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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-Mary