Products & Services' earnings decreased during 1995 and
increased during 1994 primarily due to higher gains from receivables
sales in 1994.
Environmental Matters
The Company is subject to increasingly stringent federal, state, and
local laws and regulations relating to improving or maintaining
the quality of the environment. These laws and regulations require
the Company to remove or remedy the effect on the environment of the
disposal or release of specified substances at ongoing and former
operating sites, including Environmental Protection Agency Superfund
sites. Details regarding these matters, including financial
information, are presented in Note 12 and in this Annual Report
on Form 10-K under Item 1. Business - Environmental Matters.
Liquidity and Capital Resources
Capital Requirements
The Company's capital requirements reflect the capital-intensive nature
of the utility business. Actual capital requirements for the years
1993 through 1995, along with estimated amounts for the years 1996
through 1998, are reflected below. Certain prior-year amounts have
been restated to conform with the current year's presentation.
1993 1994 1995 1996 1997 1998
(In millions)
Utility Business:
Construction expenditures (excluding AFC)
Electric $ 365 $345 $223 $231 $205 $212
Gas 52 68 70 68 73 67
Common 41 42 51 41 47 46
- ---------------------------------------------------------------------------------------------------------------------------
Total construction expenditures 458 455 344 340 325 325
AFC 23 34 22 11 10 10
Nuclear fuel (uranium purchases and processing charges) 47 42 46 45 45 44
Deferred energy conservation expenditures 33 41 46 34 25 27
Deferred nuclear expenditures 14 8 -- -- -- --
Retirement of long-term debt and redemption of preference stock 907 203 279 98 164 125
- ---------------------------------------------------------------------------------------------------------------------------
Total utility business 1,482 783 737 528 569 531
Diversified Businesses:
Retirement of long-term debt 222 37 55 49 135 138
Investment requirements 78 51 118 92 71 82
- ---------------------------------------------------------------------------------------------------------------------------
Total diversified businesses 300 88 173 141 206 220
Total $1,782 $871 $910 $669 $775 $751
===========================================================================================================================
29
Baltimore Gas and Electric Company and Subsidiaries
BGE Utility Capital Requirements
BGE's construction program is subject to continuous review and
modification, and actual expenditures may vary from the estimates
above. Electric construction expenditures include the installation
of a 5,000 kilowatt diesel generator at the Calvert Cliffs Nuclear
Power Plant which is scheduled to be placed in service in 1996, and
improvements in BGE's existing generating plants and its transmission
and distribution facilities. Future electric construction
expenditures do not include additional generating units.
During 1995, 1994, and 1993, the internal generation of cash from
utility operations provided 100%, 72%, and 71% respectively, of the
funds required for BGE's capital requirements exclusive of retirements
and redemptions of debt and preference stock. In addition, in 1994, $70
million of cash was provided by the sale of certain BGE and HP&S
receivables (see Note 12). During the three-year period 1996
through 1998, the Company expects to provide through utility
operations 115% of the funds required for BGE's capital requirements,
exclusive of retirements and redemptions.
Utility capital requirements not met through the internal generation of
cash are met through the issuance of debt and equity securities.
During the three-year period ended December 31, 1995, BGE's issuances
of long-term debt, preference stock, and common stock were $1,237
million, $190 million, and $92 million, respectively. During the
same period, retirements and redemptions of BGE's long-term debt
and preference stock totaled $1,148 million and $219 million,
respectively, exclusive of any redemption premiums or discounts. The
amount and timing of future issuances and redemptions will depend upon
market conditions and BGE's actual capital requirements.
BGE's fixed income securities are rated by various independent
credit rating agencies. The ratings assigned reflect the rating
agencies' current assessment of BGE's ability to pay interest,
dividends, and principal on these securities. The ratings impact BGE's
cost of raising fixed income capital in the public markets. At the
date of this Report, BGE's securities ratings were as follows:
Securities Ratings Table
- ---------------------------------------------------------------------------
Standard Moody's
& Poors Investors Duff & Phelps
Rating Group Service Credit Rating Co.
- ---------------------------------------------------------------------------
Senior Secured Debt A+ A1 AA-
(First Mortgage Bonds)
Unsecured Debt A A2 A+
Preferred Stock A "a1" A+
Preference Stock A "a2" A
The Constellation Companies' capital requirements are discussed
below in the section titled "Diversified Businesses Capital
Requirements-Debt and Liquidity." The Constellation Companies are
exploring expansion of their energy, real estate service, and senior
living facility businesses. Expansion may be achieved in a variety of
ways, including, without limitation, increased investment activity
and acquisitions. The Constellation Companies plan to meet their
capital requirements with a combination of debt and internal
generation of cash from their operations. Additionally, from time to
time, BGE may make loans to Constellation Holdings, Inc., or
contribute equity to enhance the capital structure of Constellation
Holdings, Inc.
Historically, Constellation's energy projects have been in the United
States. As of December 31, 1995, one of the Constellation
Companies had invested approximately $10 million in a Bolivian power
generation company. In addition, $10 million has been committed, of
which $1.2 million has been funded, to a fund that will invest in and
develop power projects in Latin America. Constellation's energy business
expansion may include domestic and international projects.
Diversified Businesses Capital Requirements
Debt and Liquidity
The Constellation Companies intend to meet capital requirements by
refinancing debt as it comes due and through internally generated
cash. These internal sources include cash that may be generated from
operations, sale of assets, and cash generated by tax benefits earned
by the Constellation Companies. In the event the Constellation
Companies can obtain reasonable value for real estate properties,
additional cash may become available through the sale of projects (for
additional information see the discussion of the real estate business
and market on pages 28 and 29). The ability of the Constellation Companies
to sell or liquidate assets described above will depend on market
conditions, and no assurances can be given that such sales or
liquidations can be made. Also, to provide additional liquidity to
meet interim financial needs, CHI has a $50 million revolving credit
agreement.
Investment Requirements
The investment requirements of the Constellation Companies include its
portion of equity funding to committed projects under development, as
well as net loans made to project partnerships. Investment requirements
for the years 1996 through 1998 reflect the Constellation Companies'
estimate of funding for ongoing and anticipated projects and are
subject to continuous review and modification. Actual investment
requirements may vary significantly from the estimates on page 29 because
of 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. The Constellation
Companies have met their investment requirements in the past through
the internal generation of cash and through borrowings from
institutional lenders.
30
Baltimore Gas and Electric Company and Subsidiaries
Response to Regulatory Change
Electric utilities presently face competition in the construction of generating
units to meet future load growth and in the sale of electricity in the bulk
power markets. Electric utilities also face the future prospect of competition
for electric sales to retail customers. As previously disclosed, BGE regularly
considered various strategies designed to enhance its competitive position and
to increase its ability to adapt to and anticipate regulatory changes in its
utility business. In September 1995, BGE concluded that a merger with PEPCO
would enhance two key factors regarding its competitive position--maintaining
low-cost production and increasing in size. The merger is discussed in Note 12.
Although BGE believes the merger will have a positive effect on its competitive
position in future years, it is not possible to predict currently the ultimate
effect competition will have on BGE's earnings in future years, or after the
merger, on the earnings of the new company. In response to the competitive
forces and regulatory changes, as discussed in Part 1 of BGE's Reports on Form
10-K under the headings Electric Regulatory Matters and Competition and Gas
Regulatory Matters and Competition, BGE (and after the merger the new company)
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, acquisitions of
related or unrelated businesses, business combinations, and additions to or
dispositions of portions of its franchised service territories. BGE may from
time to time be engaged in preliminary discussions, either internally or
with third parties, regarding one or more of these potential strategies. No
assurances can be given as to whether any potential transaction of the type
described above may actually occur, or as to the ultimate effect thereof on
the financial condition or competitive position of BGE.
31
Baltimore Gas and Electric Company and Subsidiaries
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT ACCOUNTANTS
To the Shareholders of
Baltimore Gas and Electric Company
We have audited the accompanying consolidated balance sheets and statements
of capitalization of Baltimore Gas and Electric Company and Subsidiaries as of
December 31, 1995 and 1994, and the related consolidated statements of income,
cash flows, common shareholders' equity, and income taxes for each of the three
years in the period ended December 31, 1995, and the consolidated financial
statement schedule listed in Item 14(a)(1) and (2) of this Form 10-K. These
financial statements and the financial statement schedule are the responsibility
of the Company's Management. Our responsibility is to express an opinion on
these financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
Management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Baltimore Gas
and Electric Company and Subsidiaries as of December 31, 1995 and 1994, and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 1995 in conformity with generally
accepted accounting principles. In addition, the consolidated financial
statement schedule referred to above, when considered in relation to the basic
consolidated financial statements taken as a whole, presents fairly, in all
material respects, the information required to be included therein.
We have also previously audited, in accordance with generally accepted
standards, the consolidated balance sheets and statements of capitalization at
December 31, 1993, 1992, and 1991, and the related consolidated statements of
income, cash flows, common shareholders' equity, and income taxes for each of
the two years in the period ended December 31, 1992 (none of which are presented
herein); and we expressed unqualified opinions on those consolidated financial
statements. In our opinion, the information set forth in the Summary of
Operations included in the Selected Financial Data for each of the five years in
the period ended December 31, 1995, appearing on page 23 is fairly stated in all
material respects in relation to the financial statements from which it has been
derived.
/s/ COOPERS & LYBRAND L.L.P.
COOPERS & LYBRAND L.L.P.
Baltimore, Maryland
January 19, 1996
32
Baltimore Gas and Electric Company and Subsidiaries
Consolidated Statements of Income
Year Ended December 31, 1995 1994 1993
- --------------------------------------------------------------------------------------------------------------------
(In thousands, except per share amounts)
Revenues
Electric $2,229,774 $2,126,581 $2,112,147
Gas 400,504 421,249 433,163
Diversified businesses 304,521 235,155 196,075
- --------------------------------------------------------------------------------------------------------------------
Total revenues 2,934,799 2,782,985 2,741,385
Expenses Other Than Interest and Income Taxes
Electric fuel and purchased energy 578,801 542,314 534,628
Gas purchased for resale 198,069 224,590 242,685
Operations 550,811 552,817 574,073
Maintenance 168,269 164,892 181,208
Diversified businesses - selling, general, and administrative 220,573 167,430 143,654
Depreciation and amortization 317,417 295,950 253,913
Taxes other than income taxes 205,167 199,733 194,832
- --------------------------------------------------------------------------------------------------------------------
Total expenses other than interest and income taxes 2,239,107 2,147,726 2,124,993
Income from Operations 695,692 635,259 616,392
- --------------------------------------------------------------------------------------------------------------------
Other Income
Allowance for equity funds used during construction 14,162 21,746 14,492
Equity in earnings of Safe Harbor Water Power Corporation 4,559 4,349 4,243
Net other income and deductions (9,902) 6,270 1,575
- --------------------------------------------------------------------------------------------------------------------
Total other income 8,819 32,365 20,310
Income Before Interest and Income Taxes 704,511 667,624 636,702
- --------------------------------------------------------------------------------------------------------------------
Interest Expense
Interest charges 219,689 214,347 212,971
Capitalized interest (15,050) (12,427) (16,167)
Allowance for borrowed funds used during construction (7,662) (11,766) (8,040)
- --------------------------------------------------------------------------------------------------------------------
Net interest expense 196,977 190,154 188,764
Income Before Income Taxes 507,534 477,470 447,938
Income Taxes 169,527 153,853 138,072
- --------------------------------------------------------------------------------------------------------------------
Net Income 338,007 323,617 309,866
Preferred and Preference Stock Dividends 40,578 39,922 41,839
- --------------------------------------------------------------------------------------------------------------------
Earnings Applicable to Common Stock $ 297,429 $ 283,695 $ 268,027
====================================================================================================================
Average Shares of Common Stock Outstanding 147,527 147,100 145,072
Earnings Per Share of Common Stock $2.02 $1.93 $1.85
====================================================================================================================
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the
current year's presentation.
33
Baltimore Gas and Electric Company and Subsidiaries
Consolidated Balance Sheets
At December 31, 1995 1994
- --------------------------------------------------------------------------------------------------------
(In thousands)
Assets
Current Assets
Cash and cash equivalents $ 23,443 $ 38,590
Accounts receivable (net of allowance for uncollectibles
of $16,390 and $14,960, respectively) 400,005 314,842
Fuel stocks 59,614 70,627
Materials and supplies 145,900 149,614
Prepaid taxes other than income taxes 60,508 57,740
Deferred income taxes 36,831 43,358
Trading securities 47,990 24,337
Other 31,487 22,686
- --------------------------------------------------------------------------------------------------------
Total current assets 805,778 721,794
Investments and Other Assets
Real estate projects 479,344 471,435
Power generation systems 358,629 311,960
Financial investments 205,841 224,340
Nuclear decommissioning trust fund 85,811 66,891
Safe Harbor Water Power Corporation 34,327 34,168
Senior living facilities 16,045 11,540
Net pension asset 60,077 ---
Other 71,894 58,824
- --------------------------------------------------------------------------------------------------------
Total investments and other assets 1,311,968 1,179,158
Utility Plant
Plant in service
Electric 6,360,624 5,929,996
Gas 692,693 616,823
Common 522,450 511,016
- --------------------------------------------------------------------------------------------------------
Total plant in service 7,575,767 7,057,835
Accumulated depreciation (2,481,801) (2,305,372)
- --------------------------------------------------------------------------------------------------------
Net plant in service 5,093,966 4,752,463
Construction work in progress 247,296 506,030
Nuclear fuel (net of amortization) 130,782 134,012
Plant held for future use 25,552 24,320
- --------------------------------------------------------------------------------------------------------
Net utility plant 5,497,596 5,416,825
Deferred Charges
Regulatory assets (net) 637,915 623,639
Other 63,406 96,086
- --------------------------------------------------------------------------------------------------------
Total deferred charges 701,321 719,725
Total Assets $8,316,663 $8,037,502
========================================================================================================
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the
current year's presentation.
34
Baltimore Gas and Electric Company and Subsidiaries
Consolidated Balance Sheets
At December 31, 1995 1994
- -------------------------------------------------------------------------------------------------------
(In thousands)
Liabilities and Capitalization
Current Liabilities
Short-term borrowings $ 279,305 $ 63,700
Current portions of long-term debt and preference stock 146,969 323,675
Accounts payable 177,092 181,931
Customer deposits 26,857 24,891
Accrued taxes 8,244 19,585
Accrued interest 56,670 60,348
Dividends declared 67,198 66,012
Accrued vacation costs 33,403 30,917
Other 39,417 30,857
- -------------------------------------------------------------------------------------------------------
Total current liabilities 835,155 801,916
Deferred Credits and Other Liabilities
Deferred income taxes 1,311,530 1,199,787
Pension and postemployment benefits 148,594 138,835
Decommissioning of federal uranium enrichment facilities 43,695 45,836
Other 55,568 59,645
- -------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 1,559,387 1,444,103
Capitalization
Long-term debt 2,598,254 2,584,932
Preferred stock 59,185 59,185
Redeemable preference stock 242,000 279,500
Preference stock not subject to mandatory redemption 210,000 150,000
Common shareholders' equity 2,812,682 2,717,866
- -------------------------------------------------------------------------------------------------------
Total capitalization 5,922,121 5,791,483
Commitments, Guarantees, and Contingencies - See Note 12
Total Liabilities and Capitalization $8,316,663 $8,037,502
=======================================================================================================
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the
current year's presentation.
35
Baltimore Gas and Electric Company and Subsidiaries
Consolidated Statements of Cash Flows
Year Ended December 31, 1995 1994 1993
- ---------------------------------------------------------------------------------------------------------------------------
(In thousands)
Cash Flows From Operating Activities
Net income $ 338,007 $ 323,617 $ 309,866
Adjustments to reconcile to net cash provided by operating activities
Depreciation and amortization 378,977 351,064 314,027
Deferred income taxes 103,494 79,278 53,057
Investment tax credit adjustments (8,088) (8,192) (8,444)
Deferred fuel costs 5,565 11,461 51,445
Accrued pension and postemployment benefits (7,641) (41,113) (25,276)
Allowance for equity funds used during construction (14,162) (21,746) (14,492)
Equity in earnings of affiliates and joint ventures (net) (21,259) (20,225) (4,655)
Changes in current assets other than sale of accounts receivable (107,392) (10,536) (37,252)
Changes in current liabilities, other than short-term borrowings (7,293) (24,447) 71,153
Other 2,837 13,070 (4,020)
- ---------------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 663,045 652,231 705,409
Cash Flows From Financing Activities
Proceeds from issuance of
Short-term borrowings (net) 215,605 63,700 (11,900)
Long-term debt 184,422 207,169 1,206,350
Preference stock 59,329 --- 128,776
Common stock 318 33,869 57,379
Proceeds from sale of receivables 2,000 70,000 ---
Reacquisition of long-term debt (315,105) (240,853) (1,012,514)
Redemption of preference stock (73,000) (4,406) (144,310)
Common stock dividends paid (227,192) (220,152) (211,137)
Preferred and preference stock dividends paid (40,087) (39,950) (42,425)
Other 13 (437) (7,094)
- ---------------------------------------------------------------------------------------------------------------------------
Net cash used in financing activities (193,697) (131,060) (36,875)
Cash Flows From Investing Activities
Utility construction expenditures (including AFC) (366,037) (488,976) (480,501)
Allowance for equity funds used during construction 14,162 21,746 14,492
Nuclear fuel expenditures (46,330) (42,089) (47,329)
Deferred nuclear expenditures --- (8,393) (13,791)
Deferred energy conservation expenditures (45,503) (40,440) (32,909)
Contributions to nuclear decommissioning trust fund (9,780) (9,780) (9,699)
Purchases of marketable equity securities (18,447) (52,099) (46,820)
Proceeds from sales of marketable equity securities 49,788 40,585 33,754
Other financial investments 9,423 2,469 19,589
Real estate projects (15,599) 14,926 (30,330)
Power generation systems (37,446) (1,116) (26,841)
Other (18,726) (3,650) 8,965
- ---------------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities (484,495) (566,817) (611,420)
Net Increase (Decrease) in Cash and Cash Equivalents (15,147) (45,646) 57,114
Cash and Cash Equivalents at Beginning of Year 38,590 84,236 27,122
- ---------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 23,443 $ 38,590 $ 84,236
===========================================================================================================================
Other Cash Flow Information
Cash paid during the year for:
Interest (net of amounts capitalized) $ 198,001 $ 184,441 $ 183,266
Income taxes $ 132,274 $ 112,923 $ 126,034
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the
current year's presentation.
36
Baltimore Gas and Electric Company and Subsidiaries
Consolidated Statements of Common Shareholders' Equity
Unrealized
Gain (Loss)
on Available Pension
Common Stock Retained For Sale Liability Total
Years Ended December 31, 1995, 1994, and 1993 Shares Amount Earnings Securities Adjustment Amount
- ---------------------------------------------------------------------------------------------------------------------------
(In thousands)
Balance at December 31, 1992 143,784 $1,335,002 $1,199,637 $ --- $ --- $2,534,639
Net income 309,866 309,866
Dividends declared
Preferred and preference stock (41,839) (41,839)
Common stock ($1.47 per share) (213,407) (213,407)
Common stock issued 2,250 57,379 57,379
Other (917) (3,117) (4,034)
Pension liability adjustment (33,990) (33,990)
Deferred taxes on pension liability adjustment 11,897 11,897
- ---------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1993 146,034 1,391,464 1,251,140 --- (22,093) 2,620,511
Net income 323,617 323,617
Dividends declared
Preferred and preference stock (39,922) (39,922)
Common stock ($1.51 per share) (222,180) (222,180)
Common stock issued 1,493 33,869 33,869
Other 45 45
Net unrealized loss on securities (5,609) (5,609)
Deferred taxes on net unrealized loss on securities 1,963 1,963
Pension liability adjustment 8,573 8,573
Deferred taxes on pension liability adjustment (3,001) (3,001)
- ---------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1994 147,527 1,425,378 1,312,655 (3,646) (16,521) 2,717,866
Net income 338,007 338,007
Dividends declared
Preferred and preference stock (40,578) (40,578)
Common stock ($1.55 per share) (228,667) (228,667)
Common stock issued 318 318
Other 109 109
Net unrealized gain on securities 14,010 14,010
Deferred taxes on net unrealized gain on securities (4,904) (4,904)
Pension liability adjustment 25,417 25,417
Deferred taxes on pension liability adjustment (8,896) (8,896)
- ---------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1995 147,527 $1,425,805 $1,381,417 $ 5,460 $ --- $2,812,682
===========================================================================================================================
See Notes to Consolidated Financial Statements.
37
Baltimore Gas and Electric Company and Subsidiaries
Consolidated Statements of Capitalization
At December 31, 1995 1994
- -----------------------------------------------------------------------------------------------------
(In thousands)
Long-Term Debt
First Refunding Mortgage Bonds of BGE
9-1/8% Series, due October l5, 1995 $ --- $ 188,014
5-1/8% Series, due April 15, 1996 26,187 26,454
6-1/8% Series, due August 1, 1997 24,935 24,935
Floating rate series, due April 15, 1999 125,000 125,000
8.40% Series, due October 15, 1999 91,200 96,225
5-1/2% Series, due July 15, 2000 125,000 125,000
8-3/8% Series, due August 15, 2001 122,427 122,430
7-1/8% Series, due January 1, 2002 39,698 49,957
7-1/4% Series, due July 1, 2002 124,609 124,850
5-1/2% Installment Series, due July 15, 2002 11,045 11,650
6-1/2% Series, due February 15, 2003 124,882 124,947
6-1/8% Series, due July 1, 2003 124,925 124,925
5-1/2% Series, due April 15, 2004 124,995 125,000
7-1/2% Series, due January 15, 2007 123,667 125,000
6-5/8% Series, due March 15, 2008 124,985 125,000
7-1/2% Series, due March 1, 2023 124,973 124,998
7-1/2% Series, due April 15, 2023 100,000 100,000
- -----------------------------------------------------------------------------------------------------
Total First Refunding Mortgage Bonds of BGE 1,538,528 1,744,385
Other long-term debt of BGE
Term bank loan due March 29, 2001 50,000 ---
Medium-term notes, Series A 10,500 10,500
Medium-term notes, Series B 100,000 100,000
Medium-term notes, Series C 200,000 173,050
Medium-term notes, Series D 28,000 ---
Pollution control loan, due July 1, 2011 36,000 36,000
Port facilities loan, due June 1, 2013 48,000 48,000
Adjustable rate pollution control loan, due July 1, 2014 20,000 20,000
5.55% Pollution control revenue refunding loan, due July 15, 2014 47,000 47,000
Economic development loan, due December 1, 2018 35,000 35,000
6.00% Pollution control revenue refunding loan, due April 1, 2024 75,000 75,000
- -----------------------------------------------------------------------------------------------------
Total other long-term debt of BGE 649,500 544,550
Long-term debt of Constellation Companies
Revolving credit agreement
Variable rates based on LIBOR, due December 9, 1998 1,000 ---
Mortgage and construction loans and other collateralized notes
7.6675%, due October 1, 1995 --- 13,000
7.50%, due October 9, 2005 9,989 ---
Variable rates, due through 2009 110,018 116,613
7.357%, due March 15, 2009 5,896 6,152
Unsecured notes 420,000 440,000
- -----------------------------------------------------------------------------------------------------
Total long-term debt of Constellation Companies 546,903 575,765
Unamortized discount and premium (15,708) (17,593)
Current portion of long-term debt (120,969) (262,175)
- -----------------------------------------------------------------------------------------------------
Total long-term debt $2,598,254 $2,584,932
continued on page 39
See Notes to Consolidated Financial Statements.
38
Baltimore Gas and Electric Company and Subsidiaries
Consolidated Statements of Capitalization
At December 31, 1995 1994
- -----------------------------------------------------------------------------------------------------------------------
(In thousands)
Preferred Stock
Cumulative, $100 par value, 1,000,000 shares authorized
Series B, 41/2%, 222,921 shares outstanding, callable at $110 per share $ 22,292 $ 22,292
Series C, 4%, 68,928 shares outstanding, callable at $105 per share 6,893 6,893
Series D, 5.40%, 300,000 shares outstanding, callable at $101 per share 30,000 30,000
- -----------------------------------------------------------------------------------------------------------------------
Total preferred stock 59,185 59,185
Preference Stock
Cumulative, $100 par value, 6,500,000 shares authorized
Redeemable preference stock
7.50%, 1986 Series, 425,000 and 455,000 shares outstanding. Callable
at $105 per share prior to October 1, 1996 and at lesser amounts thereafter 42,500 45,500
6.75%, 1987 Series, 455,000 shares outstanding. Callable at
$104.50 per share prior to April 1, 1997 and at lesser amounts thereafter 45,500 45,500
6.95%, 1987 Series, 500,000 shares redeemed at par on October 1, 1995 --- 50,000
7.80%, 1989 Series, 500,000 shares outstanding 50,000 50,000
8.25%, 1989 Series, 300,000 and 500,000 shares outstanding 30,000 50,000
8.625%, 1990 Series, 650,000 shares outstanding 65,000 65,000
7.85%, 1991 Series, 350,000 shares outstanding 35,000 35,000
Current portion of redeemable preference stock (26,000) (61,500)
- -----------------------------------------------------------------------------------------------------------------------
Total redeemable preference stock 242,000 279,500
Preference stock not subject to mandatory redemption
7.78%, 1973 Series, 200,000 shares outstanding, callable at $101 per share 20,000 20,000
7.125%, 1993 Series, 400,000 shares outstanding, not callable prior to July 1, 2003 40,000 40,000
6.97%, 1993 Series, 500,000 shares outstanding, not callable prior to October 1, 2003 50,000 50,000
6.70%, 1993 Series, 400,000 shares outstanding, not callable prior to January 1, 2004 40,000 40,000
6.99%, 1995 Series, 600,000 shares outstanding, not callable prior to October 1, 2005 60,000 ---
- -----------------------------------------------------------------------------------------------------------------------
Total preference stock not subject to mandatory redemption 210,000 150,000
Common Shareholders' Equity
Common stock without par value, 175,000,000 shares authorized; 147,527,114
shares issued and outstanding at December 31, 1995 and 1994. (At December
31, 1995, 166,893 shares were reserved for the Employee Savings Plan and
3,277,656 shares were reserved for the Dividend Reinvestment and Stock
Purchase Plan.) 1,425,805 1,425,378
Retained earnings 1,381,417 1,312,655
Unrealized gain (loss) on available for sale securities 5,460 (3,646)
Pension liability adjustment --- (16,521)
- -----------------------------------------------------------------------------------------------------------------------
Total common shareholders' equity 2,812,682 2,717,866
Total Capitalization $5,922,121 $5,791,483
=======================================================================================================================
See Notes to Consolidated Financial Statements.
39
Baltimore Gas and Electric Company and Subsidiaries
Consolidated Statements of Income Taxes
Year Ended December 31, 1995 1994 1993
- -------------------------------------------------------------------------------------------------------------------------
(Dollar amounts in thousands)
Income Taxes
Current $ 74,121 $ 82,767 $ 93,459
- -------------------------------------------------------------------------------------------------------------------------
Deferred
Change in tax effect of temporary differences 118,300 88,896 63,972
Change in income taxes recoverable through future rates (1,006) (8,580) (30,086)
Deferred taxes credited (charged) to shareholders' equity (13,800) (1,038) 11,897
- -------------------------------------------------------------------------------------------------------------------------
Deferred taxes charged to expense 103,494 79,278 45,783
Effect on deferred taxes of enacted change in federal corporate income tax rate
Increase in deferred tax liability --- --- 20,105
Income taxes recoverable through future rates --- --- (12,831)
- -------------------------------------------------------------------------------------------------------------------------
Deferred taxes charged to expense --- --- 7,274
Investment tax credit adjustments (8,088) (8,192) (8,444)
Income taxes per Consolidated Statements of Income $169,527 $153,853 $138,072
=========================================================================================================================
Reconciliation of Income Taxes Computed at Statutory
Federal Rate to Total Income Taxes
Income before income taxes $507,534 $477,470 $447,938
Statutory federal income tax rate 35% 35% 35%
- ---------------------------------------------------------------------------------------------------------------------------
Income taxes computed at statutory federal rate 177,637 167,115 156,778
Increases (decreases) in income taxes due to
Depreciation differences not normalized on regulated activities 10,953 9,791 9,253
Allowance for equity funds used during construction (4,957) (7,611) (5,072)
Amortization of deferred investment tax credits (8,088) (8,164) (8,444)
Tax credits flowed through to income (521) (1,754) (9,736)
Change in federal corporate income tax rate charged to expense --- --- 7,274
Amortization of deferred tax rate differential on regulated activities (2,013) (1,885) (5,789)
Other (3,484) (3,639) (6,192)
- ---------------------------------------------------------------------------------------------------------------------------
Total income taxes $169,527 $153,853 $138,072
===========================================================================================================================
Effective federal income tax rate 33.4% 32.2% 30.8%
At December 31, 1995 1994
- --------------------------------------------------------------------------------------------------------------------------
Deferred Income Taxes (Dollar amounts in thousands)
Deferred tax liabilities
Accelerated depreciation $ 878,470 $ 840,376
Allowance for funds used during construction 210,928 208,726
Income taxes recoverable through future rates 94,305 93,952
Deferred termination and postemployment costs 49,591 53,749
Deferred fuel costs 39,559 41,507
Leveraged leases 29,842 31,948
Percentage repair allowance 38,295 36,630
Energy conservation expenditures 28,121 ---
Other 151,231 148,064
- --------------------------------------------------------------------------------------------------------------------------
Total deferred tax liabilities 1,520,342 1,454,952
Deferred tax assets
Alternative minimum tax 32,626 71,074
Accrued pension and postemployment benefit costs 31,707 51,163
Deferred investment tax credits 49,512 52,288
Capitalized interest and overhead 39,439 34,071
Contributions in aid of construction 34,404 32,707
Nuclear decommissioning liability 16,708 14,870
Other 41,247 42,350
- --------------------------------------------------------------------------------------------------------------------------
Total deferred tax assets 245,643 298,523
Deferred tax liability, net $1,274,699 $1,156,429
==========================================================================================================================
See Notes to Consolidated Financial Statements.
40
Baltimore Gas and Electric Company and Subsidiaries
Notes to Consolidated Financial Statements
Note 1. Significant Accounting Policies
Nature of the Business
Baltimore Gas and Electric Company (BGE) and Subsidiaries (collectively,
the Company) is primarily an electric and gas utility serving a
territory which encompasses Baltimore City and all or part of ten
Central Maryland counties. The Company is also engaged in diversified
businesses as described further in Note 3.
Principles of Consolidation
The consolidated financial statements include the accounts of BGE
and all subsidiaries in which BGE owns directly or indirectly a
majority of the voting stock. Intercompany balances and
transactions have been eliminated in consolidation. Under this
policy, the accounts of Constellation Holdings, Inc. and its
subsidiaries (collectively, the Constellation Companies), BGE Home
Products & Services, Inc. and Subsidiary (HP&S), BGE Energy Projects &
Services, Inc. (EP&S), and BNG, Inc. are consolidated in the financial
statements, and Safe Harbor Water Power Corporation is reported under
the equity method. Corporate joint ventures, partnerships, and
affiliated companies in which a 20% to 50% voting interest is held
are accounted for under the equity method, unless control is
evident, in which case the entity is consolidated. Investments in
which less than a 20% voting interest is held are accounted for under
the cost method, unless significant influence is exercised over the
entity, in which case the investment is accounted for under the equity
method.
Regulation of Utility Operations
BGE's utility operations are subject to regulation by the Maryland
Public Service Commission (PSC). The accounting policies and
practices used in the determination of service rates are also generally
used for financial reporting purposes in accordance with generally
accepted accounting principles for regulated industries. See Note 5.
Utility Revenues
BGE recognizes utility revenues as service is rendered to customers.
Fuel and Purchased Energy Costs
Subject to the approval of the PSC, the cost of fuel used in
generating electricity, net of revenues from interchange sales, and
the cost of gas sold may be recovered through zero-based electric
fuel rate (see Note 12) and purchased gas adjustment clauses,
respectively. The difference between actual fuel costs and fuel
revenues is deferred on the balance sheet to be recovered from or
refunded to customers in future periods.
The electric fuel rate formula is based upon the latest
twenty-four-month generation mix and the latest three-month average
fuel cost for each generating unit. The fuel rate does not change unless
the calculated rate is more than 5% above or below the rate then in
effect. The purchased gas adjustment is based on recent annual volumes
of gas and the related current prices charged by BGE's gas suppliers.
Any deferred underrecoveries or overrecoveries of purchased gas costs
for the twelve months ended November 30 each year are charged or
credited to customers over the ensuing calendar year.
Income Taxes
The deferred tax liability represents the tax effect of temporary
differences between the financial statement and tax bases of assets and
liabilities. It is measured using presently enacted tax rates. The
portion of BGE's deferred tax liability applicable to utility
operations which has not been reflected in current service rates
represents income taxes recoverable through future rates. It has been
recorded as a regulatory asset on the balance sheet. Deferred income tax
expense represents the net change in the deferred tax liability
and regulatory asset during the year, exclusive of amounts charged or
credited to common shareholders' equity.
Current tax expense consists solely of regular tax less applicable tax
credits. In certain prior years, tax expense included an alternative
minimum tax (AMT) that can be carried forward indefinitely as tax
credits to future years in which the regular tax liability exceeds the
AMT liability. Current income tax for the year ended December 31, 1995
reflects utilization of AMT credits of $40 million. Deferred income
taxes related to the remaining AMT credit carryforward of $33 million
have been classified as current assets at December 31, 1995. Prior-year
amounts have been reclassified to conform with the current year's
presentation.
The investment tax credit (ITC) associated with BGE's regulated
utility operations has been deferred (see Note 5) and is amortized to
income ratably over the lives of the subject property. ITC and other
tax credits associated with nonregulated diversified businesses other
than leveraged leases are flowed through to income.
BGE's utility revenue from system sales is subject to the Maryland
public service company franchise tax in lieu of a state income tax.
The franchise tax is included in taxes other than income taxes in the
Consolidated Statements of Income.
Inventory Valuation
Fuel stocks and materials and supplies are generally stated at average cost.
Real Estate Projects
Real estate projects consist of the Constellation Companies'
investment in rental and operating properties and properties under
development. Rental and operating properties are held for investment.
Properties under development are held for future development and sale.
Costs incurred in the acquisition and active development of such
properties are capitalized. Rental and operating properties and
properties under development are stated at cost unless the amount
invested exceeds the amounts expected to be recovered through
operations and sales. In these cases, the projects are written down to
the amount estimated to be recoverable.
41
Baltimore Gas and Electric Company and Subsidiaries
Investments and Other Assets
Investments in debt and equity securities subject to the
requirements of Statement of Financial Accounting Standards No. 115
(Statement No. 115) are reported at fair value. Certain of
Constellation Companies' marketable equity securities and financial
partnerships are classified as trading securities. Unrealized gains
and losses on these securities are included in diversified
businesses revenues. The investments comprising the nuclear
decommissioning trust fund and certain marketable equity securities
of CHI are classified as available for sale. Unrealized gains and
losses on these securities, as well as CHI's portion of unrealized
gains and losses on securities of equity-method investees, are
recorded in shareholders' equity. The Company utilizes specific
identification to determine the cost of these securities in computing
realized gains or losses.
Utility Plant, Depreciation and Amortization, and Decommissioning
Utility plant is stated at original cost, which includes material,
labor, and, where applicable, construction overhead costs and an
allowance for funds used during construction. Additions to utility
plant and replacements of units of property are capitalized to
utility plant accounts. Utility plant retired or otherwise disposed
of is charged to accumulated depreciation. Maintenance and repairs of
property and replacements of items of property determined to be less
than a unit of property are charged to maintenance expense.
Depreciation is generally computed using composite straight-line rates
applied to the average investment in classes of depreciable
property. Vehicles are depreciated based on their estimated useful
lives. As a result of the PSC's November 1995 gas rate order, BGE
revised its gas utility plant depreciation rates to reflect the
results of a detailed depreciation study. The new rates are expected to
result in an increase in depreciation accruals of approximately $2.4
million annually.
Depreciation expense for 1995 and 1994 includes the write-off of
certain costs at BGE's Perryman site. Initially, BGE had planned to
build two combined cycle generating units at its Perryman site
with each unit consisting of two combustion turbines. However, due
to significant changes in the environment in which utilities operate,
BGE decided in 1994 not to construct the second combined cycle
generating unit and wrote off the construction work in progress costs
associated with that unit. This write-off reduced after-tax
earnings during 1994 by $11.0 million or 7 cents per share. As a
result of the PSC's August 1995 Order requiring all new
generation capacity needs to be competitively bid and BGE's
September 1995 announcement that it will merge with Potomac Electric
Power Company (PEPCO), BGE determined that it will not build the
second combustion turbine for the first combined cycle unit.
Therefore, during the third quarter of 1995, BGE wrote off the remaining
construction work in progress costs associated with the first combined
cycle unit. This write-off reduced after-tax earnings during 1995 by
$9.7 million, or 7 cents per share. The construction of the first
140-megawatt combustion turbine at Perryman was completed, and the
unit was placed in service, during June 1995.
BGE owns an undivided interest in the Keystone and Conemaugh electric
generating plants located in western Pennsylvania, as well as in the
transmission line which transports the plants' output to the joint
owners' service territories. BGE's ownership interest in these
plants is 20.99% and 10.56%, respectively, and represents a net
investment of $150 million as of December 31, 1995. Financing and
accounting for these properties are the same as for wholly owned
utility plant.
Nuclear fuel expenditures are amortized as a component of actual
fuel costs based on the energy produced over the life of the fuel.
Fees for the future disposal of spent fuel are paid quarterly to the
Department of Energy and are accrued based on the kilowatt-hours of
electricity sold. Nuclear fuel expenses are subject to recovery through
the electric fuel rate.
Nuclear decommissioning costs are accrued by and recovered through a
sinking fund methodology. In a 1995 order, the PSC authorized
BGE to record decommissioning expense based on a facility-specific
cost estimate in order to accumulate a decommissioning reserve of $521
million in 1993 dollars by the end of Calvert Cliffs' service life in
2016, adjusted to reflect expected inflation, to decommission the
radioactive portion of the plant. The total decommissioning reserve of
$136.7 million and $109.8 million at December 31, 1995 and 1994,
respectively, is included in accumulated depreciation in the
Consolidated Balance Sheets.
In accordance with Nuclear Regulatory Commission (NRC) regulations,
BGE has established an external decommissioning trust to which a
portion of accrued decommissioning costs have been contributed. The
NRC requires utilities to provide financial assurance that they
will accumulate sufficient funds to pay for the cost of nuclear
decommissioning based upon either a generic NRC formula or a
facility-specific decommissioning cost estimate. The Company plans to
use the facility-specific cost estimate for funding these costs and
providing the requisite financial assurance.
Allowance for Funds Used During Construction and Capitalized Interest
The allowance for funds used during construction (AFC) is an
accounting procedure which capitalizes the cost of funds used
to finance utility construction projects as part of utility plant on
the balance sheet, crediting the cost as a noncash item on the income
statement. The cost of borrowed and equity funds is segregated
between interest expense and other income, respectively. BGE
recovers the capitalized AFC and a return thereon after the related
utility plant is placed in service and included in depreciable assets
and rate base.
Prior to April 23, 1993, the Company accrued AFC at a pre-tax rate
of 9.94%. Effective April 24, 1993, a rate order of the PSC reduced
the pre-tax AFC rate to 9.40%. Effective November 20, 1995, a rate
order of the PSC reduced the pre-tax gas plant and common plant AFC
rates to 9.04% and 9.36%, respectively. AFC is compounded annually.
The Constellation Companies capitalize interest on qualifying real
estate and power generation development projects. BGE capitalizes
interest on carrying charges accrued on certain deferred fuel costs as
discussed in Note 5.
42
Baltimore Gas and Electric Company and Subsidiaries
Long-Term Debt
The discount or premium and expense of issuance associated with
long-term debt are deferred and amortized over the original lives
of the respective debt issues. Gains and losses on the reacquisition
of debt are amortized over the remaining original lives of the
issuances.
Cash Flows
For the purpose of reporting cash flows, highly liquid investments
purchased with a maturity of three months or less are considered to be
cash equivalents.
Use of Accounting Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities
and disclosure of contingent assets and liabilities at the date of the
financial statements and the reported amounts of revenues and
expenses during the reporting period. These estimates involve judgments
with respect to, among other things, various future economic factors
which are difficult to predict and are beyond the control of the
Company. Therefore, actual amounts could differ from these estimates.
Accounting Standards Issued
The Financial Accounting Standards Board has issued Statement of
Financial Accounting Standards No. 121, regarding accounting for
asset impairments, effective January 1, 1996. Adoption of this
statement is not expected to have a material impact on the Company's
financial statements.
Note 2. Segment Information
1995 1994 1993
- --------------------------------------------------------------------------------------------------------
(In thousands)
Electric
Nonaffiliated revenues $2,229,774 $2,126,581 $2,112,147
Affiliated revenues 1,337 840 ---
- --------------------------------------------------------------------------------------------------------
Total revenues 2,231,111 2,127,421 2,112,147
Income from operations 574,299 539,739 534,185
Depreciation and amortization 276,285 252,273 219,735
Construction expenditures (including AFC) 288,509 412,885 421,923
Identifiable assets at December 31 6,195,722 5,981,634 5,867,725
Gas
Total revenues (nonaffiliated) $ 400,504 $ 421,249 $ 433,163
Income from operations 48,104 27,801 34,738
Depreciation and amortization 29,637 32,478 23,875
Construction expenditures (including AFC) 77,528 76,091 58,578
Identifiable assets at December 31 748,462 726,759 677,857
Diversified Businesses
Nonaffiliated revenues $ 304,521 $ 235,155 $ 196,075
Affiliated revenues 6,609 8,245 6,825
- --------------------------------------------------------------------------------------------------------
Total revenues 311,130 243,400 202,900
Income from operations 73,289 67,719 47,469
Depreciation and amortization 11,495 11,199 10,303
Identifiable assets at December 31 1,266,049 1,200,551 1,166,997
Total
Nonaffiliated revenues $2,934,799 $2,782,985 $2,741,385
Affiliated revenues 7,946 9,085 6,825
Intercompany eliminations (7,946) (9,085) (6,825)
- --------------------------------------------------------------------------------------------------------
Total revenues 2,934,799 2,782,985 2,741,385
Income from operations 695,692 635,259 616,392
Depreciation and amortization 317,417 295,950 253,913
Construction expenditures (including AFC) 366,037 488,976 480,501
Identifiable assets at December 31 8,210,233 7,908,944 7,712,579
Other assets at December 31 106,430 128,558 117,034
- --------------------------------------------------------------------------------------------------------
Total assets at December 31 8,316,663 8,037,502 7,829,613
Certain prior-year amounts have been reclassified to conform with the
current year's presentation.
43
Baltimore Gas and Electric Company and Subsidiaries
Note 3. Subsidiary Information
Diversified businesses consist of the operations of the Constellation
Companies, HP&S, EP&S, and BNG, Inc.
The Constellation Companies include Constellation Holdings, Inc., a
wholly owned subsidiary which holds all of the stock of three
other subsidiaries, Constellation Real Estate Group, Inc.,
Constellation Power, Inc. (formerly "Constellation Energy, Inc."),
and Constellation Investments, Inc. These companies are engaged in
real estate development and ownership of senior living facilities;
development, ownership, and operation of power generation systems; and
financial investments, respectively.
HP&S is a wholly owned subsidiary which engages predominantly in the
businesses of appliance and consumer electronics sales and service;
heating, ventilation, and air conditioning system sales, installation
and service; as well as, home improvements and services, primarily in
Central Maryland.
Effective November 1, 1995, BGE formed a wholly owned subsidiary,
EP&S, which provides a broad range of customized energy services to
major customers, including industrial, institutional, and government
customers in commercial office buildings, warehouses, educational,
healthcare, and retail facilities. These energy services include
customer electrical system improvements, lighting and mechanical
engineering services, campus and multi-building systems, brokering and
associated financial contracts, and district chilled water systems.
BNG, Inc. is a wholly owned subsidiary which engages
in natural gas brokering.
BGE's investment in Safe Harbor Water Power Corporation, a
producer of hydroelectric power, represents two-thirds of Safe Harbor's
total capital stock, including one-half of the voting stock, and a
two-thirds interest in its retained earnings.
The following is condensed financial information for Constellation
Holdings, Inc. and its subsidiaries. The condensed financial
information does not reflect the elimination of intercompany balances or
transactions which are eliminated in the Company's consolidated
financial statements.
1995 1994 1993
(In thousands, except per share amounts)
Income Statements
Revenues
Real estate projects $ 108,414 $ 106,915 $ 77,598
Power generation systems 57,734 41,301 24,971
Financial investments 25,201 12,126 21,195
- ------------------------------------------------------------------------------------------------------------
Total revenues 191,349 160,342 123,764
Expenses other than interest and income taxes 114,479 107,267 80,427
- ------------------------------------------------------------------------------------------------------------
Income from operations 76,870 53,075 43,337
Minority interest (2,348) --- (280)
Interest expense (46,673) (45,782) (47,845)
Capitalized interest 13,582 10,776 14,702
Income tax benefit (expense) (14,355) (4,305) 1,984
- ------------------------------------------------------------------------------------------------------------
Net income $ 27,076 $ 13,764 $ 11,898
============================================================================================================
Contribution to the Company's earnings per share of common stock $ .18 $ .09 $ .08
============================================================================================================
Balance Sheets
Current assets $ 98,526 $ 92,814 $ 54,039
Noncurrent assets 1,102,528 1,055,056 1,036,507
- ------------------------------------------------------------------------------------------------------------
Total assets $1,201,054 $1,147,870 $1,090,546
Current liabilities $ 70,393 $ 70,670 $ 24,201
Noncurrent liabilities 778,505 758,626 759,048
Shareholder's equity 352,156 318,574 307,297
- ------------------------------------------------------------------------------------------------------------
Total liabilities and shareholder's equity $1,201,054 $1,147,870 $1,090,546
============================================================================================================
44
Baltimore Gas and Electric Company and Subsidiaries
Note 4. Real Estate Projects and Financial Investments
Real estate projects consist of the following investments held by the
Constellation Companies:
At December 31, 1995 1994
- --------------------------------------------------------------------
(In thousands)
Properties under development $270,678 $267,483
Rental and operating properties
(net of accumulated
depreciation) 207,666 203,000
Other real estate ventures 1,000 952
- --------------------------------------------------------------------
Total $479,344 $471,435
====================================================================
Financial investments consist of the following investments held
by the Constellation Companies:
At December 31, 1995 1994
- --------------------------------------------------------------------
(In thousands)
Insurance companies $ 77,792 $ 87,700
Marketable equity securities 41,475 51,175
Financial limited partnerships 51,023 48,014
Leveraged leases 35,551 37,451
- --------------------------------------------------------------------
Total $205,841 $224,340
====================================================================
The Constellation Companies' marketable equity securities and BGE's
investments comprising the nuclear decommissioning trust fund are
classified as available for sale. The fair values, gross unrealized
gains and losses, and amortized cost bases for available for sale
securities, exclusive of $3.2 million of unrealized net gains on
securities of equity-method investees, are as follows:
Amortized Unrealized Unrealized Fair
At December 31, 1995 Cost Basis Gains Losses Value
- ---------------------------------------------------------------------------
(In thousands)
Marketable equity
securities $ 38,520 $2,998 $ (43) $ 41,475
U.S. government
agency 14,177 141 --- 14,318
State municipal
bonds 50,411 2,056 (74) 52,393
- ---------------------------------------------------------------------------
Total $103,108 $5,195 $ (117) $108,186
===========================================================================
Amortized Unrealized Unrealized Fair
At December 31, 1994 Cost Basis Gains Losses Value
- ---------------------------------------------------------------------------
(In thousands)
Marketable equity
securities $ 51,758 $1,276 $(1,859) $ 51,175
U.S. government
agency 5,215 --- (113) 5,102
State municipal
bonds 59,704 929 (2,599) 58,034
- ---------------------------------------------------------------------------
Total $116,677 $2,205 $(4,571) $114,311
===========================================================================
Gross and net realized gains and losses on available for sale securities
were as follows:
1995 1994 1993
- ---------------------------------------------------------------------------
(In thousands)
Gross realized gains $5,470 $ 1,108 $2,437
Gross realized losses (2,446) (3,150) (1,389)
- ---------------------------------------------------------------------------
Net realized gains (losses) $3,024 $(2,042) $1,048
===========================================================================
Contractual maturities of debt securities:
Amount
- ---------------------------------------------------------------------------
(In thousands)
Less than 1 year $ ---
1-5 years 10,975
5-10 years 52,920
More than 10 years 4,850
- ---------------------------------------------------------------------------
Total $68,745
===========================================================================
Note 5. Regulatory Assets (net)
As discussed in Note 1, BGE's utility operations are subject to
regulation by the PSC. Except for differences in the timing of the
recognition of certain utility expenses and credits, the
ratemaking process utilized by the PSC generally is based upon the
same accounting principles applied by nonregulated entities. Under the
PSC's ratemaking process, these utility expenses and credits are
deferred on the balance sheet as regulatory assets and liabilities and
are recognized in income as the related amounts are included in
service rates and recovered from or refunded to customers in utility
revenues. The following table sets forth BGE's regulatory assets and
liabilities:
At December 31, 1995 1994
- --------------------------------------------------------------------
(In thousands)
Income taxes recoverable
through future rates $269,442 $268,436
Deferred fuel costs 113,026 118,591
Deferred nuclear expenditures 86,519 90,937
Deferred postemployment benefit costs 81,616 73,591
Deferred energy conservation
expenditures 73,297 45,534
Deferred termination benefit costs 60,073 79,979
Deferred cost of
decommissioning federal
uranium enrichment facilities 51,104 52,748
Deferred environmental costs 38,371 35,015
Deferred investment tax credits (141,463) (149,394)
Other 5,930 8,202
- --------------------------------------------------------------------
Total $637,915 $623,639
====================================================================
45
Baltimore Gas and Electric Company and Subsidiaries
Income taxes recoverable through future rates represent principally
the tax effect of depreciation differences not normalized and the
allowance for equity funds used during construction, offset by
unamortized deferred tax rate differentials and deferred taxes on
deferred ITC. These amounts are amortized as the related temporary
differences reverse. See Note 1 for a further discussion of income
taxes.
Deferred fuel costs represent the difference between actual fuel costs
and the fuel rate revenues under BGE's fuel clauses (see Note 1).
Deferred fuel costs are reduced as they are collected from customers.
The underrecovered costs deferred under the fuel clauses were as
follows:
At December 31, 1995 1994
- --------------------------------------------------------------------
(In thousands)
Electric
Costs deferred $130,399 $152,815
Reserve for possible
disallowance of replacement
energy costs (see Note 12) (35,000) (35,000)
- --------------------------------------------------------------------
Net electric 95,399 117,815
Gas 17,627 776
- --------------------------------------------------------------------
Total $113,026 $118,591
====================================================================
Deferred nuclear expenditures represent the net unamortized balance of
certain operations and maintenance costs which are being amortized
over the remaining life of the Calvert Cliffs Nuclear Power Plant in
accordance with orders of the PSC. These expenditures consist of
costs incurred from 1979 through 1982 for inspecting and repairing
seismic pipe supports, expenditures incurred from 1989 through 1994
associated with nonrecurring phases of certain nuclear operations
projects, and expenditures incurred during 1990 for investigating
leaks in the pressurizer heater sleeves.
Deferred postemployment benefit costs represent the excess of
such costs recognized in accordance with Statements of Financial
Accounting Standards No. 106 and No. 112 over the amounts reflected in
utility rates. These costs will be amortized over a 15-year period
beginning in 1998 (see Note 6).
Deferred energy conservation expenditures represent the net unamortized
balance of certain operations costs which are being amortized
over five years in accordance with orders of the PSC. These
expenditures consist of labor, materials, and indirect costs
associated with the conservation programs approved by the PSC.
Deferred termination benefit costs represent the net unamortized
balance of the cost of certain termination benefits (see Note 7)
applicable to BGE's regulated operations. These costs are being
amortized over a five-year period in accordance with rate actions
of the PSC.
Deferred cost of decommissioning federal uranium enrichment
facilities represents the unamortized portion of BGE's required
contributions to a fund for decommissioning and decontaminating the
Department of Energy's (DOE) uranium enrichment facilities. The Energy
Policy Act of 1992 requires domestic utilities to make such
contributions, which are generally payable over a 15-year period with
escalation for inflation and are based upon the amount of uranium
enriched by DOE for each utility. These costs are being amortized over
the contribution period as a cost of fuel.
Deferred environmental costs represent the estimated costs of
investigating contamination and performing certain remediation
activities at contaminated Company-owned sites (see Note 12). In
November 1995, the PSC issued a rate order in the Company's gas base
rate proceeding which authorized the Company to amortize over a
10-year period $21.6 million of these costs, the amount which had
been incurred through October 1995.
Deferred investment tax credits represents investment tax credits
associated with BGE's regulated utility operations as discussed in Note
1. Previously, the Company reported deferred investment tax credits
on the Consolidated Balance Sheets as Deferred Credits and Other
Liabilities. In 1995, the Company reclassified those credits as a
reduction of Regulatory Assets because they are deferred solely
because of the regulatory treatment. Prior year amounts have been
reclassified to conform with the current year's presentation.
Electric deferred fuel costs in excess of $72.8 million are excluded
from rate base by the PSC for ratemaking purposes. Effective April 24,
1993, BGE has been authorized by the PSC to accrue carrying charges
on deferred fuel costs in excess of $72.8 million, net of related
deferred income taxes. These carrying charges are accrued
prospectively at the 9.40% authorized rate of return. The income
effect of the equity funds portion of the carrying charges is being
deferred until such amounts are recovered in utility service rates
subsequent to the completion of the fuel rate proceeding examining the
1989-1991 outages at Calvert Cliffs Nuclear Power Plant as discussed in
Note 12. Deferred investment tax credits are not deducted from rate
base in accordance with federal income tax normalization requirements.
The foregoing regulatory assets and liabilities are recorded
on BGE's Consolidated Balance Sheets in accordance with Statement of
Financial Accounting Standards (SFAS) No. 71. If BGE were required to
terminate application of SFAS No. 71 for all of its regulated
operations, all such amounts deferred would be recognized in the
income statement at that time, resulting in a charge to earnings,
net of applicable income taxes.
46
Baltimore Gas and Electric Company and Subsidiaries
Note 6. Pension and Postemployment Benefits
Pension Benefits
The Company sponsors several noncontributory defined benefit pension
plans, the largest of which (the Pension Plan) covers substantially
all BGE employees and certain employees of its subsidiaries. The other
plans, which are not material in amount, provide supplemental benefits
to certain non-employee directors and key employees. Benefits under
the plans are generally based on age, years of service, and
compensation levels.
Prior service cost associated with retroactive plan amendments is
amortized on a straight-line basis over the average remaining
service period of active employees.
The Company's funding policy is to contribute at least the minimum
amount required under Internal Revenue Service regulations using the
projected unit credit cost method. Plan assets at December 31, 1995
consisted primarily of marketable equity and fixed income securities,
and group annuity contracts.
The following tables set forth the combined funded status of the plans
and the composition of total net pension cost. At December 31, 1994,
the accumulated benefit obligation was greater than the fair
value of the Pension Plan's assets. As a result, the Company recorded
an additional pension liability, a portion of which was charged to
shareholders' equity.
Net pension cost shown below does not include the cost of termination
benefits described in Note 7.
At December 31, 1995 1994
(In thousands)
Vested benefit obligation $688,084 $622,445
Nonvested benefit obligation 15,668 8,838
- ----------------------------------------------------------------------------------------------------
Accumulated benefit obligation 703,752 631,283
Projected benefits related to increase in future compensation levels 122,539 82,815
- ----------------------------------------------------------------------------------------------------
Projected benefit obligation 826,291 714,098
Plan assets at fair value (744,645) (614,284)
- ----------------------------------------------------------------------------------------------------
Projected benefit obligation less plan assets 81,646 99,814
Unrecognized prior service cost (24,357) (23,863)
Unrecognized net loss (118,361) (112,546)
Pension liability adjustment --- 52,177
Unamortized net asset from adoption of FASB Statement No. 87 995 1,586
- ----------------------------------------------------------------------------------------------------
Accrued pension (asset) liability $ (60,077) $ 17,168
====================================================================================================
Year Ended December 31, 1995 1994 1993
- -------------------------------------------------------------------------------------------------------------------
(In thousands)
Components of net pension cost
Service cost-benefits earned during the period $11,407 $15,015 $11,645
Interest cost on projected benefit obligation 58,433 58,723 51,183
Actual return on plan assets (150,510) 7,932 (56,225)
Net amortization and deferral 94,674 (60,071) 6,591
- -------------------------------------------------------------------------------------------------------------------
Total net pension cost 14,004 21,599 13,194
Amount capitalized as construction cost (1,422) (2,578) (1,800)
- -------------------------------------------------------------------------------------------------------------------
Amount charged to expense $12,582 $19,021 $11,394
===================================================================================================================
The Company also sponsors a defined contribution savings plan
covering all eligible BGE employees and certain employees of its
subsidiaries. Under this plan, the Company makes contributions on
behalf of participants. Company contributions to this plan totaled
$8.5 million, $8.7 million, and $9.0 million in 1995, 1994, and 1993,
respectively.
Postretirement Benefits
The Company sponsors defined benefit postretirement health care
and life insurance plans which cover substantially all BGE
employees and certain employees of its subsidiaries. Benefits under
the plans are generally based on age, years of service, and pension
benefit levels. The postretirement benefit (PRB) plans are unfunded.
Substantially all of the health care plans are contributory, and
participant contributions for employees who retire after June 30, 1992
are based on age and years of service. Retiree contributions increase
commensurate with the expected increase in medical costs. The
postretirement life insurance plan is noncontributory.
Effective January 1, 1993, the Company adopted Statement of Financial
Accounting Standards No. 106, which requires a change in the method
of accounting for postretirement benefits other than pensions from
the pay-as-you-go method used prior to 1993 to the accrual method. The
transition obligation existing at the beginning of 1993 is being
amortized over a 20-year period.
47
Baltimore Gas and Electric Company and Subsidiaries
In April 1993, the PSC issued a rate order authorizing BGE to
recognize in operating expense one-half of the annual increase in
PRB costs applicable to regulated operations as a result of the
adoption of Statement No. 106 and to defer the remainder of the annual
increase in these costs for inclusion in BGE's next base rate
proceeding. In accordance with the April 1993 Order, the increase in
annual PRB costs applicable to regulated operations for the period
January through April 1993, net of amounts capitalized as construction
cost, has been deferred. This amount, which totaled $5.7 million, as
well as all amounts to be deferred prior to completion of BGE's next
base rate proceeding, will be amortized over a 15-year period
beginning in 1998 in accordance with the PSC's Order. In November 1995,
the PSC issued a rate order in BGE's gas base rate proceeding
providing for full recognition in operating expense of PRB and other
postemployment benefits (discussed below) costs attributable to gas
operations, and affirming its previous decision on amortization of
deferred PRB costs. This phase-in approach meets the guidelines
established by the Emerging Issues Task Force of the Financial
Accounting Standards Board for deferring PRB costs as a regulatory
asset. Accrual-basis PRB costs applicable to nonregulated operations are
charged to expense.
The following table sets forth the components of the accumulated PRB
obligation and a reconciliation of these amounts to the accrued PRB
liability.
At December 31, 1995 1994
Life Life
Health Care Insurance Health Care Insurance
(In thousands)
Accumulated postretirement benefit obligation:
Retirees $157,804 $44,769 $161,134 $45,146
Fully eligible active employees 20,942 84 15,777 101
Other active employees 63,782 18,515 44,371 12,597
- ---------------------------------------------------------------------------------------------------------------------------
Total accumulated postretirement benefit obligation 242,528 63,368 221,282 57,844
Unrecognized transition obligation (149,907) (43,521) (158,725) (46,081)
Unrecognized net gain (loss) (12,767) (5,764) 1,238 (2,141)
- ---------------------------------------------------------------------------------------------------------------------------
Accrued postretirement benefit liability $ 79,854 $ 14,083 $ 63,795 $ 9,622
===========================================================================================================================
The following table sets forth the composition of net PRB cost. Such
cost does not include the cost of termination benefits described in Note
7.
Year ended December 31, 1995 1994
- ------------------------------------------------------------------------
(In thousands)
Net postretirement benefit cost:
Service cost--benefits earned during
the period $ 3,918 $ 5,035
Interest cost on accumulated post-
retirement benefit obligation 21,203 23,037
Amortization of transition obligation 11,378 11,700
Net amortization and deferral (86) 646
- ------------------------------------------------------------------------
Total net postretirement benefit cost 36,413 40,418
Amount capitalized as construction cost (5,299) (5,773)
Amount deferred (8,025) (10,213)
- ------------------------------------------------------------------------
Amount charged to expense $23,089 $24,432
========================================================================
Other Postemployment Benefits
The Company provides health and life insurance benefits to employees of
BGE and certain employees of its subsidiaries who are determined to
be disabled under BGE's Disability Insurance Plan. The Company also
provides pay continuation payments for employees determined to be
disabled before November 1995. Such payments for employees
determined to be disabled after that date are paid by an insurance
company, and the cost of such insurance is paid by employees. The
Company adopted Statement of Financial Accounting Standards No.
112, which requires a change in the method of accounting for these
benefits from the pay-as-you-go method to an accrual method, as of
December 31, 1993. The liability for these benefits totaled $52
million and $48 million as of December 31, 1995 and 1994, respectively.
The portion of the December 31, 1993 liability attributable to
regulated activities was deferred. Consistent with the PSC's November
1995 order, the amounts deferred will be amortized over a 15-year
period beginning in 1998. The adoption of Statement No. 112 did
not have a material impact on net income.
Assumptions
The pension, postretirement, and other postemployment benefit
liabilities were determined using the following assumptions.
At December 31, 1995 1994
- --------------------------------------------------------------
Assumptions:
Discount rate
Pension and postretirement benefits 7.5% 8.5%
Other postemployment benefits 6.0% 8.5%
Average increase in
future compensation levels 4.0% 4.0%
Expected long-term rate of
return on assets 9.0% 9.0%
The health care inflation rates for 1995 are assumed to be
8.7% for Medicare-eligible retirees and 11.8% for retirees not covered
by Medicare. The health care inflation rates for 1996 are
assumed to be 8.0% for Medicare-eligible retirees and 10.5% for
retirees not covered by Medicare. After 1996, both rates are assumed to
decrease by 0.5% annually to an ultimate rate of 5.5% in the years 2001
and 2006, respectively. A one percentage point increase in the health
care inflation rate from the assumed rates would increase the
accumulated postretirement benefit obligation by approximately $40
million as of December 31, 1995 and would increase the aggregate of
the service cost and interest cost components of postretirement
benefit cost by approximately $4 million annually.
48
Baltimore Gas and Electric Company and Subsidiaries
Note 7. Termination Benefits
BGE offered a Voluntary Special Early Retirement Program (the 1992
VSERP) to eligible employees who retired during the period February 1,
1992 through April 1, 1992. In accordance with Statement of Financial
Accounting Standards No. 88, "Employers' Accounting for Settlements
and Curtailments of Defined Benefit Pension Plans and for
Termination Benefits," the one-time cost of termination benefits
associated with the 1992 VSERP, which consisted principally of an
enhanced pension benefit, was recognized in 1992 and reduced net income
by $6.6 million, or 5 cents per common share. In April 1993, the PSC
authorized BGE to amortize this charge over a five-year period
for ratemaking purposes. Accordingly, BGE established a regulatory
asset and recorded a corresponding credit to operating expense for
this amount. The reversal of the 1992 VSERP in April 1993 increased net
income by $6.6 million, or 5 cents per common share.
BGE offered a second Voluntary Special Early Retirement Program (the
1993 VSERP) to eligible employees who retired as of February 1, 1994.
The one-time cost of the 1993 VSERP consisted of enhanced pension and
postretirement benefits. In addition to the 1993 VSERP, further
employee reductions have been accomplished through the elimination of
certain positions, and various programs have been offered to
employees impacted by the eliminations. In accordance with Statement
No. 88, the one-time cost of termination benefits associated with the
1993 VSERP and various programs, which totaled $105.5 million, was
recognized in 1993. The $88.3 million portion of 1993 VSERP
attributable to regulated activities was deferred and is being
amortized over a five-year period for ratemaking purposes, beginning in
February 1994, consistent with previous rate actions of the PSC. The
$17.2 million remaining cost of termination benefits was charged to
expense in 1993.
Note 8. Short-Term Borrowings
Information concerning short-term borrowings is set forth below.
Short-term borrowings include bank loans, commercial paper notes, and
bank lines of credit. The Company pays commitment fees in support of
lines of credit. Borrowings under the lines are at the banks' prime
rates, base interest rates, or at various money market rates.
1995 1994 1993
(Dollar amounts in thousands)
BGE's Bank Loans
Borrowings outstanding at December 31 $ 3,845 $ - $ -
Weighted average interest rate of borrowings outstanding at December 31 4.74% - % - %
Maximum borrowings during the year $ 3,845 $ - $ -
BGE's Commercial Paper Notes
Borrowings outstanding at December 31 $275,300 $ 63,700 $ -
Weighted average interest rate of notes outstanding at December 31 5.92% 6.10% - %
Unused lines of credit supporting commercial paper notes at December 31* $238,000 $148,000 $ 208,000
Maximum borrowings during the year $339,100 $187,500 $ 96,900
Constellation Companies' Lines of Credit
Borrowings outstanding at December 31 $ 160 $ - $ -
Weighted average interest rate of borrowings outstanding at December 31 -% - % - %
Unused lines of credit at December 31 $ --- $ - $ 20,000
Maximum borrowings during the year $ 160 $ - $ -
*Exclusive of $150 million of revolving credit agreements undrawn at
year-end (see Note 9).
49
Baltimore Gas and Electric Company and Subsidiaries
Note 9. Long-Term Debt
First Refunding Mortgage Bonds of BGE
Substantially all of the principal properties and franchises owned by
BGE, as well as the capital stock of Constellation Holdings, Inc.,
Safe Harbor Water Power Corporation, HP&S, EP&S, and BNG, Inc., are
subject to the lien of the mortgage under which BGE's outstanding First
Refunding Mortgage Bonds have been issued.
On August 1 of each year, BGE is required to pay to the mortgage
trustee an annual sinking fund payment equal to 1% of the largest
principal amount of Mortgage Bonds outstanding under the mortgage
during the preceding twelve months. Such funds are to be used, as
provided in the mortgage, for the purchase and retirement by the
trustee of Mortgage Bonds of any series other than the 5-1/2%
Installment Series of 2002, the 8.40% Series of 1999, the 5-1/2% Series
of 2000, the 8-3/8% Series of 2001, the 7-1/4% Series of 2002, the
6-1/2% Series of 2003, the 6-1/8% Series of 2003, the 5-1/2% Series of
2004, the 7-1/2% Series of 2007, and the 6-5/8% Series of 2008.
Other Long-Term Debt of BGE
BGE maintains revolving credit agreements that expire at various
times during 1998. Under the terms of the agreements, BGE may, at its
option, obtain loans at various interest rates. A commitment fee is
paid on the daily average of the unborrowed portion of the
commitment. At December 31, 1995, BGE had no borrowings under
these revolving credit agreements and had available $150 million
of unused capacity under these agreements.
On December 29, 1995 BGE entered into a $50 million term bank loan which
matures on March 29, 2001. Under the terms of the loan, the bank has a
one-time option to cancel the loan on December 29, 1997. Until that
date, the interest rate on the loan is 5.22%. If the bank does not
cancel the loan on December 29, 1997, the interest rate for the
remaining term will reset to 6.11%.
Following is information regarding BGE's Medium-term Notes
outstanding at December 31, 1995:
Weighted-Average
Series Interest Rate Maturity Dates
- --------------------------------------------------------------------
A 8.22% 1996
B 8.43% 1998-2006
C 7.04% 1996-2003
D 6.12% 1998-2005
The principal amounts of the 5-1/2% Installment Series Mortgage Bonds
payable each year are as follows:
Year
- --------------------------------------------------------------------
(In thousands)
1996 through 1997 $ 605
1998 and 1999 690
2000 and 2001 865
2002 6,725
Long-Term Debt of Constellation Companies
The Constellation Companies entered into an unsecured revolving credit
agreement on December 9, 1994 in the amount of $50 million. This
agreement matures December 9, 1998 and will be used to provide
liquidity for general corporate purposes. As of December 31, 1995, the
Constellation Companies had $1 million outstanding under this agreement.
The mortgage and construction loans and other collateralized notes have
varying terms. The $9.9 million, 7.50% mortgage note requires
monthly principal and interest payments through October 9, 2005.
The $110 million of variable rate mortgage notes require periodic
payment of principal and interest with various maturities from January
1996 through July 2009. The $5.9 million, 7.357% mortgage note
requires quarterly principal and interest payments through March 15,
2009.
The unsecured notes outstanding as of December 31, 1995 mature in
accordance with the following schedule:
Amount
- --------------------------------------------------------------------
(In thousands)
8.71%, due August 28, 1996 $ 23,000
6.19%, due September 9, 1996 10,000
8.93%, due August 28, 1997 52,000
6.65%, due September 9, 1997 15,000
8.23%, due October 15, 1997 30,000
7.05%, due April 22, 1998 25,000
7.06%, due September 9, 1998 20,000
8.48%, due October 15, 1998 75,000
7.30%, due April 22, 1999 90,000
8.73%, due October 15, 1999 15,000
7.55%, due April 22, 2000 35,000
7.43%, due September 9, 2000 30,000
- --------------------------------------------------------------------
Total $420,000
====================================================================
Weighted Average Interest Rates for Variable Rate Debt
The weighted average interest rates for variable rate debt during 1995
and 1994 were as follows:
1995 1994
- --------------------------------------------------------------------
BGE
Floating rate series mortgage bonds 6.30% 4.91%
Pollution control loan 3.79 2.80
Port facilities loan 4.06 3.02
Adjustable rate pollution control loan 3.75 3.13
Economic development loan 4.01 3.00
Constellation Companies
Mortgage and construction loans
and other collateralized notes 8.99 7.27
Loans under credit agreements 6.74 -
Aggregate Maturities
The combined aggregate maturities and sinking fund requirements for
all of the Company's long-term borrowings for each of the next five
years are as follows:
Constellation
Year BGE Companies
- --------------------------------------------------------------------
(In thousands)
1996 $ 71,659 $ 49,310
1997 80,657 134,970
1998 92,328 138,351
1999 246,420 118,175
2000 251,441 85,521
50
Baltimore Gas and Electric Company and Subsidiaries
Note 10. Redeemable Preference Stock
The 7.80%, 1989 Series is subject to mandatory redemption in full at par
on July 1, 1997. The following series are subject to an annual
mandatory redemption of the number of shares shown below at par
beginning in the year shown below. At BGE's option, an additional
number of shares, not to exceed the same number as are mandatory, may
be redeemed at par in any year, commencing in the same year in which
the mandatory redemption begins. The 8.25%, 1989 Series, the 8.625%,
1990 Series, and the 7.85%, 1991 Series listed below are not
redeemable except through operation of a sinking fund.
Beginning
Series Shares Year
- --------------------------------------------------------------------
7.50%, 1986 Series 15,000 1992
6.75%, 1987 Series 15,000 1993
8.25%, 1989 Series 100,000 1995
8.625%, 1990 Series 130,000 1996
7.85%, 1991 Series 70,000 1997
The combined aggregate redemption requirements for all series of
redeemable preference stock for each of the next five years are as
follows:
Year
- --------------------------------------------------------------------
(In thousands)
1996 $26,000
1997 83,000
1998 33,000
1999 23,000
2000 23,000
With regard to payment of dividends or assets available in the
event of liquidation, preferred stock ranks prior to preference and
common stock; all issues of preference stock, whether subject to
mandatory redemption or not, rank equally; and all preference stock
ranks prior to common stock.
Note 11. Leases
The Company, as lessee, contracts for certain facilities and
equipment under lease agreements with various expiration dates and
renewal options. Consistent with the regulatory treatment, lease
payments for utility operations are charged to expense. Lease expense,
which is comprised primarily of operating leases, totaled $12.2
million, $12.7 million, and $13.8 million for the years ended 1995,
1994, and 1993, respectively.
The future minimum lease payments at December 31, 1995 for
long-term noncancelable operating leases are as follows:
Year
- --------------------------------------------------------------------
(In thousands)
1996 $ 4,485
1997 4,398
1998 3,681
1999 1,712
2000 1,537
Thereafter 4,214
- --------------------------------------------------------------------
Total minimum lease payments $20,027
====================================================================
Certain of the Constellation Companies, as lessor, have entered into
operating leases for office and retail space. These leases expire
over periods ranging from 1 to 21 years, with options to renew. The
net book value of property under operating leases was $147 million at
December 31, 1995. The future minimum rentals to be received under
operating leases in effect at December 31, 1995 are as follows:
Year
- --------------------------------------------------------------------
(In thousands)
1996 $ 14,412
1997 12,134
1998 10,883
1999 10,130
2000 9,459
Thereafter 66,660
- --------------------------------------------------------------------
Total minimum rentals $123,678
====================================================================
51
Baltimore Gas and Electric Company and Subsidiaries
Note 12. Commitments, Guarantees, and Contingencies
Commitments
BGE has made substantial commitments in connection with its construction
program for 1995 and subsequent years. In addition, BGE has entered into
three long-term contracts for the purchase of electric generating
capacity and energy. The contracts expire in 2001, 2013, and 2023.
Total payments under these contracts were $68.4, $69.4, and $68.7
million during 1995, 1994, and 1993, respectively. At December 31,
1995, the estimated future payments for capacity and energy that BGE is
obligated to buy under these contracts are as follows:
Year
- --------------------------------------------------------------------
(In thousands)
1996 $ 62,989
1997 60,355
1998 78,950
1999 90,224
2000 91,365
Thereafter 902,432
- --------------------------------------------------------------------
Total payments $1,286,315
====================================================================
Certain of the Constellation Companies have committed to contribute
additional capital and to make additional loans to certain affiliates,
joint ventures, and partnerships in which they have an interest. As of
December 31, 1995, the total amount of investment requirements committed
to by the Constellation Companies is $44 million.
In December, 1994, BGE and HP&S entered into agreements with a
financial institution whereby BGE and HP&S can sell on an ongoing basis
up to an aggregate of $40 million and $50 million, respectively, of
an undivided interest in a designated pool of customer receivables.
Under the terms of the agreements, BGE and HP&S have limited recourse on
the receivables and have recorded a reserve for credit losses. At
December 31, 1995, BGE and HP&S had sold $30 million and $42 million of
receivables, respectively, under these agreements.
Guarantees
BGE has agreed to guarantee two-thirds of certain indebtedness of
Safe Harbor Water Power Corporation. The total amount of indebtedness
that can be guaranteed is $45 million, of which $30 million represents
BGE's share of the guarantee. As of December 31, 1995, outstanding
indebtedness of Safe Harbor Water Power Corporation was $33 million,
of which $22 million is guaranteed by BGE. BGE has also agreed to
guarantee up to $20 million of obligations and indebtedness of BNG,
Inc. As of December 31, 1995, there were no outstanding obligations
under this guarantee. BGE assesses that the risk of material loss
on the loans guaranteed is minimal.
As of December 31, 1995, the total outstanding loans and letters of
credit of certain power generation and real estate projects
guaranteed by the Constellation Companies were $35 million. Also, the
Constellation Companies have agreed to guarantee cer-tain other
borrowings of various power generation and real estate projects. The
Company has assessed that the risk of material loss on the loans
guaranteed and performance guarantees is minimal.
Pending Merger With Potomac Electric Power Company
BGE, Potomac Electric Power Company, a District of Columbia and
Virginia corporation (PEPCO) and Constellation Energy Corporation
(formerly named "RH Acquisition Corp."), a Maryland corporation which
will also be incorporated in Virginia (CEC), have entered into an
Agreement and Plan of Merger, dated as of September 22, 1995. CEC was
formed to accomplish the merger and its outstanding capital stock is
owned 50% by BGE and 50% by PEPCO. The Agreement and Plan of Merger
provides for a strategic business combination that will be
accomplished by merging both BGE and PEPCO into CEC (the Transaction).
The Transaction, which was unanimously approved by the Boards of
Directors of BGE and PEPCO, is expected to close during 1997 after
shareholder approval is obtained and all other conditions to the
consummation of the Transaction, including obtaining applicable
regulatory approvals, are met or waived. In connection with the
Transaction, BGE common shareholders will receive one share of CEC
common stock for each BGE share and PEPCO common shareholders will
receive 0.997 share of CEC common stock for each PEPCO share. Further
details about the proposed merger are provided in the report on Form 8-K
dated September 22, 1995 and the Registration Statement on Form S-4
(Registration No. 33-64799).
Environmental Matters
The Clean Air Act of 1990 (the Act) contains two titles designed
to reduce emissions of sulfur dioxide and nitrogen oxide (NOx) from
electric generating stations. Title IV contains provisions for
compliance in two separate phases. Phase I of Title IV became
effective January 1, 1995, and Phase II of Title IV must be implemented
by 2000. BGE met the requirements of Phase I by installing flue gas
desulfurization systems and fuel switching and through unit
retirements. BGE is currently examining what actions will be required
in order to comply with Phase II of the Act. However, BGE anticipates
that compliance will be attained by some combination of fuel
switching, flue gas desulfurization, unit retirements, or allowance
trading.
At this time, plans for complying with NOx control requirements under
Title I of the Act are less certain because all implementation
regulations have not yet been finalized by the government. It is
expected that by the year 1999 these regulations will require
additional NOx controls for ozone attainment at BGE's generating plants
and at other BGE facilities. The controls will result in additional
expenditures that are difficult to predict prior to the issuance of
such regulations. Based on existing and proposed ozone
nonattainment regulations, BGE currently estimates that the NOx
controls at BGE's generating plants will cost approximately $90
million. BGE is currently unable to predict the cost of compliance with
the additional requirements at other BGE facilities.
BGE has been notified by the Environmental Protection Agency and
several state agencies that it is being considered a potentially
responsible party (PRP) with respect to the cleanup of certain
52
Baltimore Gas and Electric Company and Subsidiaries
environmentally contaminated sites owned and operated by third
parties. In addition, a subsidiary of Constellation Holdings,
Inc. has been named as a defendant in a case concerning an alleged
environmentally contaminated site owned and operated by a third
party. Cleanup costs for these sites cannot be estimated, except that
BGE's 15.79% share of the possible cleanup costs at one of these sites,
Metal Bank of America, a metal reclaimer in Philadelphia, could exceed
amounts recognized by up to approximately $7 million based on the
highest estimate of costs in the range of reasonably possible
alternatives. Although the cleanup costs for certain of the remaining
sites could be significant, BGE believes that the resolution of these
matters will not have a material effect on its financial position or
results of operations.
Also, BGE is coordinating investigation of several former gas
manufacturing plant sites, including exploration of corrective action
options to remove coal tar. However, no formal legal proceedings
have been instituted. BGE has recognized estimated environmental
costs at these sites totaling $38.6 million as of December 31, 1995.
These costs, net of accumulated amortization, have been deferred as a
regulatory asset (see Note 5). The technology for cleaning up such sites
is still developing, and potential remedies for these sites have not
been identified. Cleanup costs in excess of the amounts recognized,
which could be significant in total, cannot presently be estimated.
Nuclear Insurance
An accident or an extended outage at either unit of the Calvert Cliffs
Nuclear Power Plant could have a substantial adverse effect on
BGE. The primary contingencies resulting from an incident at the
Calvert Cliffs plant would involve the physical damage to the plant,
the recoverability of replacement power costs, and BGE's liability to
third parties for property damage and bodily injury. BGE maintains
various insurance policies for these contingencies. The costs that
could result from a major accident or an extended outage at either of
the Calvert Cliffs units could exceed the coverage limits.
In addition, in the event of an incident at any commercial nuclear
power plant in the country, BGE could be assessed for a portion of
any third party claims associated with the incident. Under the
provisions of the Price Anderson Act, the limit for third party claims
from a nuclear incident is $8.92 billion. If third party claims
relating to such an incident exceed $200 million (the amount of primary
insurance), BGE's share of the total liability for third party claims
could be up to $159 million per incident, that would be payable at a
rate of $20 million per year.
BGE and other operators of commercial nuclear power plants in the
United States are required to purchase insurance to cover claims of
certain nuclear workers. Other non-governmental commercial nuclear
facilities may also purchase such insurance. Coverage of up to $400
million is provided for claims against BGE or others insured by these
policies for radiation injuries. If certain claims were made under
these policies, BGE and all policyholders could be assessed, with
BGE's share being up to $6.08 million in any one year.
For physical damage to Calvert Cliffs, BGE has $2.75 billion of
property insurance from industry mutual insurance companies. If an
outage at Calvert Cliffs is caused by an insured physical damage
loss and lasts more than 21 weeks, BGE has up to $473.2 million per
unit of insurance, provided by an industry mutual insurance company,
for replacement power costs. This amount can be reduced by up to $94.6
million per unit if an outage to both units at Calvert Cliffs is caused
by a singular insured physical damage loss. If accidents at any insured
plants cause a short-fall of funds at the industry mutuals, BGE and all
policyholders could be assessed, with BGE's share being up to $44.1
million.
Recoverability of Electric Fuel Costs
By statute, actual electric fuel costs are recoverable so long as the
PSC finds that BGE demonstrates that, among other things, it has
maintained the productive capacity of its generating plants at a
reasonable level. The PSC and Maryland's highest appellate court have
interpreted this as permitting a subjective evaluation of each
unplanned outage at BGE's generating plants to determine whether or
not BGE had implemented all reasonable and cost effective maintenance
and operating control procedures appropriate for preventing the
outage. Effective January 1, 1987, the PSC authorized the
establishment of the Generating Unit Performance Program (GUPP)
to measure, annually, utility compliance with maintaining the
productive capacity of generating plants at reasonable levels by
establishing a system-wide generating performance target and
individual performance targets for each base load generating unit. In
future fuel rate hearings, actual generating performance after
adjustment for planned outages will be compared to the system-wide
target and, if met, should signify that BGE has complied with the
requirements of Maryland law. Failure to meet the system-wide target
will result in review of each unit's adjusted actual generating
performance versus its performance target in determining compliance
with the law and the basis for possibly imposing a penalty on BGE.
Parties to fuel rate hearings may still question the prudence of BGE's
actions or inactions with respect to any given generating plant
outage, which could result in the disallowance of replacement energy
costs by the PSC.
Since the two units at BGE's Calvert Cliffs Nuclear Power Plant
utilize BGE's lowest cost fuel, replacement energy costs associated
with outages at these units can be significant. BGE cannot estimate the
amount of replacement energy costs that could be challenged or
disallowed in future fuel rate proceedings, but such amounts could be
material.
In October 1988, BGE filed its first fuel rate application for a
change in its electric fuel rate under the GUPP program. The
resultant case before the PSC covers BGE's operating performance in
calendar year 1987, and BGE's filing demonstrated that it met the
system-wide and individual nuclear plant performance targets for
1987. In November 1989, testimony was filed on behalf of Maryland
People's Counsel alleging that seven outages
53
Baltimore Gas and Electric Company and Subsidiaries
at the Calvert Cliffs plant in 1987 were due to management imprudence
and that the replacement energy costs associated with those outages
should be disallowed by the PSC. Total replacement energy costs
associated with the 1987 outages were approximately $33 million. On
January 23, 1995, the Hearing Examiner issued his decision in the 1987
fuel rate proceeding and found that the Company had met the GUPP
standard which establishes a presumption that BGE had operated the Plant
at a reasonably productive capacity level. However, the Order
found that the presumption of reasonableness would be overcome by a
showing of mismanagement and that such a showing was made with
respect to the environmental qualifications outage time. 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
PSC by both BGE and People's Counsel. If the PSC upholds the Hearing
Examiner, the Company's earnings would be impacted by approximately
$4.5 million.
In May 1989, BGE filed its fuel rate case in which 1988 performance
was to be examined. BGE met the system-wide and nuclear plant
performance targets in 1988. People's Counsel alleges that BGE
imprudently managed several outages at Calvert Cliffs, and BGE
estimates that the total replacement energy costs associated with
these 1988 outages were approximately $2 million. On November 14,
1991, a Hearing Examiner at the PSC issued a proposed Order, which
became final on December 17, 1991 and concluded that no disallowance
was warranted. The Hearing Examiner found that BGE maintained the
productive capacity of the Plant at a reasonable level, noting that
it produced a near record amount of power and exceeded the GUPP
standard. Based on this record, the Order concluded there was
sufficient cause to excuse any avoidable failures to maintain
productive capacity at higher levels.
During 1989, 1990, and 1991, BGE experienced extended outages at its
Calvert Cliffs Nuclear Power Plant. In the Spring of 1989, a leak was
discovered around the Unit 2 pressurizer heater sleeves during a
refueling outage. BGE shut down Unit 1 as a precautionary measure on
May 6, 1989 to inspect for similar leaks and none were found. However,
Unit 1 was out of service for the remainder of 1989 and 285 days of
1990 to undergo maintenance and modification work to enhance the
reliability of various safety systems, to repair equipment, and to
perform required periodic surveillance tests. Unit 2, which returned to
service on May 4, 1991, remained out of service for the remainder of
1989, 1990, and the first part of 1991 to repair the pressurizer,
perform maintenance and modification work, and complete the
refueling. The replacement energy costs associated with these
extended outages for both units at Calvert Cliffs, concluding with
the return to service of Unit 2, is estimated to be $458 million.
In a December 1990 Order issued by the PSC in a BGE base rate
proceeding, the PSC found that certain operations and maintenance
expenses incurred at Calvert Cliffs during the test year should not be
recovered from ratepayers. The PSC found that this work, which was
performed during the 1989-1990 Unit 1 outage and fell within the test
year, was avoidable and caused by BGE actions which were deficient.
The Commission noted in the Order that its review and findings on
these issues pertain to the reasonableness of BGE's test-year
operations and maintenance expenses for purposes of setting base rates
and not to the responsibility for replacement power costs associated
with the outages at Calvert Cliffs. The PSC stated that its decision
in the base rate case will have no res judicata (binding) effect
in the fuel rate proceeding examining the 1989-1991 outages. The work
characterized as avoidable significantly increased the duration of the
Unit 1 outage. Despite the PSC's statement regarding no binding
effect, BGE recognizes that the views expressed by the PSC make the
full recovery of all of the replacement energy costs associated
with the Unit 1 outage doubtful. Therefore, in December 1990, BGE
recorded a provision of $35 million against the possible disallowance
of such costs. BGE cannot determine whether replacement energy costs
may be disallowed in the present fuel rate proceedings in excess of the
provision, but such amounts could be material.
Note 13. Fair Value of Financial Instruments
The following table presents the carrying amounts and fair values of
financial instruments included in the Consolidated Balance Sheets.
At December 31, 1995 1994
Carrying Fair Carrying Fair
Amount Value Amount Value
(In thousands)
Cash and cash equivalents $ 23,443 $ 23,443 $ 38,590 $ 38,590
Net accounts receivable 400,005 400,005 314,842 314,842
Other current assets 54,070 54,070 29,344 29,344
Investments and other assets for which it is:
Practicable to estimate fair value 149,645 150,170 138,978 137,782
Not practicable to estimate fair value 73,042 --- 69,514 ---
Short-term borrowings 279,305 279,305 64,205 64,205
Current portions of long-term debt and preference stock 146,969 146,969 323,675 323,675
Accounts payable 177,092 177,092 181,931 181,931
Other current liabilities 193,992 193,992 191,121 191,121
Long-term debt 2,598,254 2,694,858 2,584,932 2,417,625
Redeemable preference stock 242,000 254,809 279,500 281,478
54
Baltimore Gas and Electric Company and Subsidiaries
Financial instruments included in other current assets include
trading securities and miscellaneous loans receivable of the
Constellation Companies. Financial instruments included in other
current liabilities represent total current liabilities from the
Consolidated Balance Sheets excluding short-term borrowings, current portions of
long-term debt and preference stock, accounts payable, and accrued
vacation costs. The carrying amount of current assets and current
liabilities approximates fair value because of the short maturity of
these instruments.
Investments and other assets include investments in common and
preferred securities, which are classified as financial investments in
the Consolidated Balance Sheets, and the nuclear decommissioning
trust fund. The fair value of investments and other assets is based
on quoted market prices where available. It was not practicable to
estimate the fair value of the Constellation Companies'
investments in 23 financial partnerships which invest in nonpublic
debt and equity securities or investments in four partnerships
which own solar powered energy production facilities because the
timing and magnitude of cash flows from these investments are difficult
to predict. These investments are carried at their original
cost in the Consolidated Balance Sheets. The investments
in financial partnerships totaled $50 million and $47 million at
December 31, 1995 and 1994, respectively, representing ownership
interests up to 10%. The aggregate assets of these partnerships totaled
$6.3 billion at December 31, 1994. The investments in solar
powered energy production facility partnerships totaled $23
million at December 31, 1995 and 1994, representing ownership
interests up to 12%. The aggregate assets of these partnerships
totaled $83 million at December 31, 1994.
The fair value of fixed-rate long-term debt and redeemable preference
stock is estimated using quoted market prices where available or by
discounting remaining cash flows at the current market rate. The
carrying amount of variable-rate long-term debt approximates fair
value.
BGE and the Constellation Companies have loan guarantees on
outstanding indebtedness totaling $22 million and $35 million,
respectively, at December 31, 1995 and $23.3 million and $17.0 million,
respectively, at December 31, 1994 for which it is not practicable to
determine fair value. It is not anticipated that these loan guarantees
will need to be funded.
Note 14. Quarterly Financial Data (Unaudited)
The following data are unaudited but, in the opinion of Management,
include all adjustments necessary for a fair presentation. BGE's
utility business is seasonal in nature with the peak sales periods
generally occurring during the summer and winter months. Accordingly,
comparisons among quarters of a year may not be indicative of overall
trends and changes in operations.
Quarter Ended Year Ended
March 31 June 30 September 30 December 31 December 31
- ------------------------------------------------------------------------------------------------------------------------------
(In thousands, except per-share amounts)
1995
Revenues $717,806 $642,500 $848,781 $725,712 $2,934,799
Income from operations 148,222 120,920 299,744 126,806 695,692
Net income 70,854 50,889 163,335 52,929 338,007
Earnings applicable to common stock 60,902 40,937 153,104 42,486 297,429
Earnings per share of common stock 0.41 0.28 1.04 0.29 2.02
==============================================================================================================================
1994
Revenues $767,686 $651,152 $753,878 $610,269 $2,782,985
Income from operations 162,559 136,778 232,472 103,450 635,259
Net income 82,145 66,708 126,616 48,148 323,617
Earnings applicable to common stock 72,114 56,687 116,714 38,180 283,695
Earnings per share of common stock 0.49 0.39 0.79 0.26 1.93
==============================================================================================================================
Results for the first quarter of 1994 reflect a $10.0 million
one-time bonus paid to employees in lieu of a general increase.
Results for the third quarters of 1995 and 1994 reflect the $9.7 and
$11.0 million write-offs, respectively, of certain Perryman costs (see
Note 1).
Certain prior-quarter amounts have been reclassified to conform
with the current presentation.
55
Baltimore Gas and Electric Company and Subsidiaries
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Not applicable.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this item with respect to directors is set
forth on pages 2 through 4 under "Item 1. Election of 14 Directors" in the Proxy
Statement and is incorporated herein by reference.
The information required by this item with respect to executive officers
is, pursuant to instruction 3 of paragraph (b) of Item 401 of Regulation S-K,
set forth in Item 10 of Part I of this Form 10-K under "Executive Officers of
the Registrant."
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item is set forth on pages 7 through 14
under "Item 1. Election of 14 Directors -- Compensation of Executive Officers by
the Company" in the Proxy Statement and is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this item is set forth on page 6 under "Item 1.
Election of 14 Directors -- Security Ownership of Directors and Executive
Officers" in the Proxy Statement and is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this item is set forth on page 5 under "Item 1.
Election of 14 Directors -- Certain Relationships and Transactions" in the Proxy
Statement and is incorporated herein by reference.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) The following documents are filed as a part of this Report:
1. Financial Statements:
Auditors' Report dated January 19, 1996 of Coopers & Lybrand L.L.P.,
Independent Accountants
Consolidated Statements of Income for three years ended December 31,
1995
Consolidated Balance Sheets at December 31, 1995 and December 31,
1994
Consolidated Statements of Cash Flows for three years ended December
31, 1995
Consolidated Statements of Common Shareholders' Equity for three
years ended
December 31, 1995
Consolidated Statements of Capitalization at December 31, 1995 and
December 31, 1994
Consolidated Statements of Income Taxes for three years ended
December 31, 1995
Notes to Consolidated Financial Statements
2. Financial Statement Schedules:
Schedule II -- Valuation and Qualifying Accounts
Schedules other than those listed above are omitted as not applicable or
not required.
3. Exhibits Required by Item 601 of Regulation S-K Including Each
Management Contract or Compensatory Plan or Arrangement Required to
be Filed as an Exhibit.
56
EXHIBIT
NUMBER
*2(a) -- Agreement and Plan of Merger dated as of September 22, 1995, by and among Baltimore Gas and Electric
Company, Potomac Electric Power Company, and RH Acquisition Corp. (Designated as Exhibit A in the
Joint Proxy Statement of Baltimore Gas and Electric Company and Potomac Electric Power Company, which
was filed as part of Form S-4 of Constellation Energy Corporation, as amended, which became effective
February 9, 1996, Registration No. 33-64799.)
*2(b) -- BGE Stock Option Agreement dated as of September 22, 1995, by and between Baltimore Gas and Electric
Company and Potomac Electric Power Company. (Designated as Exhibit B1 in the Joint Proxy Statement of
Baltimore Gas and Electric Company and Potomac Electric Power Company, which was filed as part of
Form S-4 of Constellation Energy Corporation, as amended, which became effective February 9, 1996,
Registration No. 33-64799.)
*2(c) -- PEPCO Stock Option Agreement dated as of September 22, 1995, by and between Baltimore Gas and
Electric Company and Potomac Electric Power Company. (Designated as Exhibit B2 in the Joint Proxy
Statement of Baltimore Gas and Electric Company and Potomac Electric Power Company, which was filed
as part of Form S-4 of Constellation Energy Corporation, as amended, which became effective February
9, 1996, Registration No. 33-64799.)
*2(d) -- Registration Statement on Form S-4 of Constellation Energy Corporation, as amended, which became
effective February 9, 1996, Registration No. 33-64799.
*3(a) -- Charter of BGE, restated as of April 25, 1995. (Designated as Exhibit No. 3(a) in Form 10-Q dated May
11, 1995, File No. 1-1910.)
*3(b) -- Articles Supplementary, dated as of September 5, 1995, to the Charter of BGE. (Designated as Exhibit
No. 3 in Form 10-Q dated November 13, 1995, File No. 1-1910.)
*3(c) -- By-Laws of BGE, as amended to April 18, 1995. (Designated as Exhibit No. 3(b) in Form 10-Q dated May
11, 1995, File No. 1-1910.)
*4(a) -- Supplemental Indenture between BGE and Bankers Trust Company, as Trustee, dated as of June 20, 1995,
supplementing, amending and restating Deed of Trust dated February 1, 1919. (Designated as Exhibit
No. 4 in Form 10-Q dated August 11, 1995, File No. 1-1910.); and the following Supplemental
Indentures between BGE and Bankers Trust Company, Trustee:
DESIGNATED IN
EXHIBIT
DATED FILE NO. NUMBER
*April 15, 1966 2-26278 4-3
*August 1, 1967 1-1910 (Form 10-K Annual Report for 1967) D-1
*July 1, 1972 2-45452 2-3
*July 15, 1977 2-59772 2-3
(3 Indentures)
*October 15, 1989 1-1910 (Form 10-Q dated November 14, 1989) 4(a)
*August 15, 1991 33-45259 (Form S-3 Registration) 4(a)(i)
*January 15, 1992 33-45259 (Form S-3 Registration) 4(a)(ii)
*July 1, 1992 1-1910 (Form 8-K Report for January 29, 1993) 4(a)
*February 15, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(i)
*March 1, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(ii)
*March 15, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(iii)
*April 15, 1993 1-1910 (Form 10-Q dated May 13, 1993) 4
*July 1, 1993 1-1910 (Form 10-Q dated August 13, 1993) 4(a)
*July 15, 1993 1-1910 (Form 10-Q dated August 13, 1993) 4(b)
*October 15, 1993 1-1910 (Form 10-Q dated November 12, 1993) 4
*March 15, 1994 1-1910 (Form 10-K Annual Report for 1993) 4(a)
*4(b) -- Indenture dated July 1, 1985, between BGE and The Bank of New York (Successor to Mercantile- Safe
Deposit and Trust Company), Trustee. (Designated in Registration File No. 2-98443 as Exhibit 4(a));
as supplemented by Supplemental Indentures dated as of October 1, 1987 (Designated in Form 8-K, dated
November 13, 1987, File No. 1-1910 as Exhibit 4(a)) and as of January 26, 1993 (Designated in Form
8-K, dated January 29, 1993, File No. 1-1910 as Exhibit 4(b).)
*10(a) -- Baltimore Gas and Electric Company Executive Benefits Plan, as amended and restated. (Designated as
Exhibit No. 10 in Form 10-Q dated August 11, 1995, File No. 1-1910.)
*10(b) -- Executive Incentive Plan of the Baltimore Gas and Electric Company. (Designated as Exhibit No. 10(b)
to the Annual Report on Form 10-K for the year ended December 31, 1992, File No. 1-1910.)
57
*10(c) -- Baltimore Gas and Electric Company 1995 Long-Term Incentive Plan. (Designated as Exhibit No. 10(c) to
the Annual Report on Form 10-K for the year ended December 31, 1994, File No. 1-1910.)
*10(d) -- Baltimore Gas and Electric Company Non-qualified Deferred Compensation Plan for Executive Officers.
(Designated as Exhibit No. 10(d) to the Annual Report on Form 10-K for the year ended December 31,
1992, File No. 1-1910.)
*10(e) -- Baltimore and Gas and Electric Company Non-qualified Deferred Compensation Plan for Non-Employee
Directors (formerly Baltimore Gas and Electric Company Deferred Compensation Plan for Non-Employee
Directors). (Designated as Exhibit No. 10(f) to the Annual Report on Form 10-K for the year ended
December 31, 1993, File No. 1-1910.)
*10(f) -- Baltimore Gas and Electric Company Retirement Plan for Non-Employee Directors, as amended and
restated. (Designated as Exhibit No. 10(f) to the Annual Report on Form 10-K for the year ended
December 31, 1994, File No. 1-1910.)
*10(g) -- Summary of Baltimore Gas and Electric Company Long Term Performance Program. (Designated as Exhibit
No. 10(h) to the Annual Report on Form 10-K for the year ended December 31, 1993, File No. 1-1910.)
*10(h) -- Grantor Trust Agreement Dated as of July 31, 1994 between Baltimore Gas and Electric Company and
Citibank, N.A. (Designated as Exhibit No. 10(h) to the Annual Report on Form 10-K for the year ended
December 31, 1994, File No. 1-1910.)
*10(i) -- Constellation Holdings, Inc., Summary of Amended Executive Benefits Plan. (Designated as Exhibit No.
10(i) to the Annual Report on Form 10-K for the year ended December 31, 1994, File No. 1-1910.)
*10(j) -- Summary of Constellation Holdings, Inc. Annual Incentive Plan. (Designated as Exhibit No. 10(g) to
the Annual Report on Form 10-K for the year ended December 31, 1992, File No. 1-1910.)
*10(k) -- Amended Summary 1992 Long Term Incentive Plan of Constellation Holdings, Inc. (Designated as Exhibit
No. 10(k) to the Annual Report on Form 10-K for the year ended December 31, 1993, File No. 1-1910.)
*10(l) -- Summary 1994-96 Long Term Incentive Plan of Constellation Holdings, Inc. (Designated as Exhibit No.
10(l) to the Annual Report on Form 10-K for the year ended December 31, 1994, File No. 1-1910.)
*10(m) -- Employment Agreement of Christian H. Poindexter. (Designated as Exhibit C2 in the Joint Proxy
Statement of Baltimore Gas and Electric Company and Potomac Electric Power Company, which was filed
as part of Form S-4 of Constellation Energy Corporation, as amended, which became effective February
9, 1996, Registration No. 33-64799.)
*10(n) -- Employment Agreement of Edward A. Crooke. (Designated as Exhibit C3 in the Joint Proxy Statement of
Baltimore Gas and Electric Company and Potomac Electric Power Company, which was filed as part of
Form S-4 of Constellation Energy Corporation, as amended, which became effective February 9, 1996,
Registration No. 33-64799.)
10(o) -- Severance Agreements between BGE and 15 key employees.
12 -- Computation of Ratio of Earnings to Fixed Charges and Computation of Ratio of Earnings to Combined
Fixed Charges and Preferred and Preference Dividend Requirements.
21 -- Subsidiaries of the Registrant.
23 -- Consent of Coopers & Lybrand L.L.P., Independent Accountants.
27 -- Financial Data Schedule.
*99(a) -- Indemnification of Directors and Officers of the Company. (Designated as Exhibit No. 28(a) to the
Annual Report on Form 10-K for the year ended December 31, 1988, File No. 1-1910.)
*99(b) -- Corporations and Associations Article, Section 2-418 of the Annotated Code of Maryland. (Designated
as Exhibit 28(b) to the Annual Report on Form 10-K for the year ended December 31, 1987, File No.
1-1910.)
*Incorporated by Reference.
(b) Reports on Form 8-K: None.
58
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
COLUMN C
COLUMN B ADDITIONS
BALANCE CHARGED COLUMN E
AT TO BALANCE
BEGINNING COSTS CHARGED TO OTHER COLUMN D AT END
COLUMN A OF AND ACCOUNTS -- (DEDUCTIONS) -- OF
DESCRIPTION PERIOD EXPENSES DESCRIBE DESCRIBE PERIOD
(IN THOUSANDS)
Reserves deducted in the Balance Sheet from
the assets to which they apply:
Accumulated Provision for Uncollectibles
1995.................................... $14,960 $19,170 $ -- $(17,740) $16,390
1994.................................... 13,957 20,557 -- (19,554)(A) 14,960
1993.................................... 12,484 19,155 -- (17,682)(A) 13,957
Valuation Allowance --
Net unrealized (gain) loss on available
for sale securities
1995.................................... 5,609 -- (14,010)(B) -- (8,401 )
1994.................................... -- -- 5,609(B) -- 5,609
1993.................................... -- -- -- -- --
Provision for possible disallowance of
replacement energy costs
1995.................................... 35,000 -- -- -- 35,000
1994.................................... 35,000 -- -- -- 35,000
1993.................................... 35,000 -- -- -- 35,000
Loan loss reserve
1995.................................... -- -- -- -- --
1994.................................... 5,123 -- -- (5,123)(C) --
1993.................................... 4,382 741 -- -- 5,123
Energy projects under development reserves
1995.................................... 1,806 -- -- (1,504)(D) 302
1994.................................... 1,778 28 -- -- 1,806
1993.................................... 492 1,286 -- -- 1,778
(A) Represents principally net amounts charged off as uncollectible.
(B) Represents net unrealized (gains)/losses (credited)/charged to common
shareholders' equity.
(C) Represents reversal of loan loss reserve due to reclassification of this
amount as part of the purchase price of certain real estate partnership
interests.
(D) Represents removal of a reserve associated with an energy project of a
subsidiary which was abandoned.
59
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, Baltimore Gas and Electric Company, the Registrant, has
duly caused this Report to be signed on its behalf by the undersigned, thereunto
duly authorized.
BALTIMORE GAS AND ELECTRIC COMPANY
(REGISTRANT)
By /s/ C. H. POINDEXTER
Date: March 15, 1996
C. H. POINDEXTER
CHAIRMAN OF THE BOARD
Pursuant to the requirements of the Securities Exchange Act of 1934, this
Report has been signed below by the following persons on behalf of Baltimore Gas
and Electric Company, the Registrant, and in the capacities and on the dates
indicated.
SIGNATURE TITLE DATE
Principal executive officer and director:
By /s/ C. H. POINDEXTER Chairman of the Board and Director March 15, 1996
C. H. POINDEXTER
Principal financial and accounting officer:
By /s/ C. W. SHIVERY Vice President and Secretary March 15, 1996
C. W. SHIVERY
Directors:
/s/ H. F. BALDWIN Director March 15, 1996
H. F. BALDWIN
/s/ B. B. BYRON Director March 15, 1996
B. B. BYRON
/s/ J. O. COLE Director March 15, 1996
J. O. COLE
/s/ D. A. COLUSSY Director March 15, 1996
D. A. COLUSSY
/s/ E. A. CROOKE Director March 15, 1996
E. A. CROOKE
/s/ J. R. CURTISS Director March 15, 1996
J. R. CURTISS
/s/ J. W. GECKLE Director March 15, 1996
J. W. GECKLE
/s/ M. L. GRASS Director March 15, 1996
M. L. GRASS
60
/s/ F. A. HRABOWSKI III Director March 15, 1996
F. A. HRABOWSKI III
/s/ N. LAMPTON Director March 15, 1996
N. LAMPTON
/s/ G. V. MCGOWAN Director March 15, 1996
G. V. MCGOWAN
/s/ G. L. RUSSELL, JR. Director March 15, 1996
G. L. RUSSELL, JR.
/s/ M. D. SULLIVAN Director March 15, 1996
M. D. SULLIVAN
61
EXHIBIT INDEX
EXHIBIT
NUMBER
*2(a) -- Agreement and Plan of Merger dated as of September 22, 1995, by and among Baltimore Gas and Electric
Company, Potomac Electric Power Company, and RH Acquisition Corp. (Designated as Exhibit A in the
Joint Proxy Statement of Baltimore Gas and Electric Company and Potomac Electric Power Company, which
was filed as part of Form S-4 of Constellation Energy Corporation, as amended, which became effective
February 9, 1996, Registration No. 33-64799.)
*2(b) -- BGE Stock Option Agreement dated as of September 22, 1995, by and between Baltimore Gas and Electric
Company and Potomac Electric Power Company. (Designated as Exhibit B1 in the Joint Proxy Statement of
Baltimore Gas and Electric Company and Potomac Electric Power Company, which was filed as part of
Form S-4 of Constellation Energy Corporation, as amended, which became effective February 9, 1996,
Registration No. 33-64799.)
*2(c) -- PEPCO Stock Option Agreement dated as of September 22, 1995, by and between Baltimore Gas and
Electric Company and Potomac Electric Power Company. (Designated as Exhibit B2 in the Joint Proxy
Statement of Baltimore Gas and Electric Company and Potomac Electric Power Company, which was filed
as part of Form S-4 of Constellation Energy Corporation, as amended, which became effective February
9, 1996, Registration No. 33-64799.)
*2(d) -- Registration Statement on Form S-4 of Constellation Energy Corporation, as amended, which became
effective February 9, 1996, Registration No. 33-64799.
*3(a) -- Charter of BGE, restated as of April 25, 1995. (Designated as Exhibit No. 3(a) in Form 10-Q dated May
11, 1995, File No. 1-1910.)
*3(b) -- Articles Supplementary, dated as of September 5, 1995, to the Charter of BGE. (Designated as Exhibit
No. 3 in Form 10-Q dated November 13, 1995, File No. 1-1910.)
*3(c) -- By-Laws of BGE, as amended to April 18, 1995. (Designated as Exhibit No. 3(b) in Form 10-Q dated May
11, 1995, File No. 1-1910.)
*4(a) -- Supplemental Indenture between BGE and Bankers Trust Company, as Trustee, dated as of June 20, 1995,
supplementing, amending and restating Deed of Trust dated February 1, 1919. (Designated as Exhibit
No. 4 in Form 10-Q dated August 11, 1995, File No. 1-1910.); and the following Supplemental
Indentures between BGE and Bankers Trust Company, Trustee:
DESIGNATED IN
EXHIBIT
DATED FILE NO. NUMBER
*April 15, 1966 2-26278 4-3
*August 1, 1967 1-1910 (Form 10-K Annual Report for 1967) D-1
*July 1, 1972 2-45452 2-3
*July 15, 1977 2-59772 2-3
(3 Indentures)
*October 15, 1989 1-1910 (Form 10-Q dated November 14, 1989) 4(a)
*August 15, 1991 33-45259 (Form S-3 Registration) 4(a)(i)
*January 15, 1992 33-45259 (Form S-3 Registration) 4(a)(ii)
*July 1, 1992 1-1910 (Form 8-K Report for January 29, 1993) 4(a)
*February 15, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(i)
*March 1, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(ii)
*March 15, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(iii)
*April 15, 1993 1-1910 (Form 10-Q dated May 13, 1993) 4
*July 1, 1993 1-1910 (Form 10-Q dated August 13, 1993) 4(a)
*July 15, 1993 1-1910 (Form 10-Q dated August 13, 1993) 4(b)
*October 15, 1993 1-1910 (Form 10-Q dated November 12, 1993) 4
*March 15, 1994 1-1910 (Form 10-K Annual Report for 1993) 4(a)
*4(b) -- Indenture dated July 1, 1985, between BGE and The Bank of New York (Successor to Mercantile- Safe
Deposit and Trust Company), Trustee. (Designated in Registration File No. 2-98443 as Exhibit
4(a)); as supplemented by Supplemental Indentures dated as of October 1, 1987 (Designated in Form
8-K, dated November 13, 1987, File No. 1-1910 as Exhibit 4(a)) and as of January 26, 1993
(Designated in Form 8-K, dated January 29, 1993, File No. 1-1910 as Exhibit 4(b).)
*10(a) -- Baltimore Gas and Electric Company Executive Benefits Plan, as amended and restated. (Designated
as Exhibit No. 10 in Form 10-Q dated August 11, 1995, File No. 1-1910.)
62
*10(b) -- Executive Incentive Plan of the Baltimore Gas and Electric Company. (Designated as Exhibit No.
10(b) to the Annual Report on Form 10-K for the year ended December 31, 1992, File No. 1-1910.)
*10(c) -- Baltimore Gas and Electric Company 1995 Long-Term Incentive Plan. (Designated as Exhibit No. 10(c)
to the Annual Report on Form 10-K for the year ended December 31, 1994, File No. 1-1910.)
*10(d) -- Baltimore Gas and Electric Company Non-qualified Deferred Compensation Plan for Executive
Officers. (Designated as Exhibit No. 10(d) to the Annual Report on Form 10-K for the year ended
December 31, 1992, File No. 1-1910.)
*10(e) -- Baltimore and Gas and Electric Company Non-qualified Deferred Compensation Plan for Non-Employee
Directors (formerly Baltimore Gas and Electric Company Deferred Compensation Plan for Non-Employee
Directors). (Designated as Exhibit No. 10(f) to the Annual Report on Form 10-K for the year ended
December 31, 1993, File No. 1-1910.)
*10(f) -- Baltimore Gas and Electric Company Retirement Plan for Non-Employee Directors, as amended and
restated. (Designated as Exhibit No. 10(f) to the Annual Report on Form 10-K for the year ended
December 31, 1994, File No. 1-1910.)
*10(g) -- Summary of Baltimore Gas and Electric Company Long Term Performance Program. (Designated as
Exhibit No. 10(h) to the Annual Report on Form 10-K for the year ended December 31, 1993, File No.
1-1910.)
*10(h) -- Grantor Trust Agreement Dated as of July 31, 1994 between Baltimore Gas and Electric Company and
Citibank, N.A. (Designated as Exhibit No. 10(h) to the Annual Report on Form 10-K for the year
ended December 31, 1994, File No. 1-1910.)
*10(i) -- Constellation Holdings, Inc., Summary of Amended Executive Benefits Plan. (Designated as Exhibit
No. 10(i) to the Annual Report on Form 10-K for the year ended December 31, 1994, File No.
1-1910.)
*10(j) -- Summary of Constellation Holdings, Inc. Annual Incentive Plan. (Designated as Exhibit No. 10(g) to
the Annual Report on Form 10-K for the year ended December 31, 1992, File No. 1-1910.)
*10(k) -- Amended Summary 1992 Long Term Incentive Plan of Constellation Holdings, Inc. (Designated as
Exhibit No. 10(k) to the Annual Report on Form 10-K for the year ended December 31, 1993, File No.
1-1910.)
*10(l) -- Summary 1994-96 Long Term Incentive Plan of Constellation Holdings, Inc. (Designated as Exhibit
No. 10(l) to the Annual Report on Form 10-K for the year ended December 31, 1994, File No.
1-1910.)
*10(m) -- Employment Agreement of Christian H. Poindexter. (Designated as Exhibit C2 in the Joint Proxy
Statement of Baltimore Gas and Electric Company and Potomac Electric Power Company, which was
filed as part of Form S-4 of Constellation Energy Corporation, as amended, which became effective
February 9, 1996, Registration No. 33-64799.)
*10(n) -- Employment Agreement of Edward A. Crooke. (Designated as Exhibit C3 in the Joint Proxy Statement
of Baltimore Gas and Electric Company and Potomac Electric Power Company, which was filed as part
of Form S-4 of Constellation Energy Corporation, as amended, which became effective February 9,
1996, Registration No. 33-64799.)
10(o) -- Severance Agreements between BGE and 15 key employees.
12 -- Computation of Ratio of Earnings to Fixed Charges and Computation of Ratio of Earnings to Combined
Fixed Charges and Preferred and Preference Dividend Requirements.
21 -- Subsidiaries of the Registrant.
23 -- Consent of Coopers & Lybrand L.L.P., Independent Accountants.
27 -- Financial Data Schedule.
*99(a) -- Indemnification of Directors and Officers of the Company. (Designated as Exhibit No. 28(a) to the
Annual Report on Form 10-K for the year ended December 31, 1988, File No. 1-1910.)
*99(b) -- Corporations and Associations Article, Section 2-418 of the Annotated Code of Maryland.
(Designated as Exhibit 28(b) to the Annual Report on Form 10-K for the year ended December 31,
1987, File No. 1-1910.)
*Incorporated by Reference.
63