FORM 10-Q/A
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended June 30, 1995
Commission file number 1-1910
BALTIMORE GAS AND ELECTRIC COMPANY
- -----------------------------------------------------------------
(Exact name of registrant as specified in its charter)
Maryland 52-0280210
- -----------------------------------------------------------------
(State of incorporation) (IRS Employer Identification No.)
Gas and Electric Building, Charles Center,
Baltimore, Maryland 21201
- -----------------------------------------------------------------
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code 410-783-5920
Not Applicable
- -----------------------------------------------------------------
(Former name, former address and former fiscal year, if changed
since last report)
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months,
and (2) has been subject to such filing requirements for the past
90 days.
Yes X No
Common Stock, without par value - 147,527,114 shares outstanding
on July 31, 1995.
BALTIMORE GAS AND ELECTRIC COMPANY
PART I. FINANCIAL INFORMATION
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
Quarter Ended June 30, Six Months Ended June 30,
1995 1994 1995 1994
(In Thousands, Except Per-Share Amounts)
Revenues
Electric ............................................... $ 504,627 $ 500,177 $ 1,012,451 $ 1,017,325
Gas ....................................................... 67,968 67,885 220,753 273,071
Diversified businesses .................................... 69,905 83,091 127,102 128,443
Total revenues ............................................ 642,500 651,153 1,360,306 1,418,839
Expenses Other Than Interest and Income Taxes
Electric fuel and purchased energy ........................ 133,128 120,960 280,582 247,513
Gas purchased for resale .................................. 29,188 31,582 110,991 158,507
Operations ................................................ 134,593 137,862 266,128 288,001
Maintenance ............................................... 51,362 43,544 88,243 88,991
Diversified businesses - selling, general, and administrati 52,638 68,759 93,746 102,248
Depreciation and amortization ............................. 75,337 67,934 152,015 137,713
Taxes other than income taxes ............................. 45,334 43,734 99,459 96,529
Total expenses other than interest and income taxes ....... 521,580 514,375 1,091,164 1,119,502
Income From Operations ...................................... 120,920 136,778 269,142 299,337
Other Income
Allowance for equity funds used during construction ....... 4,832 5,542 10,201 10,616
Equity in earnings of Safe Harbor Water Power Corporation . 1,108 1,088 2,215 2,178
Net other income and deductions ........................... (3,328) (405) (5,938) 202
Total other income ........................................ 2,612 6,225 6,478 12,996
Income Before Interest and Income Taxes ..................... 123,532 143,003 275,620 312,333
Interest Expense
Interest charges .......................................... 55,333 53,569 110,310 105,769
Capitalized interest ...................................... (3,683) (3,010) (7,167) (5,811)
Allowance for borrowed funds used during construction ..... (2,614) (2,998) (5,519) (5,739)
Net interest expense ...................................... 49,036 47,561 97,624 94,219
Income Before Income Taxes .................................. 74,496 95,442 177,996 218,114
Income Taxes
Current ................................................... 7,946 10,742 4,913 23,886
Deferred .................................................. 17,689 20,033 55,395 49,456
Investment tax credit adjustments ......................... (2,028) (2,041) (4,055) (4,081)
Total income taxes ........................................ 23,607 28,734 56,253 69,261
Net Income .................................................. 50,889 66,708 121,743 148,853
Preferred and Preference Stock Dividends .................... 9,952 10,021 19,904 20,052
Earnings Applicable to Common Stock ...................... $ 40,937 $ 56,687 $ 101,839 $ 128,801
Average Shares of Common Stock Outstanding ................. 147,527 146,947 147,527 146,692
Total Earnings Per Share of Common Stock .................... $0.28 $0.39 $0.69 $0.88
Dividends Declared Per Share of Common Stock ................ $0.39 $0.38 $0.77 $0.75
Certain prior-year amounts have been reclassified to conform with the current year's presentation.
See Notes to Consolidated Financial Statements.
PART I. FINANCIAL INFORMATION (Continued)
CONSOLIDATED BALANCE SHEETS June 30, December 31,
1995 * 1994
(In Thousands)
ASSETS
Current Assets
Cash and cash equivalents ................................... $ 27,234 $ 38,590
Accounts receivable (net of allowance for uncollectibles).... 330,587 314,842
Fuel stocks ................................................... 64,285 70,627
Materials and supplies ........................................ 150,321 149,614
Prepaid taxes other than income taxes ......................... 2,798 57,740
Other ......................................................... 72,930 47,022
Total current assets .......................................... 648,155 678,435
Investments and Other Assets
Real estate projects .......................................... 477,132 471,435
Power generation systems ...................................... 329,331 311,960
Financial investments ......................................... 206,186 224,340
Nuclear decommissioning trust fund ............................ 77,510 66,891
Safe Harbor Water Power Corporation ........................... 34,183 34,168
Senior living facilities ...................................... 12,749 11,540
Other ........................................................ 58,153 58,824
Total investments and other assets ............................ 1,195,244 1,179,158
Utility Plant
Plant in service
Electric .................................................... 6,217,995 5,929,996
Gas ......................................................... 659,652 616,823
Common ...................................................... 521,035 511,016
Total plant in service ...................................... 7,398,682 7,057,835
Accumulated depreciation ......................................(2,405,132) (2,305,372)
Net plant in service .......................................... 4,993,550 4,752,463
Construction work in progress ................................. 308,861 506,030
Nuclear fuel (net of amortization) ............................ 127,497 134,012
Plant held for future use ..................................... 24,692 24,320
Net utility plant ............................................. 5,454,600 5,416,825
Deferred Charges
Regulatory assets ............................................. 754,457 773,034
Other deferred charges ........................................ 91,129 96,086
Total deferred charges ........................................ 845,586 869,120
TOTAL ASSETS .................................................. $ 8,143,585 $ 8,143,538
* Unaudited
See Notes to Consolidated Financial Statements.
PART I. FINANCIAL INFORMATION (Continued)
CONSOLIDATED BALANCE SHEETS June 30, December 31,
1995 * 1994
(In Thousands)
LIABILITIES AND CAPITALIZATION
Current Liabilities
Short-term borrowings ....................................... $ 113,500 $ 63,700
Current portions of long-term debt and preference stock ....... 359,373 323,675
Accounts payable .............................................. 128,786 181,931
Customer deposits ............................................. 25,955 24,891
Accrued taxes ................................................. 2,129 19,585
Accrued interest .............................................. 61,797 60,348
Dividends declared ............................................ 67,487 66,012
Accrued vacation costs ........................................ 33,449 30,917
Other ......................................................... 16,814 30,857
Total current liabilities ..................................... 809,290 801,916
Deferred Credits and Other Liabilities
Deferred income taxes ......................................... 1,218,083 1,156,429
Deferred investment tax credits ............................... 145,409 149,394
Pension and postemployment benefits ........................... 131,218 138,835
Decommissioning of federal uranium enrichment facilities ...... 45,637 45,836
Other ......................................................... 52,095 59,645
Total deferred credits and other liabilities .................. 1,592,442 1,550,139
Capitalization
Long-term Debt
First refunding mortgage bonds of BGE ......................... 1,744,385 1,744,385
Other long-term debt of BGE ................................... 544,550 544,550
Long-term debt of Constellation Companies ..................... 566,008 575,765
Unamortized discount and premium .............................. (16,540) (17,593)
Current portion of long-term debt ............................. (296,373) (262,175)
Total long-term debt .......................................... 2,542,030 2,584,932
Preferred Stock ................................................. 59,185 59,185
Redeemable Preference Stock ..................................... 341,000 341,000
Current portion of redeemable preference stock ................ (63,000) (61,500)
Total redeemable preference stock ............................. 278,000 279,500
Preference Stock Not Subject to Mandatory Redemption ............ 150,000 150,000
Common Shareholders' Equity
Common stock .................................................. 1,425,460 1,425,378
Retained earnings ............................................. 1,300,899 1,312,655
Pension liability adjustment ................................ (16,521) (16,521)
Net unrealized gain/(loss) on available-for-sale securities . 2,800 (3,646)
Total common shareholders' equity ............................. 2,712,638 2,717,866
Total capitalization .......................................... 5,741,853 5,791,483
TOTAL LIABILITIES AND CAPITALIZATION .......................... $ 8,143,585 $ 8,143,538
* Unaudited
See Notes to Consolidated Financial Statements.
PART I. FINANCIAL INFORMATION (Continued)
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Six Months Ended June 30,
1995 1994
(In Thousands)
Cash Flows From Operating Activities
Net income ................................................... $ 121,743 $ 148,853
Adjustments to reconcile to net cash provided by operating activities
Depreciation and amortization .............................. 180,168 161,641
Deferred income taxes ...................................... 55,440 49,456
Investment tax credit adjustments .......................... (4,055) (4,081)
Deferred fuel costs ........................................ 19,978 (2,972)
Accrued pension and postemployment benefits ................ (11,504) (53,833)
Allowance for equity funds used during construction......... (10,201) (10,616)
Equity in earnings of affiliates and joint ventures (5,579) (1,697)
Changes in current assets, other than sale of accounts receivable ... 23,776 36,880
Changes in current liabilities, other than short-te......... (80,720) (80,522)
Other ...................................................... 15 17,672
Net cash provided by operating activities .................... 289,061 260,781
Cash Flows From Financing Activities
Proceeds from issuance of
Short-term borrowings (net) ................................ 49,800 94,800
Long-term debt ............................................. 10,694 203,018
Common stock ............................................... 83 22,945
Reacquisition of long-term debt .............................. (20,451) (213,319)
Redemption of preference stock ............................... - (1,500)
Common stock dividends paid .................................. (112,120) (108,234)
Preferred and preference stock dividends paid ................ (19,904) (19,964)
Other ........................................................ (810) (36)
Net cash used in financing activities ........................ (92,708) (22,290)
Cash Flows From Investing Activities
Utility construction expenditures ............................ (176,680) (227,091)
Allowance for equity funds used during construction .......... 10,201 10,616
Nuclear fuel expenditures .................................... (16,310) (35,078)
Deferred nuclear expenditures ................................ - (4,066)
Deferred energy conservation expenditures .................... (18,869) (18,661)
Contributions to nuclear decommissioning trust fund .......... (4,890) (4,890)
Purchases of marketable equity securities .................... (6,759) (31,076)
Sales of marketable equity securities ........................ 32,169 20,146
Other financial investments .................................. 3,869 (676)
Real estate projects ......................................... (4,473) 25,090
Power generation systems ..................................... (16,458) (5,066)
Other ........................................................ (9,509) (2,303)
Net cash used in investing activities ........................ (207,709) (273,055)
.........
Net Decrease in Cash and Cash Equivalents ...................... (11,356) (34,564)
Cash and Cash Equivalents at Beginning of Period ...... 38,590 84,236
.........
Cash and Cash Equivalents at End of Period ............ $ 27,234 $ 49,672
Other Cash Flow Information
Cash paid during the period for: .........
Interest (net of amounts capitalized) ...................... $ 95,233 $ 89,395
Income taxes ............................................... $ 45,075 $ 41,025
See Notes to Consolidated Financial Statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Results for interim periods, which can be largely influenced
by weather conditions, are not necessarily indicative of results
to be expected for the year.
The preceding interim financial statements of Baltimore Gas
and Electric Company (BGE) and Subsidiaries (collectively, the
Company) reflect all adjustments which are, in the opinion of
Management, necessary for the fair presentation of the Company's
financial position and results of operations for such interim
periods. These adjustments are of a normal recurring nature.
Statement of Financial Accounting Standards No. 121
In March 1995, the Financial Accounting Standards Board
issued Statement of Financial Accounting Standards (SFAS) No. 121
regarding accounting for asset impairments. This statement,
which must be adopted by the Company by January 1, 1996, requires
the Company to review long-lived assets for impairment whenever
events or changes in circumstances indicate that the carrying
amount of an asset may not be recoverable. Additionally, the
statement requires rate-regulated companies to write-off
regulatory assets against earnings whenever those assets no
longer meet the criteria for recognition of a regulatory asset as
defined by SFAS No. 71, Accounting for the Effects of Certain
Types of Regulation. Adoption of SFAS No. 121 is not expected to
have a material impact on the Company's financial statements.
BGE Financing Activity
No issuances or early redemptions of long-term debt or
preference stock have occurred or have been announced during the
period January 1, 1995 through the date of this Report except for
First Refunding Mortgage Bonds redeemed through operation of the
annual sinking fund as required by BGE's mortgage. Through
August 1, 1995, BGE has redeemed $5,025,000 principal amount of
the 8.40% Series due October 15, 1999, $1,333,000 of the 7-1/2%
Series due January 15, 2007, and $857,000 from various other
series. In addition, on August 28, 1995, BGE will redeem $10,033,000
principal amount of the 7-1/8% Series due January 1, 2002 to
complete the sinking fund.
Diversified Business Financing Matters
See Management's Discussion and Analysis of Financial
Condition and Results of Operations - Diversified Businesses
Capital Requirements for additional information about the debt of
Constellation Holdings, Inc. and its subsidiaries.
Environmental Matters
The Clean Air Act of 1990 (the Act) contains two titles
designed to reduce emissions of sulfur dioxide and nitrogen oxide
(NOx) from electric generating stations. Title IV contains
provisions for compliance in two separate phases. Phase I of
Title IV became effective January 1, 1995, and Phase II of Title
IV must be implemented by 2000. BGE met the requirements of
Phase I by installing flue gas desulfurization systems and fuel
switching and through unit retirements. BGE is currently
examining what actions will be required in order to comply with
Phase II of the Act. However, BGE anticipates that compliance
will be attained by some combination of fuel switching, flue gas
desulfurization, unit retirements, or allowance trading.
At this time, plans for complying with NOx control
requirements under Title I of the Act are less certain because
all implementation regulations have not yet been finalized by the
government. It is expected that by the year 1999 these
regulations will require additional NOx controls for ozone
attainment at BGE's generating plants and at other BGE
facilities. The controls will result in additional expenditures
that are difficult to predict prior to the issuance of such
regulations. Based on existing and proposed ozone nonattainment
regulations, BGE currently estimates that the NOx controls at
BGE's generating plants will cost approximately $90 million. BGE
is currently unable to predict the cost of compliance with the
additional requirements at other BGE facilities.
BGE has been notified by the Environmental Protection Agency
and several state agencies that it is being considered a
potentially responsible party with respect to the cleanup of
certain environmentally contaminated sites owned and operated by
third parties. In addition, a subsidiary of Constellation
Holdings, Inc. has been named as a defendant in a case concerning
an alleged environmentally contaminated site owned and operated
by a third party. Cleanup costs for these sites cannot be
estimated, except that BGE's 15.79% share of the possible cleanup
costs at one of these sites, Metal Bank of America, a metal
reclaimer in Philadelphia, could exceed amounts recognized by up
to approximately $14 million based on the highest estimate of
costs in the range of reasonably possible alternatives. Although
the cleanup costs for certain of the remaining sites could be
significant, BGE believes that the resolution of these matters
will not have a material effect on its financial position or
results of operations.
Also, BGE is coordinating investigation of several former gas
manufacturing plant sites, including exploration of corrective
action options to remove tar. However, no formal legal
proceedings have been instituted against BGE. BGE has recognized
estimated environmental costs at these sites totaling $38.6
million as of March 31, 1995. These costs, net of accumulated
amortization, have been deferred as a regulatory asset. The
technology for cleaning up such sites is still developing, and
potential remedies for these sites have not been identified.
Cleanup costs in excess of the amounts recognized, which could be
significant in total, cannot presently be estimated.
Nuclear Insurance
An accident or an extended outage at either unit of the
Calvert Cliffs Nuclear Power Plant could have a substantial
adverse effect on BGE. The primary contingencies resulting from
an incident at the Calvert Cliffs plant would involve the
physical damage to the plant, the recoverability of replacement
power costs, and BGE's liability to third parties for property
damage and bodily injury. BGE maintains various insurance
policies for these contingencies. The costs that could result
from a major accident or an extended outage at either of the
Calvert Cliffs units could exceed the coverage limits.
In addition, in the event of an incident at any commercial
nuclear power plant in the country, BGE could be assessed for a
portion of any third party claims associated with the incident.
Under the provisions of the Price Anderson Act, the limit for
third party claims from a nuclear incident is $8.92 billion. If
third party claims relating to such an incident exceed $200
million (the amount of primary insurance), BGE's share of the
total liability for third party claims could be up to $159
million per incident, that would be payable at a rate of $20
million per year.
BGE and other operators of commercial nuclear power plants
in the United States are required to purchase insurance to cover
claims of certain nuclear workers. Other non-governmental
commercial nuclear facilities may also purchase such insurance.
Coverage of up to $400 million is provided for claims against BGE
or others insured by these policies for radiation injuries. If
certain claims were made under these policies, BGE and all
policyholders could be assessed, with BGE's share being up to
$6.08 million in any one year.
For physical damage to Calvert Cliffs, BGE has $2.75
billion of property insurance, including $1.9 billion from
industry mutual insurance companies.
If an outage at Calvert Cliffs is caused by an insured
physical damage loss and lasts more than 21 weeks, BGE has up to
$473.2 million per unit of insurance, provided by the same
industry mutual insurance company, for replacement power costs.
This amount can be reduced by up to $94.6 million per unit if an
outage to both units at Calvert Cliffs is caused by a singular
insured physical damage loss.
If accidents at any insured plants cause a shortfall of
funds at the industry mutual, BGE and all policyholders could be
assessed, with BGE's share being up to $32.89 million.
Recoverability of Electric Fuel Costs
By statute, actual electric fuel costs are recoverable so
long as the Public Service Commission of Maryland (PSC) finds
that BGE demonstrates that, among other things, it has maintained
the productive capacity of its generating plants at a reasonable
level. The PSC and Maryland's highest appellate court have
interpreted this as permitting a subjective evaluation of each
unplanned outage at BGE's generating plants to determine whether
or not BGE had implemented all reasonable and cost-effective
maintenance and operating control procedures appropriate for
preventing the outage. Effective January 1, 1987, the PSC
authorized the establishment of a Generating Unit Performance
Program (GUPP) to measure, annually, utility compliance with
maintaining the productive capacity of generating plants at
reasonable levels by establishing a system-wide generating
performance target and individual performance targets for each
base load generating unit. In future fuel rate hearings, actual
generating performance after adjustment for planned outages will
be compared to the system-wide target and, if met, should signify
that BGE has complied with the requirements of Maryland law.
Failure to meet the system-wide target will result in review of
each unit's adjusted actual generating performance versus its
performance target in determining compliance with the law and the
basis for possibly imposing a penalty on BGE. Parties to fuel
rate hearings may still question the prudence of BGE's actions or
inactions with respect to any given generating plant outage,
which could result in the disallowance of replacement energy
costs by the PSC.
Since the two units at BGE's Calvert Cliffs Nuclear Power
Plant utilize BGE's lowest cost fuel, replacement energy costs
associated with outages at these units can be significant. BGE
cannot estimate the amount of replacement energy costs that could
be challenged or disallowed in future fuel rate proceedings, but
such amounts could be material.
In October 1988, BGE filed its first fuel rate application
for a change in its electric fuel rate under GUPP. The resultant
case before the PSC covers BGE's operating performance in
calendar year 1987, and BGE's filing demonstrated that it met the
system-wide and individual nuclear plant performance targets for
1987. In November 1989, testimony was filed on behalf of the
Maryland People's Counsel (People's Counsel) alleging that seven
outages at the Calvert Cliffs plant in 1987 were due to
management imprudence and that the replacement energy costs
associated with those outages should be disallowed by the
Commission. Total replacement energy costs associated with the
1987 outages were approximately $33 million.
In May 1989, BGE filed its fuel rate case in which 1988
performance was examined. BGE met the system-wide and nuclear
plant performance targets in 1988. People's Counsel alleged that
BGE imprudently managed several outages at Calvert Cliffs, and
BGE estimates that the total replacement energy costs associated
with these 1988 outages were approximately $2 million. On
November 14, 1991, a Hearing Examiner at the PSC issued a
proposed Order, which became final on December 17, 1991 and
concluded that no disallowance was warranted. The Hearing
Examiner found that BGE maintained the productive capacity of the
Plant at a reasonable level, noting that it produced a near
record amount of power and exceeded the GUPP standard. Based on
this record, the Order concluded there was sufficient cause to
excuse any avoidable failures to maintain productive capacity at
higher levels.
During 1989, 1990, and 1991, BGE experienced extended
outages at its Calvert Cliffs Nuclear Power Plant. In the Spring
of 1989, a leak was discovered around the Unit 2 pressurizer
heater sleeves during a refueling outage. BGE shut down Unit 1
as a precautionary measure on May 6, 1989, to inspect for similar
leaks and none were found. However, Unit 1 was out of service
for the remainder of 1989 and 285 days of 1990 to undergo
maintenance and modification work to enhance the reliability of
various safety systems, to repair equipment, and to perform
required periodic surveillance tests. Unit 2, which returned to
service on May 4, 1991, remained out of service for the remainder
of 1989, 1990, and the first part of 1991 to repair the
pressurizer, perform maintenance and modification work, and
complete the refueling. The replacement energy costs associated
with these extended outages for both units at Calvert Cliffs,
concluding with the return to service of Unit 2, are estimated to
be $458 million.
In a December 1990 order issued by the PSC in a BGE base
rate proceeding, the PSC found that certain operations and
maintenance expenses incurred at Calvert Cliffs during the test
year should not be recovered from ratepayers. The PSC found that
this work, which was performed during the 1989-1990 Unit 1 outage
and fell within the test year, was avoidable and caused by BGE
actions which were deficient.
The PSC noted in the order that its review and findings on
these issues pertain to the reasonableness of BGE's test-year
operations and maintenance expenses for purposes of setting base
rates and not to the responsibility for replacement power costs
associated with the outages at Calvert Cliffs. The PSC stated
that its decision in the base rate case will have no res judicata
(binding) effect in the fuel rate proceeding examining the 1989-
1991 outages. The work characterized as avoidable significantly
increased the duration of the Unit 1 outage. Despite the PSC's
statement regarding no binding effect, BGE recognizes that the
views expressed by the PSC make the full recovery of all of the
replacement energy costs associated with the Unit 1 outage
doubtful. Therefore, in December 1990, BGE recorded a provision
of $35 million against the possible disallowance of such costs.
BGE cannot determine whether replacement energy costs may be
disallowed in the present fuel rate proceeding in excess of the
provision, but such amounts could be material.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The financial condition and results of operations of
Baltimore Gas and Electric Company (BGE) and its subsidiaries
(collectively, the Company) are set forth in the Consolidated
Financial Statements and Notes to Consolidated Financial
Statements (Notes) sections of this Report. Factors significantly
affecting results of operations, liquidity, and capital resources
are discussed below.
RESULTS OF OPERATIONS FOR THE QUARTER AND SIX MONTHS ENDED JUNE
30, 1995 COMPARED WITH THE CORRESPONDING PERIOD OF 1994
Earnings per Share of Common Stock
Consolidated earnings per share for the quarter and six
months ended June 30, 1995 were $.28 and $.69, respectively,
which represent decreases of $.11 and $.19 compared to the
earnings for the corresponding periods of 1994. These decreases
in earnings per share reflect a lower level of earnings
applicable to common stock. The earnings per share are summarized
as follows:
Quarter Ended Six Months Ended
June 30 June 30
1995 1994 1995 1994
Utility operations $.25 $.38 $.63 $.86
Diversified businesses .03 .01 .06 .02
Total $.28 $.39 $.69 $.88
Earnings Applicable to Common Stock
Earnings applicable to common stock decreased $15.8 million
during the quarter and $27.0 million during the six months ended
June 30, 1995. These decreases reflect lower earnings from
utility operations, partially offset by higher earnings from
diversified businesses.
Earnings from utility operations decreased during the second
quarter of 1995 primarily due to lower electric system sales
resulting from the mild weather in 1995 in contrast to the
extremely hot spring and early summer weather experienced last
year. The effect of weather on utility sales is discussed on
pages 12 and 13. Depreciation and amortization expense also
increased during 1995.
Earnings from utility operations decreased during the six
months ended June 30, 1995 primarily due to lower electric and
gas sales resulting from substantially milder winter weather in
the first quarter of 1995 as compared to 1994. Depreciation and
amortization expense also increased during the six months ended
June 30, 1995, offset partially by lower operations and
maintenance expenses.
The following factors influence BGE's utility operations
earnings: regulation by the Public Service Commission of Maryland
(PSC), the effect of weather and economic conditions on sales,
and competition in the generation and sale of electricity.
Several electric fuel rate cases now pending before the PSC
discussed in Notes 1 and 13 of the Form 10-K for the year ended
December 31, 1994 (Form 10-K) could also affect future years'
earnings.
Electric utilities presently face competition in the
construction of generating units to meet future load growth and
in the sale of electricity in the bulk power markets. Electric
utilities also face the future prospect of competition for
electric sales to retail customers. It is not possible to
predict currently the ultimate effect competition will have on
BGE's earnings in future years. In response to the competitive
forces and regulatory changes, as discussed in Part 1 of the Form
10-K under the heading Regulatory Matters and Competition, BGE
from time to time will consider various strategies designed to
enhance its competitive position and to increase its ability to
adapt to and anticipate regulatory changes in its utility
business. These strategies may include internal restructurings
involving the complete or partial separation of its generation,
transmission and distribution businesses, acquisitions of related
or unrelated businesses, business combinations, and additions to
or dispositions of portions of its franchised service
territories. BGE may from time to time be engaged in preliminary
discussions, either internally or with third parties, regarding
one or more of these potential strategies. No assurances can be
given as to whether any potential transaction of the type
described above may actually occur, or as to the ultimate effect
thereof on the financial condition or competitive position of
BGE.
Earnings from diversified businesses, which primarily
represent the operations of Constellation Holdings, Inc. and its
subsidiaries (collectively, the Constellation Companies) and BGE
Home Products & Services, Inc. (HPS) and its subsidiary were
higher during the quarter and six months ended June 30, 1995
compared to the corresponding periods of 1994. Diversified
businesses' earnings are discussed on pages 19 through 21.
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. 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. 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. The degree-days chart below presents
information regarding heating and cooling degree days for the
quarter and six months ended June 30, 1995 and 1994.
Quarter Ended Six Months Ended
June 30 June 30
1995 1994 1995 1994
Heating degree days............ 479 444 2,719 3,196
Percent change compared to
prior period.................. 7.9% (14.9)%
Cooling degree days............ 252 320 252 320
Percent change compared to
prior period.................. (21.0)% (21.0)%
BGE Utility Revenues and Sales
Electric revenues changed for the quarter and six months
ended June 30, 1995 because of the following factors:
Quarter Ended Six Months Ended
June 30 June 30
1995 vs. 1994 1995 vs. 1994
(In millions)
System sales volumes $(11.6) $(35.8)
Base rates 2.4 3.8
Fuel rates (6.9) (15.6)
Revenues from system sales (16.1) (47.6)
Interchange and other sales 18.5 42.7
Other revenues 2.0 0.0
Total $ 4.4 $ (4.9)
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, which are discussed separately. Below is a comparison
of the changes in electric system sales volumes:
Quarter Ended Six Months Ended
June 30 June 30
1995 vs. 1994 1995 vs. 1994
Residential (2.2)% (7.5)%
Commercial (1.6) (1.8)
Industrial (6.6) 2.3
Total (2.7) (3.4)
The decrease in sales to the residential and commercial
classes of electric customers during the second quarter of 1995
is primarily attributable to the mild weather in 1995 as compared
to the extremely hot spring and early summer weather conditions
experienced during the second quarter of 1994. The decrease in industrial
sales was primarily due to lower usage-per-customer. These
decreases were offset partially by moderate customer growth
in all classes.
In addition to the factors noted above for the second
quarter of 1995, electric system sales for the six months ended
June 30, 1995 reflect milder winter weather during 1995 compared
to the extremely cold weather conditions experienced last year.
Sales to industrial customers primarily reflect an increase in
the sale of electricity to Bethlehem Steel, which has been
purchasing its full electricity requirements from BGE since March
of 1994. Bethlehem Steel is still producing power with its own
generating facility, but is now selling the output from this
facility to BGE rather than using the power to reduce its
requirements.
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 for the quarter and six months ended June 30, 1995 due
to the deferral in 1994 of the portion of conservation surcharge
billings subject to refund, as described below.
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 occur. 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, of which $3.9 million occurred during the
quarter ended June 30, 1994 and a total of $8.5 million
occurred during the six months ended June 30, 1994.
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
13 of the Form 10-K.) 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 13 of
the Form 10-K.
Fuel rate revenues were lower for the quarter and six months
ended June 30, 1995 as compared to the same periods in 1994 as a
result of decreased electric system sales volumes and a lower
fuel rate. The fuel rate was lower because of a less costly
twenty-four month generation mix due to greater generation in
1995 at the Calvert Cliffs Nuclear Power Plant and the Brandon
Shores Power Plant. BGE expects electric fuel rate revenues to
decrease slightly during the remainder of 1995 due to a lower
fuel rate.
Interchange and other sales represent sales of BGE's energy
to the Pennsylvania - New Jersey - Maryland Interconnection
(PJM), a regional power pool of eight member companies including
BGE, and sales to other non-PJM utilities. These sales occur
after BGE has satisfied the demand for its own system sales of
electricity, if BGE's available generation is the least costly
available. Interchange and other sales increased for the quarter
and six months ended June 30, 1995 because of 1995 sales to other
utilities and because BGE had a less costly generation mix than
other PJM utilities. This less costly generation mix was due to
greater generation from the Brandon Shores Power Plant and
continued operation of the Calvert Cliffs Nuclear Power Plant.
Gas revenues changed for the quarter and six months ended June
30, 1995 because of the following factors:
Quarter Ended Six Months Ended
June 30 June 30
1995 vs. 1994 1995 vs. 1994
(In millions)
Sales volumes $ 2.3 $ (5.4)
Base rates 0.6 2.0
Gas cost adjustment revenues (2.6) (48.6)
Other revenues (0.2) (0.3)
Total $ 0.1 $(52.3)
Below is a comparison of the changes in gas sales volumes:
Quarter Ended Six Months Ended
June 30 June 30
1995 vs. 1994 1995 vs. 1994
Residential (1.3)% (11.2)%
Commercial 3.0 (5.3)
Industrial 18.9 16.5
Total 8.5 (1.8)
Total gas sales for the second quarter of 1995 increased
compared to last year primarily as a result of higher sales to
commercial and industrial customers. Sales to residential
customers decreased slightly during the second quarter as the
favorable impacts on sales of cooler early spring weather and
moderate customer growth were offset by lower usage-per-customer.
Sales to commercial customers increased slightly during the
second quarter due to the cooler early spring
weather and moderate customer growth, offset partially by lower
usage. Sales to industrial customers increased during the second
quarter due to greater usage of gas by interruptible customers,
including Bethlehem Steel. These customers maintain alternate
fuel sources and pay reduced rates in exchange for BGE's right to
interrupt service during periods of peak demand.
Total gas sales for the six months ended June 30, 1995
decreased slightly as a result of lower sales to residential and
commercial customers, offset partially by an increase in sales to
industrial customers. Sales to residential and commercial
customers decreased due to milder winter weather in 1995 and
lower usage-per-customer, offset partially by an increase in the
number of customers. Sales to industrial customers increased
compared to last year due to greater usage of gas per customer,
including Bethlehem Steel, and fewer customer interruptions in
the first quarter of 1995 due to the milder weather as compared
to the same period last year.
Base rates increased slightly during 1995 due to an
increased recovery of eligible gas conservation program costs
through the energy conservation surcharge. Future gas base rate
revenues may be impacted positively by the Maryland Commission's
anticipated November 1995 order in response to BGE's April 21,
1995 application for $29 million of increased gas base rates.
Changes in gas cost adjustment revenues result primarily
from the operation of the purchased gas adjustment clause,
commodity charge adjustment clause, and the actual cost
adjustment clause which are designed to recover actual gas costs.
(See Note 1 of the Form 10-K.) Changes in gas cost adjustment
revenues normally do not affect earnings.
Gas cost adjustment revenues decreased for the quarter ended
June 30, 1995 because of lower prices for purchased gas, offset
partially by slightly higher sales volumes subject to gas cost
adjustment clauses. Delivery service sales volumes are not
subject to gas cost adjustment clauses because these customers
purchase their gas directly from third parties. Gas cost
adjustment revenues decreased for the six months ended June 30,
1995 because of lower prices for purchased gas and lower sales
volumes subject to gas cost adjustment clauses.
BGE Utility Fuel and Energy Expenses
Electric fuel and purchased energy expenses were as follows:
Quarter Ended Six Months Ended
June 30 June 30
1995 1994 1995 1994
(In millions)
Actual costs $124.9 $119.9 $263.5 $273.2
Net (deferral) recovery of
costs under electric fuel
rate clause (see Note 1 of
the Form 10-K) 8.2 1.1 17.1 (25.7)
Total $133.1 $121.0 $280.6 $247.5
Total electric fuel and purchased energy expenses increased
during the quarter and six months ended June 30, 1995 primarily
as a result of the operation of the electric fuel rate clause.
Actual electric fuel and purchased energy costs increased
slightly for the quarter ended June 30, 1995 as a result of
higher net output of electricity generated and higher purchased
energy costs, offset partially by a less costly generation mix.
Actual electric fuel and purchased energy costs decreased
during the six months ended June 30, 1995 primarily due to a less
costly generation mix resulting primarily from refueling and
maintenance outages at the Calvert Cliffs Nuclear Power Plant
during the first quarter of 1994. This was offset partially by
higher purchased energy and capacity costs during the first six
months of 1995.
Purchased gas expenses were as follows:
Quarter Ended Six Months Ended
June 30 June 30
1995 1994 1995 1994
(In millions)
Actual costs $31.4 $30.5 $118.7 $153.2
Net (deferral) recovery of costs
under purchased gas adjustment
clause (see Note 1 of the
Form 10-K) (2.2) 1.1 (7.7) 5.3
Total $29.2 $31.6 $111.0 $158.5
Total purchased gas expenses decreased slightly for the
quarter ended June 30, 1995 compared to last year primarily due
to the operation of the purchased gas adjustment clause, offset
partially by a small increase in actual gas costs. The slight
increase in actual gas costs reflects $6.5 million of take-or-pay
refunds received during the second quarter of 1994 from Columbia
Gas Transmission Corporation, offset substantially by lower gas
prices during the second quarter of 1995.
Total purchased gas expenses decreased during the six months
ended June 30, 1995 due to significantly lower actual purchased
gas costs and due to the operation of the purchased gas
adjustment clause. Actual purchased gas costs decreased during
the six months ended June 30, 1995 due to the lower output
associated with the decreased demand for BGE gas and lower gas
prices. The decreased demand for BGE gas and the lower gas
prices reflect the significantly milder weather experienced
during the first quarter of 1995 compared to the first quarter of
1994. This decrease is offset partially by the $6.5 million of
take-or-pay refunds received in the second quarter of 1994.
Purchased gas costs exclude gas purchased by delivery
service customers, including Bethlehem Steel, who obtain gas
directly from third parties. Future purchased gas costs are
expected to be increased by transition costs incurred by BGE gas
pipeline suppliers in implementing FERC Order No. 636. These
transition costs, if approved by FERC, will be passed on to BGE
customers through the purchased gas adjustment clause.
Other Operating Expenses
Operations expense decreased for the quarter ended June 30,
1995 due primarily to continuing labor and other savings in 1995
resulting from the Company's ongoing cost control efforts.
In addition to the ongoing cost control efforts noted above,
operations expense for the six months ended June 30, 1995
decreased due to a $10.0 million one-time bonus paid to employees
in the first quarter of 1994 in lieu of a general wage increase
and higher expenses attributable to the winter storms in the
first quarter of 1994. Operations expense is expected to
continue to decline during 1995 due to ongoing cost control
efforts of the Company.
Maintenance expense increased during the quarter ended June
30, 1995 due primarily to higher costs at the Calvert Cliffs
Nuclear Power Plant related to the second quarter 1995 outage.
Maintenance expense for the six months ended June 30, 1995 was
essentially unchanged compared to the prior year.
Depreciation and amortization expense increased during the
quarter and six months ended June 30, 1995 because of higher
depreciable plant in service and the completion of a facility-
specific study of the cost to decommission the Calvert Cliffs
Nuclear Power Plant. This study generated a higher
decommissioning cost than the prior estimate which will increase
depreciation expense by $9 million annually, $4.5 million of
which occurred during the six months ended June 30, 1995. The
increase in depreciable plant in service resulted primarily from
certain capital additions at the Calvert Cliffs Nuclear Power
Plant during 1995.
Other Income and Expenses
Net other income and deductions decreased for the quarter
and six months ended June 30, 1995 due primarily to lower other
interest, dividend and finance charge income.
Interest expense increased for the quarter and six months
ended June 30, 1995 due to a higher level of outstanding debt and
an increase in the level of interest rates, offset partially by
more capitalized interest.
Income tax expense decreased for the quarter and six months
ended June 30, 1995 because of lower taxable income.
Diversified Businesses Earnings
Earnings per share from diversified businesses were:
Quarter Ended Six Months Ended
June 30 June 30
1995 1994 1995 1994
Constellation Holdings, Inc.
Power generation systems $.01 $.00 $.03 $.01
Financial investments .02 .01 .04 .02
Real estate development and
senior living facilities .00 .00 (.01) (.01)
Total Constellation Holdings, Inc..03 .01 .06 .02
BGE Home Products & Services, Inc .00 .00 .00 .00
Total diversified businesses $.03 $.01 $.06 $.02
The Constellation Companies' power generation systems
business includes the development, ownership, management, and
operation of wholesale power generating projects in which the
Constellation Companies hold ownership interests, as well as the
provision of services to power generation projects under
operation and maintenance contracts. Power generation systems
earnings increased for both periods of 1995 due primarily to
higher equity earnings from Constellation Companies' energy
projects.
The Constellation Companies' investment in wholesale power
generating projects includes $180 million representing ownership
interests in 16 projects that sell electricity in California
under Interim Standard Offer No. 4 power purchase agreements.
Under these agreements, the projects supply electricity to
purchasing utilities at a fixed rate for the first ten years of
the agreements and at variable rates based on the utilities'
avoided cost for the remaining term of the agreements. Avoided
cost generally represents a utility's next lowest cost generation
to service the demands on its system. These power generation
projects are scheduled to convert to supplying electricity at
avoided cost rates in various years beginning in late 1996
through the end of 2000. As a result of declines in purchasing
utilities' avoided costs subsequent to the inception of these
agreements, revenues at these projects based on current avoided
cost levels would be substantially lower than revenues presently
being realized under the fixed price terms of the agreements. If
current avoided cost levels were to continue into 1996 and
beyond, the Constellation Companies could experience reduced
earnings or incur losses associated with these projects, which
could be significant. The Constellation Companies are
investigating and pursuing alternatives for certain of these
power generation projects including, but not limited to,
repowering the projects to reduce operating costs, renegotiating
the power purchase agreements, and selling its ownership
interests in the projects. Two of these wholesale power
generating projects, in which the Constellation Companies'
investment totals $26 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.
Earnings from the Constellation Companies' portfolio of
financial investments include capital gains and losses,
dividends, income from financial limited partnerships, and income
from financial guaranty insurance companies. Financial
investment earnings were higher for the quarter and six months
ended June 30, 1995 due to favorable earnings on the Companies'
investment portfolio and realized gains from a financial
partnership.
The Constellation Companies' real estate development
business includes land under development; office buildings;
retail projects; commercial projects; an entertainment, dining
and retail complex in Orlando, Florida; a mixed-use planned-unit-
development; and senior living facilities. The majority of these
projects are in the Baltimore-Washington corridor. They have been
affected adversely by the depressed real estate market and
economic conditions, resulting in reduced demand for the purchase
or lease of available land, office, and retail space. Earnings
from real estate development and senior living facilities for the
quarter and six months ended June 30, 1995 are essentially
unchanged from the prior year.
The Constellation Companies' real estate portfolio has
experienced continuing carrying costs and depreciation.
Additionally, the Constellation Companies have been expensing
rather than capitalizing interest on certain undeveloped land
where development activities were at minimal levels. These
factors have affected earnings negatively and are expected to
continue to do so until the levels of undeveloped land are
reduced. Cash flow from real estate operations has been
insufficient to cover the debt service requirements of certain of
these projects. Resulting cash shortfalls have been satisfied
through cash infusions from Constellation Holdings, Inc., which
obtained the funds through a combination of cash flow generated
by other Constellation Companies and its corporate borrowings.
To the extent the real estate market continues to improve,
earnings from real estate activities are expected to improve
also.
The Constellation Companies continued investment in real
estate projects is a function of market demand, interest rates,
credit availability, and the strength of the economy in general.
The Constellation Companies' Management believes that although
the real estate market has improved, until the economy reflects
sustained growth and the excess inventory in the market in the
Baltimore-Washington corridor goes down, real estate values will
not improve significantly. If the Constellation Companies were to
sell their real estate projects in the current depressed market,
losses would occur in amounts difficult to determine. Depending
upon market conditions, future sales could also result in losses.
In addition, were the Constellation Companies to change their
intent about any project from an intent to hold until market
conditions improve to an intent to sell, applicable accounting
rules would require a write-down of the project to market value
at the time of such change in intent if market value is below
book value.
Environmental Matters
The Company is subject to increasingly stringent federal,
state, and local laws and regulations relating to improving or
maintaining the quality of the environment. These laws and
regulations require the Company to remove or remedy the effect on
the environment of the disposal or release of specified
substances at ongoing and former operating sites, including
Environmental Protection Agency Superfund sites. Details
regarding these matters, including financial information, are
presented in the Environmental Matters section on pages 6, 7 and
25 of this Report.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity
For the twelve months ended June 30, 1995, the Company's
ratio of earnings to fixed charges and ratio of earnings to
combined fixed charges and preferred and preference dividend
requirements were 2.91 and 2.30, respectively.
Capital Requirements
The Company's capital requirements reflect the capital-
intensive nature of the utility business. Actual capital
requirements for the six months ended June 30, 1995, along with
estimated annual amounts for the years 1995 through 1997, are
reflected below.
Six Months Ended
June 30 Calendar Year Estimate
1995 1995 1996 1997
(In millions)
Utility Business:
Construction expenditures
(excluding AFC)
Electric $111 $233 $219 $206
Gas 28 61 71 84
Common 22 56 50 35
Total construction expenditures 161 350 340 325
AFC 16 24 13 10
Nuclear fuel (uranium purchases
and processing charges) 16 48 50 52
Deferred energy conservation
expenditures 19 40 34 25
Retirement of long-term debt
and redemption of preference
stock - 268 98 164
Total utility business 212 730 535 576
Diversified Businesses:
Retirement of long-term debt 10 62 67 118
Investment requirements 36 84 70 40
Total diversified businesses 46 146 137 158
Total $258 $876 $672 $734
BGE Utility Capital Requirements
BGE's construction program is subject to continuous review
and modification, and actual expenditures may vary from the
estimates above. Electric construction expenditures include the
installation of two 5,000 kilowatt diesel generators at Calvert
Cliffs Nuclear Power Plant, one of which was placed in service in
June, 1995 and the second is scheduled to be placed in service in
1996; the construction of a 140-megawatt combustion turbine at
Perryman, which was placed in service in June, 1995; 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 twelve months ended June 30, 1995, the internal
generation of cash from utility operations provided 88% of the
funds required for BGE's capital requirements exclusive of
retirements and redemptions of debt and preference stock. During
the three-year period 1995 through 1997, the Company expects to
provide through utility operations 100% of the funds required for
BGE's capital requirements, exclusive of retirements and
redemptions.
Utility capital requirements not met through the internal
generation of cash are met through the issuance of debt and
equity securities. The amount and timing of issuances and
redemptions depends upon market conditions and BGE's actual
capital requirements. From January 1, 1995 through the date of
this Report, BGE has not issued or redeemed any long-term debt or
equity securities except for the following principal amounts of
First Refunding Mortgage Bonds totaling $17,248,000 that were, or
will be, redeemed through operation of the annual sinking fund as
required by BGE's mortgage: $10,259,000 of the 7-1/8% Series due
January 1, 2002, $5,025,000 of the 8.40% Series due October 15,
1999, $1,333,000 of the 7-1/2% Series due January 15, 2007, and
$631,000 from various other series.
The Constellation Companies' capital requirements are
discussed below in the section titled "Diversified Businesses
Capital Requirements - Debt and Liquidity." The Constellation
Companies are exploring expansion of their energy, real estate
service, and senior living facility businesses. Expansion may be
achieved in a variety of ways, including without limitation
increased investment activity and acquisitions. The Constellation
Companies plan to meet their capital requirements with a
combination of debt and internal generation of cash from their
operations. Additionally, from time to time, BGE may make loans
to Constellation Holdings, Inc., or contribute equity to enhance
the capital structure of Constellation Holdings, Inc.
Historically, Constellation's energy projects have been in
the United States. Recently one of the Constellation Companies
has invested about $9 million for an investment in Bolivia.
Constellation's energy business expansion may include domestic
and international projects.
Diversified Businesses Capital Requirements
Debt and Liquidity
The Constellation Companies intend to meet capital
requirements by refinancing debt as it comes due and through
internally generated cash. These internal sources include cash
that may be generated from operations, sale of assets, and cash
generated by tax benefits earned by the Constellation Companies.
In the event the Constellation Companies can obtain reasonable
value for real estate properties, additional cash may become
available through the sale of projects (for additional
information see the discussion of the real estate business and
market on pages 19 to 21 under the heading "Diversified
Businesses Earnings"). The ability of the Constellation
Companies to sell or liquidate assets described above will depend
on market conditions, and no assurances can be given that such
sales or liquidations can be made. Also, to provide additional
liquidity to meet interim financial needs, CHI has a $50 million
revolving credit agreement.
Investment Requirements
The investment requirements of the Constellation Companies
include its portion of equity funding to committed projects under
development, as well as net loans made to project partnerships.
Investment requirements for the years 1995 through 1997 reflect
the Constellation Companies' estimate of funding for ongoing and
anticipated projects and are subject to continuous review and
modification. Actual investment requirements may vary
significantly from the estimates on page 22 because of the type
and number of projects selected for development, the impact of
market conditions on those projects, the ability to obtain
financing, and the availability of internally generated cash.
The Constellation Companies have met their investment
requirements in the past through the internal generation of cash
and through borrowings from institutional lenders.
PART II. OTHER INFORMATION
ITEM 1. Legal Proceedings
Asbestos
During 1993 and 1994, 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.
Approximately 482 non-employee plaintiffs each claim $6 million
in damages ($2 million compensatory and $4 million punitive).
BGE does not know the specific facts necessary for BGE to assess
its potential liability for these type claims, such as the
identity of the BGE facilities at which the plaintiffs allegedly
worked as contractors, the names of the plaintiffs' employers,
and the date on which the exposure allegedly occurred.
The second type are claims by two manufacturers - Owens
Corning Fiberglas and Pittsburgh Corning Corp. - against BGE and
approximately eight others, as third-party defendants. These
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.
Environmental Matters
The Company's potential environmental liabilities and pending
environmental actions are listed in Item 1. Business -
Environmental Matters of the Form 10-K.
PART II. OTHER INFORMATION (Continued)
ITEM 4. Submission of Matters to a Vote of Security Holders
On April 18, 1995, BGE held its annual meeting of shareholders.
At that meeting, the following matters were voted upon:
1. All of the Directors nominated by BGE were selected as
follows:
COMMON SHARES CAST:
For Against Abstain
H. Furlong Baldwin 122,615,841 1,009,297 2,041,581
Beverly B. Byron 122,247,281 1,383,975 2,041,581
J. Owen Cole 122,760,885 870,772 2,041,581
Dan A. Colussy 122,937,955 693,552 2,041,581
Edward A. Crooke 122,526,564 1,099,173 2,041,581
James R. Curtiss 122,703,605 927,651 2,041,581
Jerome W. Geckle 122,753,494 878,162 2,041,581
Martin L. Grass 122,721,831 909,695 2,041,581
Freeman A. Hrabowski 122,421,604 1,205,603 2,041,581
Nancy Lampton 122,742,838 888,419 2,041,581
George V. McGowan 122,483,298 1,148,358 2,041,581
Christian H. Poindexter 121,875,308 1,756,199 2,041,581
George L. Russell, Jr. 122,114,706 1,512,501 2,041,581
Michael D. Sullivan 121,905,351 1,725,905 2,041,581
2. Coopers and Lybrand was reelected as auditor, and with respect
to holders of common stock, the number of affirmative votes
cast were 123,619,072. The number of negative votes cast were
1,069,269, and the number of abstentions were 1,115,462.
3. BGE's implementation of the 1995 Long-Term Incentive Plan was
approved. With respect to holders of common stock, the number
of affirmative votes cast for the proposal was 106,571,348,
the number of negative votes cast for the proposal was
16,210,671, and the number of abstentions was 3,022,172.
PART II. OTHER INFORMATION (Continued)
4. The amendment to BGE's Charter to allow for uncertificated
securities was approved. With respect to holders of common
stock, the number of affirmative votes cast for the amendment
was 100,443,914 the number of negative votes cast for the
amendment was 7,343,275, and the number of abstentions was
3,435,234. With respect to holders of preferred stock, the
number of affirmative votes cast for the amendment was
9,853,560, the number of negative votes cast for the amendment
was 1,057,800, and the number of abstentions was 209,112.
5. The amendment to BGE's Charter to allow for Preference Stock
with variable terms was approved. With respect to holders of
common stock, the number of affirmative votes cast for the
amendment was 98,512,153 the number of negative votes cast for
the amendment was 9,170,662, and the number of abstentions was
3,522,275. With respect to holders of preferred stock, the
number of affirmative votes cast for the amendment was
9,875,976, the number of negative votes cast for the amendment
was 1,002,144, and the number of abstentions was 242,352.
With respect to holders of preference stock, the number of
affirmative votes cast for the amendment was 3,435,570, the
number of negative votes cast for the amendment was 509,061,
and the number of abstentions was 13,234.
6. The shareholder proposal requesting that the Board of
Directors refrain from providing retirement benefits to non-
employee directors, unless the benefits are submitted for
shareholder approval was defeated. With respect to holders of
common stock, the number of affirmative votes cast for the
proposal was 38,436,952, the number of negative votes cast for
the proposal was 67,025,435, and the number of abstentions was
4,636,104.
PART II. OTHER INFORMATION (Continued)
ITEM 6. Exhibits and Reports on Form 8-K
(a) Exhibit No. 4 Supplemental Indenture between BGE
and Bankers Trust Company, as
Trustee, dated as of June 20, 1995.
Exhibit No. 10 Baltimore Gas and Electric Company
Executive Benefits Plan, as amended
and restated.
Exhibit No. 12 Computation of Ratio of Earnings to
Fixed Charges and Computation of
Ratio of Earnings to Combined Fixed
Charges and Preferred and
Preference Dividend Requirements.
Exhibit No. 27 Financial Data Schedule.
(b) Form 8-K None
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act
of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned thereunto duly authorized.
BALTIMORE GAS AND ELECTRIC COMPANY
(Registrant)
Date August 11, 1995 /s/ C. W. Shivery
C. W. Shivery, Vice President
on behalf of the Registrant and
as Principal Financial Officer
EXHIBIT INDEX
Exhibit
Number
4 Supplemental Indenture between BGE and
Bankers Trust Company, as Trustee, dated
as of June 20, 1995.
10 Baltimore Gas and Electric Company
Executive Benefits Plan, as amended and
restated.
12 Computation of Ratio of Earnings to
Fixed Charges and Computation of Ratio
of Earnings to Combined Fixed Charges
and Preferred and Preference Dividend
Requirements.
27 Financial Data Schedule.