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FORM 10-Q
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 September 30, 1995
Commission file number 1-1910
BALTIMORE GAS AND ELECTRIC COMPANY
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(Exact name of registrant as specified in its charter)
Maryland 52-0280210
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(State of incorporation) (IRS Employer Identification No.)
39 W. Lexington Street Baltimore, Maryland 21201
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code 410-783-5920
Not Applicable
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(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 October 31, 1995.
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BALTIMORE GAS AND ELECTRIC COMPANY
PART I. FINANCIAL INFORMATION
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
<TABLE>
<CAPTION>
Quarter Ended Nine Months Ended
September 30, September 30,
1995 1994 1995 1994
(In Thousands, Except Per-Share Amounts)
<S> <C> <C> <C> <C>
Revenues
Electric ............................................... $ 713,769 $ 649,223 $ 1,726,220 $ 1,666,548
Gas ....................................................... 49,477 51,450 270,229 324,520
Diversified businesses .................................... 85,535 53,205 212,638 181,648
Total revenues ............................................ 848,781 753,878 2,209,087 2,172,716
Expenses Other Than Interest and Income Taxes
Electric fuel and purchased energy ........................ 155,085 148,082 435,667 395,595
Gas purchased for resale .................................. 18,339 19,868 129,330 178,376
Operations ................................................ 135,056 136,855 401,184 424,857
Maintenance ............................................... 34,478 35,550 122,720 124,540
Diversified businesses-selling, general, and administrative 54,590 33,312 148,337 135,559
Depreciation and amortization ............................. 93,559 90,767 245,574 228,480
Taxes other than income taxes ............................. 57,930 56,971 157,389 153,500
Total expenses other than interest and income taxes ....... 549,037 521,405 1,640,201 1,640,907
Income From Operations ...................................... 299,744 232,473 568,886 531,809
Other Income
Allowance for equity funds used during construction ....... 2,026 5,565 12,227 16,180
Equity in earnings of Safe Harbor Water Power Corporation . 1,108 1,088 3,323 3,266
Net other income and deductions ........................... (1,661) 213 (7,600) 416
Total other income ........................................ 1,473 6,866 7,950 19,862
Income Before Interest and Income Taxes ..................... 301,217 239,339 576,836 551,671
Interest Expense
Interest charges .......................................... 55,436 54,071 165,746 159,840
Capitalized interest ...................................... (3,509) (3,161) (10,676) (8,972)
Allowance for borrowed funds used during construction ..... (1,096) (3,009) (6,615) (8,749)
Net interest expense ...................................... 50,831 47,901 148,455 142,119
Income Before Income Taxes .................................. 250,386 191,438 428,381 409,552
Income Taxes
Current ................................................... 64,611 51,442 69,523 75,329
Deferred .................................................. 24,470 15,440 79,865 64,896
Investment tax credit adjustments ......................... (2,030) (2,060) (6,085) (6,142)
Total income taxes ........................................ 87,051 64,822 143,303 134,083
Net Income .................................................. 163,335 126,616 285,078 275,469
Preferred and Preference Stock Dividends .................... 10,231 9,902 30,135 29,954
Earnings Applicable to Common Stock ...................... $ 153,104 $ 116,714 $ 254,943 $ 245,515
Average Shares of Common Stock Outstanding ................. 147,527 147,487 147,527 146,957
Total Earnings Per Share of Common Stock .................... $1.04 $0.79 $1.73 $1.67
Dividends Declared Per Share of Common Stock ................ $0.39 $0.38 $1.16 $1.13
Certain prior-year amounts have been reclassified to conform with the current year's presentation.
</TABLE>
See Notes to Consolidated Financial Statements.
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PART I. FINANCIAL INFORMATION (Continued)
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
September 30, December 31,
1995 * 1994
(In Thousands)
<S> <C> <C>
ASSETS
Current Assets
Cash and cash equivalents ................................... $ 28,081 $ 38,590
Accounts receivable (net of allowance for uncollectibles
of $15,983 and $14,960, respectively) ................... 388,821 314,842
Fuel stocks ................................................... 65,569 70,627
Materials and supplies ........................................ 148,501 149,614
Prepaid taxes other than income taxes ......................... 39,178 57,740
Other ......................................................... 55,239 47,022
Total current assets .......................................... 725,389 678,435
Investments and Other Assets
Real estate projects .......................................... 471,308 471,435
Power generation systems ...................................... 347,372 311,960
Financial investments ......................................... 203,277 224,340
Nuclear decommissioning trust fund ............................ 81,602 66,891
Safe Harbor Water Power Corporation ........................... 34,190 34,168
Senior living facilities ...................................... 15,445 11,540
Other ........................................................ 67,805 58,824
Total investments and other assets ............................ 1,220,999 1,179,158
Utility Plant
Plant in service
Electric .................................................... 6,256,165 5,929,996
Gas ......................................................... 676,999 616,823
Common ...................................................... 521,743 511,016
Total plant in service ...................................... 7,454,907 7,057,835
Accumulated depreciation ......................................(2,452,705) (2,305,372)
Net plant in service .......................................... 5,002,202 4,752,463
Construction work in progress ................................. 303,093 506,030
Nuclear fuel (net of amortization) ............................ 143,132 134,012
Plant held for future use ..................................... 25,295 24,320
Net utility plant ............................................. 5,473,722 5,416,825
Deferred Charges
Regulatory assets (net) ....................................... 615,987 623,640
Other deferred charges ........................................ 87,488 96,086
Total deferred charges ........................................ 703,475 719,726
TOTAL ASSETS .................................................. $ 8,123,585 $ 7,994,144
* Unaudited
Certain prior-year amounts have been reclassified to conform with the current year's presentation.
</TABLE>
See Notes to Consolidated Financial Statements.
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PART I. FINANCIAL INFORMATION (Continued)
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
September 30, December 31,
1995 * 1994
(In Thousands)
<S> <C> <C>
LIABILITIES AND CAPITALIZATION
Current Liabilities
Short-term borrowings ....................................... $ 13,800 $ 63,700
Current portions of long-term debt and preference stock ....... 416,546 323,675
Accounts payable .............................................. 126,643 181,931
Customer deposits ............................................. 26,293 24,891
Accrued taxes ................................................. 43,208 19,585
Accrued interest .............................................. 59,724 60,348
Dividends declared ............................................ 67,767 66,012
Accrued vacation costs ........................................ 31,836 30,917
Other ......................................................... 20,737 30,857
Total current liabilities ..................................... 806,554 801,916
Deferred Credits and Other Liabilities
Deferred income taxes ......................................... 1,241,711 1,156,429
Pension and postemployment benefits ........................... 135,420 138,835
Decommissioning of federal uranium enrichment facilities ...... 45,637 45,836
Other ......................................................... 53,849 59,645
Total deferred credits and other liabilities .................. 1,476,617 1,400,745
Capitalization
Long-term Debt
First refunding mortgage bonds of BGE ......................... 1,726,532 1,744,385
Other long-term debt of BGE ................................... 571,500 544,550
Long-term debt of Constellation Companies ..................... 556,175 575,765
Unamortized discount and premium .............................. (16,042) (17,593)
Current portion of long-term debt ............................. (329,046) (262,175)
Total long-term debt .......................................... 2,509,119 2,584,932
Preferred Stock ................................................. 59,185 59,185
Redeemable Preference Stock ..................................... 341,000 341,000
Current portion of redeemable preference stock ................ (87,500) (61,500)
Total redeemable preference stock ............................. 253,500 279,500
Preference Stock Not Subject to Mandatory Redemption ............ 210,000 150,000
Common Shareholders' Equity
Common stock .................................................. 1,424,993 1,425,378
Retained earnings ............................................. 1,396,467 1,312,655
Pension liability adjustment ................................ (16,521) (16,521)
Net unrealized gain(loss) on available-for-sale securities .. 3,671 (3,646)
Total common shareholders' equity ............................. 2,808,610 2,717,866
Total capitalization .......................................... 5,840,414 5,791,483
TOTAL LIABILITIES AND CAPITALIZATION .......................... $ 8,123,585 $ 7,994,144
* Unaudited
Certain prior-year amounts have been reclassified to conform with the current year's presentation.
</TABLE>
See Notes to Consolidated Financial Statements.
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PART I. FINANCIAL INFORMATION (Continued)
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
<TABLE>
<CAPTION>
Nine Months Ended September 30,
1995 1994
(In Thousands)
<S> <C> <C>
Cash Flows From Operating Activities
Net income ................................................... $ 285,078 $ 275,469
Adjustments to reconcile to net cash provided by operating activities
Depreciation and amortization .............................. 288,698 266,945
Deferred income taxes ...................................... 79,865 64,896
Investment tax credit adjustments .......................... (6,085) (6,142)
Deferred fuel costs ........................................ 21,690 4,536
Accrued pension and postemployment benefits ................ (10,540) (44,210)
Allowance for equity funds used during construction......... (12,227) (16,180)
Equity in earnings of affiliates and joint ventures (net)... (14,854) (12,551)
Changes in current assets, other than sale of accounts receivable ... (57,784) (42,073)
Changes in current liabilities, other than short-term borrowings..... (38,415) (6,296)
Other ...................................................... (4,969) 24,105
Net cash provided by operating activities .................... 530,457 508,499
Cash Flows From Financing Activities
Proceeds from issuance of
Short-term borrowings (net) ................................ (49,900) 69,400
Long-term debt ............................................. 56,164 207,018
Preference stock ........................................... 59,475 (4)
Common stock ............................................... 140 33,762
Reacquisition of long-term debt .............................. (67,002) (238,571)
Redemption of preference stock ............................... - (2,906)
Common stock dividends paid .................................. (169,656) (164,092)
Preferred and preference stock dividends paid ................ (29,856) (29,970)
Other ........................................................ 325 (214)
Net cash used in financing activities ........................ (200,310) (125,577)
Cash Flows From Investing Activities
Utility construction expenditures ............................ (258,331) (344,993)
Allowance for equity funds used during construction .......... 12,227 16,180
Nuclear fuel expenditures .................................... (45,434) (38,337)
Deferred nuclear expenditures ................................ - (5,674)
Deferred energy conservation expenditures .................... (30,068) (29,712)
Contributions to nuclear decommissioning trust fund .......... (7,335) (7,335)
Purchases of marketable equity securities .................... (12,055) (43,505)
Sales of marketable equity securities ........................ 40,856 25,418
Other financial investments .................................. 7,941 2,751
Real estate projects ......................................... (3,898) 21,048
Power generation systems ..................................... (29,949) (2,330)
Other ........................................................ (14,610) 559
Net cash used in investing activities ........................ (340,656) (405,930)
Net Decrease in Cash and Cash Equivalents ...................... (10,509) (23,008)
Cash and Cash Equivalents at Beginning of Period ............... 38,590 84,236
Cash and Cash Equivalents at End of Period ..................... $ 28,081 $ 61,228
Other Cash Flow Information
Cash paid during the period for:
Interest (net of amounts capitalized) ...................... $ 148,018 $ 137,982
Income taxes ............................................... $ 57,342 $ 58,408
</TABLE>
See Notes to Consolidated Financial Statements.
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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.
Regulatory Assets
Deferred investment tax credits represent investment tax
credits associated with BGE's regulated utility operations as
discussed in Note 1 of the Form 10-K for the year ended December
31, 1994. Previously, the Company reported deferred investment
tax credits in the consolidated balance sheets as Deferred
Credits and Other Liabilities. Effective September 30, 1995, the
Company reclassified those credits as a reduction of Regulatory
Assets, which reflects the Company's policy to defer such credits
solely because of the regulatory treatment. Prior-year amounts
have been reclassified to conform with the current year's
presentation.
BGE Financing Activity
The following is a summary of issuances of long-term debt
and preference stock during the period from January 1, 1995
through the date of this report. The net proceeds from these
issuances were used to meet capital requirements and for general
corporate purposes relating to BGE's utility business.
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Principal Amount
or Par Value Issue Net
Issued Date Proceeds
Medium-Term Notes, Series C
(Maturing August through
December, 1998) $26,950,000 9/1-9/6/95 $26,869,000
6.99% Cumulative Preference
Stock, 1995 Series
($100 Par Value) $60,000,000 9/7/95 $59,475,000
During this period, BGE redeemed the following principal
amounts of First Refunding Mortgage Bonds at various prices
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.
In addition, on October 1, BGE exercised its option to
double-up the required sinking fund on certain series of
preference stock by redeeming at par a total of 30,000 shares of
the 7.50% Cumulative Preference Stock 1986 Series ($100 par
value) and a total of 200,000 shares of the 8.25% Cumulative
Preference Stock 1989 Series ($100 par value).
BGE may purchase First Refunding Mortgage Bonds of various
series in open market transactions, from time to time in the
future, depending upon market conditions and BGE's assessment of
optimal capital structure, including the mix of secured and
unsecured debt.
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.
Pending Merger with Potomac Electric Power Company
As described in detail in the Report on Form 8-K filed
September 27, 1995, BGE, Potomac Electric Power Company, a
District of Columbia and Virginia corporation (PEPCO), and RH
Acquisition Corp., a Maryland corporation (the New Company), have
entered into an Agreement and Plan of Merger, dated as of
September 22, 1995. The New Company, which will be renamed, was
formed to accomplish the merger and its outstanding capital stock
is owned 50% by BGE and 50% by PEPCO. The Agreement and Plan of
Merger provides for a strategic business combination that will be
accomplished by merging both BGE and PEPCO into the New Company
(the Transaction). The Transaction, which was unanimously
approved by the Boards of Directors of BGE and PEPCO, is expected
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to close during 1997 after shareholder approval is obtained and
all other conditions to the consummation of the Transaction,
including obtaining applicable regulatory approvals, are met or
waived. In connection with the Transaction, BGE common
shareholders will receive one share of New Company common stock
for each BGE share and PEPCO common shareholders will receive
0.997 share of New Company common stock for each PEPCO share.
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.
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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 September 30, 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 an industry
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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 mutuals, BGE and all policyholders could be
assessed, with BGE's share being up to $33.33 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
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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-
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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.
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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 NINE MONTHS ENDED
SEPTEMBER 30, 1995 COMPARED WITH THE CORRESPONDING PERIODS OF
1994
Earnings per Share of Common Stock
Consolidated earnings per share for the quarter and nine
months ended September 30, 1995 were $1.04 and $1.73,
respectively, which represent increases of $.25 and $.06 compared
to the earnings for the corresponding periods of 1994. These
increases in earnings per share reflect a higher level of
earnings applicable to common stock. The earnings per share are
summarized as follows:
Quarter Ended Nine Months Ended
September 30 September 30
1995 1994 1995 1994
Utility operations $ .96 $ .75 $1.59 $1.61
Diversified businesses .08 .04 .14 .06
Total $1.04 $ .79 $1.73 $1.67
Earnings Applicable to Common Stock
Earnings applicable to common stock increased $36.4 million
during the third quarter of 1995 as a result of higher earnings
from both utility operations and diversified businesses. Earnings
increased $9.4 million during the nine months ended September 30,
1995, as a result of higher earnings from diversified businesses,
partially offset by slightly lower earnings from utility
operations.
Earnings from utility operations increased during the third
quarter of 1995 primarily due to higher electric system sales
resulting from the extremely hot summer weather in 1995 in
contrast to the weather experienced during the third quarter of
last year. The effect of weather on utility sales is discussed
on pages 14 and 15.
Earnings from utility operations decreased during the nine
months ended September 30, 1995 due to lower electric and gas
sales resulting from substantially milder winter weather in 1995,
as well as higher depreciation and amortization expense as
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compared to 1994. This was partially offset by higher electric
system sales due to the extremely hot summer weather experienced
in 1995 and lower operations and maintenance expenses as compared
to 1994.
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. See the discussion of BGE's pending merger with PEPCO under
the heading Pending Merger with Potomac Electric Power Company on
page 7 of this Report.
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 nine months ended September 30,
1995 compared to the corresponding periods of 1994. Diversified
businesses' earnings are discussed on pages 22 through 24.
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
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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 nine months ended September 30, 1995 and 1994.
Quarter Ended Nine Months Ended
September 30 September 30
1995 1994 1995 1994
Heating degree days............ 53 79 2,772 3,275
Percent change compared to
prior period.................. (32.9)% (15.4)%
Cooling degree days............ 746 615 997 935
Percent change compared to
prior period.................. 21.3% 6.6%
BGE Utility Revenues and Sales
Electric revenues changed for the quarter and nine months
ended September 30, 1995 because of the following factors:
Quarter Ended Nine Months Ended
September 30 September 30
1995 vs. 1994 1995 vs. 1994
(In millions)
System sales volumes $ 41.2 $ 6.2
Base rates 12.4 16.2
Fuel rates (0.4) (16.0)
Revenues from system sales 53.2 6.4
Interchange and other sales 10.4 53.1
Other revenues 0.9 0.2
Total $ 64.5 $59.7
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. Following is a
comparison of the changes in electric system sales volumes:
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Quarter Ended Nine Months Ended
September 30 September 30
1995 vs. 1994 1995 vs. 1994
Residential 10.5% (1.5)%
Commercial 5.8 0.9
Industrial 5.5 3.4
Total 7.6 0.3
The increase in sales to the residential and commercial
classes of electric customers during the third quarter of 1995 is
primarily attributable to the extremely hot summer weather
conditions in 1995 as compared to the weather experienced during
the third quarter of 1994. The increase in industrial sales was
primarily due to an increase in the number of customers as
compared to last year.
The slight decrease in sales to residential customers during
the nine months ended September 30, 1995 reflects milder weather
experienced during the first half of 1995 as compared to last
year, offset partially by the extremely hot summer weather during
1995. Sales to commercial customers increased slightly compared
to last year due to an increased number of customers and higher
usage per customer, offset partially by the net impact of the
hotter summer and milder winter weather patterns experienced this
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 still producing power with its own generating
facility which it is now selling 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 nine months ended September 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 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
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1993 through November 1994. The deferral of these billings
totaled $20.1 million, of which $6.6 million occurred during the
quarter ended September 30, 1994 and a total of $15.1 million
occurred during the nine months ended September 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 slightly lower for the quarter ended
September 30, 1995 as compared to the same period in 1994 as a
result of a lower fuel rate, offset substantially by increased
electric system sales volumes. Fuel rate revenues were lower for
the nine months ended September 30, 1995 compared to the same
period last year as a result of a lower fuel rate.
The fuel rate was lower for the quarter and nine months
ended September 30, 1995 as compared to the same periods last
year 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 nine months ended September 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 nine months ended
September 30,1995 because of the following factors:
Quarter Ended Nine Months Ended
September 30 September 30
1995 vs. 1994 1995 vs. 1994
(In millions)
Sales volumes $ (0.7) $ (6.1)
Base rates 0.1 2.1
Gas cost adjustment revenues (1.7) (50.3)
Other revenues 0.3 0.0
Total $ (2.0) $ (54.3)
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Below is a comparison of the changes in gas sales volumes:
Quarter Ended Nine Months Ended
September 30 September 30
1995 vs. 1994 1995 vs. 1994
Residential (8.1)% (10.8)%
Commercial 8.5 (2.8)
Industrial (1.6) 9.6
Total (0.7) (1.5)
Gas sales to residential customers decreased during the
third quarter of 1995 due to lower usage per customer, offset
partially by an increased number of customers. Sales to
commercial customers were higher compared to last year due to
increased usage per customer and an increase in the number of
customers. Sales to industrial customers were lower compared to
last year due to decreased usage by Bethlehem Steel, offset
partially by increased usage by other industrial customers.
Total gas sales for the nine months ended September 30, 1995
decreased as a result of lower sales to residential and
commercial customers, offset partially by an increase in sales to
industrial customers. Sales to residential 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 commercial customers decreased due to milder
winter weather, offset partially by an increase in the number of
customers and higher usage-per-customer during 1995. 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 are expected to be impacted positively by the Maryland
Commission's anticipated Order in response to BGE's April 21,
1995 application for $29 million of increased gas base rates. In
a proposed Order issued October 3, 1995, a hearing examiner
approved a $19.4 million increase to gas base rates. The proposed
Order has been appealed, and the Maryland Commission is expected
to issue a final Order on November 20, 1995.
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 and
nine months ended September 30, 1995 because of lower prices for
purchased gas and lower sales volumes subject to gas cost
adjustment clauses. Delivery service sales volumes are not
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subject to gas cost adjustment clauses because these customers
purchase their gas directly from third parties.
BGE Utility Fuel and Energy Expenses
Electric fuel and purchased energy expenses were as follows:
Quarter Ended Nine Months Ended
September 30 September 30
1995 1994 1995 1994
(In millions)
Actual costs $156.7 $141.5 $420.2 $414.7
Net (deferral) recovery of
costs under electric fuel
rate clause (see Note 1 of
the Form 10-K) (1.6) 6.6 15.5 (19.1)
Total $155.1 $148.1 $435.7 $395.6
Total electric fuel and purchased energy expenses increased
during the quarter ended September 30, 1995 as a result of
increased actual costs, offset partially by the operation of the
electric fuel rate clause. Actual electric fuel and purchased
energy costs increased for the quarter ended September 30, 1995
as a result of higher net output of electricity generated and
higher purchased energy costs.
Total electric fuel and purchased energy expenses increased
during the nine months ended September 30, 1995 as a result of
the operation of the electric fuel rate clause and increased
actual electric costs. Actual electric fuel and purchased energy
costs increased during the nine months ended September 30, 1995
primarily due to a higher net output of electricity and higher
purchased energy and capacity costs, offset partially by a less
costly generation mix resulting primarily from refueling and
maintenance outages at the Calvert Cliffs Nuclear Power Plant
during the first quarter of 1994.
Purchased gas expenses were as follows:
Quarter Ended Nine Months Ended
September 30 September 30
1995 1994 1995 1994
(In millions)
Actual costs $ 16.9 $21.4 $135.6 $174.6
Net (deferral) recovery of costs
under purchased gas adjustment
clause (see Note 1 of the
Form 10-K) 1.4 (1.5) (6.3) 3.8
Total $ 18.3 $19.9 $129.3 $178.4
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<PAGE>
Total purchased gas expenses decreased slightly for the
quarter ended September 30, 1995 compared to last year due to a
decrease in actual gas costs, offset partially by the operation
of the purchased gas adjustment clause. The decrease in actual
gas costs reflects substantially lower gas prices during the
third quarter of 1995 as compared to last year.
Total purchased gas expenses decreased during the nine
months ended September 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 nine months ended September 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 $6.5 million of take-
or-pay refunds received in the second quarter of 1994 from
Columbia Gas Transmission Corporation.
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 slightly for the quarter ended
September 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 nine months ended September 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 approximately $4.5 million in 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 decreased slightly during the quarter
and nine months ended September 30, 1995 due primarily to reduced
labor costs and other savings in 1995 resulting from the
Company's ongoing cost control efforts, offset partially by
approximately $2.3 million in higher costs at the Calvert Cliffs
Nuclear Power Plant related to the second quarter 1995 outage.
Depreciation and amortization expense increased for the
quarter and the nine months ended September 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. The higher level of depreciable plant
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in service, which is primarily due to certain capital additions
at the Calvert Cliffs Nuclear Power Plant, resulted in an
increase of approximately $10.5 million in depreciation and
amortization during the nine months ended September 30, 1995.
The facility-specific study generated a higher decommissioning
cost than the prior estimate which will increase depreciation
expense by $9 million annually, $6.8 million of which occurred
during the nine months ended September 30, 1995. Additionally, as
discussed below, depreciation and amortization expense during the
third quarter and nine months ended September 30, 1995 and 1994
reflected the write-off of certain Perryman costs.
Initially, BGE had planned to build two combined cycle
generating units at its Perryman site with each unit consisting
of two combustion turbines. However, due to significant changes
in the environment in which utilities operate, BGE decided in
1994 not to construct the second combined cycle generating unit
and wrote off the construction work in progress costs associated
with that unit. This write-off reduced after-tax earnings during
the third quarter of 1994 by $11.0 million or 7 cents per share.
As a result of the Maryland Public Service Commission's August
1995 Order requiring all new generation capacity needs to be
competitively bid and BGE's September 1995 announcement that it
will merge with PEPCO, BGE determined that it will not build the
second combustion turbine for the first combined cycle unit.
Therefore, during the third quarter of 1995, BGE wrote off the
remaining construction work in progress costs associated with the
first combined cycle unit. This write-off reduced after-tax
earnings for the quarter ended September 30, 1995 by $9.7
million, or 7 cents per share. The construction of the first 140-
megawatt combustion turbine at Perryman was completed, and the
unit was placed in service, during June 1995.
Other Income and Expenses
Allowance for equity funds used during construction
decreased for the quarter and the nine months ended September 30,
1995 due primarily to a significant reduction in construction
work in progress. This reduction in construction work in
progress resulted from both a lower level of new construction
activity and the placement of several projects in service.
Net other income and deductions decreased for the quarter
and the nine months ended September 30, 1995. For the nine months
ended September 30, 1995 net other income and deductions
decreased due primarily to approximately $11.0 million in lower
other interest, dividend and finance charge income, offset
partially by a $2.0 million gain on the sale of receivables.
Interest expense increased for the quarter and nine months
ended September 30, 1995 primarily due to an increase in the
level of interest rates, offset partially by more capitalized
interest related to increased investment in capitalized projects
by the Constellation Companies.
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Income tax expense increased for the quarter ended September
30, 1995 due primarily to higher taxable income from utility
operations and diversified businesses. Income tax expense
increased for the nine months ended September 30, 1995 due
primarily to higher taxable income from the Constellation
Companies.
Diversified Businesses Earnings
Earnings per share from diversified businesses were:
Quarter Ended Nine Months Ended
September 30 September 30
1995 1994 1995 1994
Constellation Holdings, Inc.
Power generation systems $ .07 $ .05 $ .11 $ .06
Financial investments .02 .00 .06 .02
Real estate development and
senior living facilities (.01) (.01) (.03) (.02)
Total Constellation Holdings, Inc. .08 .04 .14 .06
BGE Home Products & Services, Inc. .00 .00 .00 .00
Total diversified businesses $ .08 $ .04 $ .14 $ .06
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 the quarter and nine months ended
September 30, 1995 due primarily to higher equity earnings from
the Constellation Companies' energy projects. In addition,
earnings during the quarter ended September 30, 1995 increased
due to the gain on the sale of certain operating and maintenance
contracts.
The Constellation Companies' investment in wholesale power
generating projects includes $194 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
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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 $29 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 ended
September 30, 1995 due to favorable earnings on the Companies'
investment portfolio. Financial investment earnings were higher
for the nine months ended September 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 nine months ended September 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 for
which substantially all development activities have been
suspended. These factors have affected earnings negatively and
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are expected to continue to do so until the levels of undeveloped
land are reduced. Cash flow from real estate operations has been
insufficient to cover the debt service requirements of certain of
these projects. Resulting cash shortfalls have been satisfied
through cash infusions from Constellation Holdings, Inc., which
obtained the funds through a combination of cash flow generated
by other Constellation Companies and its corporate borrowings.
To the extent the real estate market continues to improve,
earnings from real estate activities are expected to improve
also.
The Constellation Companies' continued investment in real
estate projects is a function of market demand, interest rates,
credit availability, and the strength of the economy in general.
The Constellation Companies' Management believes that although
the real estate market has improved, until the economy reflects
sustained growth and the excess inventory in the market in the
Baltimore-Washington corridor goes down, real estate values will
not improve significantly. If the Constellation Companies were to
sell their real estate projects in the current depressed market,
losses would occur in amounts difficult to determine. Depending
upon market conditions, future sales could also result in losses.
In addition, were the Constellation Companies to change their
intent about any project from an intent to hold to an intent to
sell, applicable accounting rules would require a write-down of
the project to market value at the time of such change in intent
if market value is below book value.
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 8, 9, and
28 of this Report.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity
For the twelve months ended September 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 3.16 and 2.50, respectively.
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Capital Requirements
The Company's capital requirements reflect the capital-
intensive nature of the utility business. Actual capital
requirements for the nine months ended September 30, 1995, along
with estimated annual amounts for the years 1995 through 1997,
are reflected below.
Nine Months Ended
September 30 Calendar Year Estimate
1995 1995 1996 1997
(In millions)
Utility Business:
Construction expenditures
(excluding AFC)
Electric $159 $230 $219 $206
Gas 48 67 71 84
Common 32 53 50 35
Total construction expenditures 239 350 340 325
AFC 19 23 13 10
Nuclear fuel (uranium purchases
and processing charges) 45 50 50 52
Deferred energy conservation
expenditures 30 40 34 25
Retirement of long-term debt
and redemption of preference
stock 18 279 98 164
Total utility business 351 742 535 576
Diversified Businesses:
Retirement of long-term debt 39 57 46 141
Investment requirements 54 86 70 40
Total diversified businesses 93 143 116 181
Total $444 $885 $651 $757
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 September 30, 1995, the
internal generation of cash from utility operations provided 95%
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
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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 issued $27 million principal amount of debt and
$60 million par value of preference stock. During the same
period, BGE redeemed $206 million principal amount of debt and
$73 million par value of preference stock.
At the date of this Report, BGE's securities ratings are as
follows:
Standard Moody's
& Poors Investors Duff & Phelps
Rating Group Service Credit Rating Co.
Senior Secured Debt A+ A1 AA-
(First Mortgage Bonds)
Unsecured Debt A A2 A+
Preferred Stock A "a1" A+
Preference Stock A "a2" A
The Constellation Companies' capital requirements are
discussed below in the section titled "Diversified Businesses
Capital Requirements - Debt and Liquidity." The Constellation
Companies are exploring expansion of their energy, real estate
service, and senior living facility businesses. Expansion may be
achieved in a variety of ways, including without limitation
increased investment activity and acquisitions. The Constellation
Companies plan to meet their capital requirements with a
combination of debt and internal generation of cash from their
operations. Additionally, from time to time, BGE may make loans
to Constellation Holdings, Inc., or contribute equity to enhance
the capital structure of Constellation Holdings, Inc.
Historically, Constellation's energy projects have been in
the United States. As of September 30, 1995, one of the
Constellation Companies had invested about $10 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
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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 22 to 24 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 of which $35 million was outstanding
at the date of this Report.
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 25 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.
-27-
<PAGE>
PART II. OTHER INFORMATION
ITEM 1. Legal Proceedings
Asbestos
Since 1993, BGE has been served in several actions
concerning asbestos. The actions are collectively titled In re
Baltimore City Personal Injuries Asbestos Cases in the Circuit
Court for Baltimore City, Maryland. The actions are based upon
the theory of "premises liability," alleging that BGE knew of and
exposed individuals to an asbestos hazard. The actions relate to
two types of claims.
The first type, direct claims by individuals exposed to
asbestos, were described in a Report on Form 8-K filed August 20,
1993. BGE and approximately 70 other defendants are involved.
Approximately 510 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.
-28-
<PAGE>
PART II. OTHER INFORMATION (Continued)
ITEM 6. Exhibits and Reports on Form 8-K
(a) Exhibit No. 3 Articles Supplementary, dated as of
September 5, 1995, to the Charter
of Baltimore Gas and Electric
Company.
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) Reports on Form 8-K for the quarter ended September 30, 1995:
Date Filed Items Reported
September 27, 1995 Item 5. Other Events
Item 7. Financial Statements
and Exhibits
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 November 13, 1995 /s/ C. W. Shivery
C. W. Shivery, Vice President
on behalf of the Registrant and
as Principal Financial Officer
-29-
<PAGE>
EXHIBIT INDEX
Exhibit
Number
3 Articles Supplementary, dated as of
September 5, 1995, to the Charter
of Baltimore Gas and Electric
Company.
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.
-30-
<PAGE>
Exhibit 3
ARTICLES SUPPLEMENTARY TO THE CHARTER
OF BALTIMORE GAS AND ELECTRIC COMPANY
BALTIMORE GAS AND ELECTRIC COMPANY, a Maryland
corporation (the "corporation") having its principal office in
Baltimore City, Maryland, hereby certifies that:
FIRST: The Board of Directors of the corporation on
September 17, 1993 and its Executive Committee on September 5,
1995, acting pursuant to the power contained in paragraph 18 of
the Charter of the corporation, classified 600,000 shares of the
authorized but unissued preference stock into a series of
preference stock to be designated as 6.99% Cumulative Preference
Stock, 1995 Series ($100 par value).
SECOND: The preferences, rights, voting powers,
restrictions, and qualifications of the authorized preference
stock are set forth in the Charter of the corporation, as
restated. The following is a further description of the 6.99%
Cumulative Preference Stock, 1995 Series ($100 par value),
containing the preferences, restrictions, limitations as to
dividends, qualifications thereof, and the times and prices of
redemption thereof, as fixed by the Board of Directors and its
Executive Committee:
"32.(a). The 6.99% Cumulative Preference Stock, 1995
Series ($100 par value), shall entitle the holders thereof to
receive, when and as declared, from the surplus or net profits of
the corporation remaining after the preferential dividend
requirements for the outstanding preferred stock have been
provided for, yearly dividends at the rate of six and ninety-nine
hundredths per cent per annum and no more, payable quarterly on
the first days of January, April, July, and October in each year
commencing October 1, 1995. The dividends on the 6.99%
Cumulative Preference Stock, 1995 Series ($100 par value), shall
be cumulative and shall be payable before any dividend on the
common stock shall be paid or set apart; so that, if in any year
or years dividends amounting to six and ninety-nine hundredths
per cent shall not have been paid thereon, the deficiency shall
be payable before any dividends shall be paid upon or set apart
for the common stock. Dividends on the 6.99% Cumulative
Preference Stock, 1995 Series ($100 par value), will accrue from
and include September 7, 1995.
(b). The 6.99% Cumulative Preference Stock, 1995
Series ($100 par value), or any portion thereof, may whenever the
Board of Directors shall so determine, be redeemed by the payment
to the holders thereof of the sum hereinafter specified as the
redemption price at the time of redemption, in cash, for each
share thereof, together with all accrued dividends. The
applicable redemption prices shall be:
<PAGE>
Twelve Month Period Redemption Price
Beginning October 1, Per Share
2005 $ 103.50
2006 103.15
2007 102.80
2008 102.45
2009 102.10
2010 101.75
2011 101.40
2012 101.05
2013 100.70
2014 100.35
2015 and thereafter 100.00
provided, however, that prior to October 1, 2005, the corporation
will not redeem any shares of the 6.99% Cumulative Preference
Stock, 1995 Series ($100 par value). In case less than all of
the preference stock of this series at the time being
outstanding is so redeemed, the shares to be redeemed shall be,
as nearly as is reasonably practicable without creating
fractional shares, a proportionate part of the holdings of each
holder of preference stock of this series, or shall be selected,
in whole or in part, by lot. At least thirty (30) days' written
notice of the election of the corporation to redeem the
preference stock of this series (or any part thereof, in which
case the notice shall specify the particular shares to be
redeemed) shall be given to each holder of the preference stock
of this series so to be redeemed by mailing the same, postage
prepaid, and addressed to him at his address as it appears upon
the books of the corporation. When such notice shall have been
so given and the funds for payment of the redemption price plus
accrued dividends shall have been provided and set apart, the
dividends on the shares of preference stock of this series so
called for redemption and all other rights of the holders
thereof, except the right to receive the redemption price plus
accrued dividends, shall cease."
THIRD: The Board of Directors of the corporation on
September 17, 1993, and its Executive Committee on September 5,
1995, duly adopted resolutions classifying the said 600,000
shares of the authorized but unissued preference stock into
600,000 shares of 6.99% Cumulative Preference Stock, 1995 Series
($100 par value), setting forth the foregoing description of such
shares as classified, and authorizing the execution and filing of
these Articles Supplementary to the Charter of this corporation.
FOURTH: Such shares have been duly classified by the
Board of Directors of the corporation and its Executive Committee
pursuant to authority contained in the Charter of the
corporation.
- 2 -
<PAGE>
IN WITNESS WHEREOF, Baltimore Gas and Electric Company
has caused these Articles Supplementary to its Charter to be
signed in its name and on its behalf by its President, or one of
its Vice Presidents, and its corporate seal to be hereto affixed,
duly attested by its Secretary, or one of its Assistant
Secretaries, on September 5, 1995.
BALTIMORE GAS AND ELECTRIC COMPANY
By:__/s/ E. A. Crooke______________
President
BALTIMORE GAS AND
SEAL: ELECTRIC COMPANY,
INCORPORATED
JUNE 20, 1906
Attest: _/s/ R. M. Bange, Jr.________
Assistant Secretary
- 3 -
<PAGE>
STATE OF MARYLAND:
} SS:
COUNTY OF BALTIMORE:
I HEREBY CERTIFY that on September 5, 1995, before me,
the subscriber, a Notary Public of the State of Maryland, in and
for the County of Baltimore, personally appeared E. A. Crooke,
President of Baltimore Gas and Electric Company, a Maryland
corporation, and in the name and on behalf of said corporation,
acknowledged the foregoing Articles Supplementary to its Charter
to be the corporate act of said corporation and at the same time
personally appeared R. M. Bange, Jr., and made oath in due form
of law that he is a duly elected Assistant Secretary of said
corporation and he verified the matters and facts with respect to
authorization and approval that are set forth in said Articles
Supplementary.
AS WITNESS my hand and notarial seal the day and year
first above written.
___/s/_Ann M. Patek_______
Notary Public
My commission expires: 1/29/96
SEAL: NOTARY PUBLIC
BALTIMORE, MD
- 4 -
<PAGE>
EXHIBIT 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
12 Months Ended
<TABLE>
<CAPTION>
September December December December December December
1995 1994 1993 1992 1991 1990
(In Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
Net Income $333,226 $323,617 $309,866 $264,347 $233,681 $175,446
Taxes on Income 165,900 156,702 140,833 105,994 88,041 22,818
Adjusted Net Income $499,126 $480,319 $450,699 $370,341 $321,722 $198,264
Fixed Charges:
Interest and Amortization
of Debt Discount and
Expense and Premium on
all Indebtedness $208,237 $204,206 $199,415 $200,848 $213,616 $194,656
Capitalized Interest 14,131 12,427 16,167 13,800 20,953 25,748
Interest Factor in Rentals 2,017 2,010 2,144 2,033 1,801 1,840
Total Fixed Charges $224,385 $218,643 $217,726 $216,681 $236,370 $222,244
Preferred and Preference
Dividend Requirements: (1)
Preferred and Preference
Dividends $ 40,103 $ 39,922 $ 41,839 $ 42,247 $ 42,746 $ 40,261
Income Tax Required 19,712 19,074 18,763 16,729 15,916 5,166
Total Preferred and Preference
Dividend Requirements $ 59,815 $ 58,996 $ 60,602 $ 58,976 $ 58,662 $ 45,427
Total Fixed Charges and Preferred
and Preference Dividend
Requirements $284,200 $277,639 $278,328 $275,657 $295,032 $267,671
Earnings (2) $709,380 $686,535 $652,258 $573,222 $537,139 $394,760
Ratio of Earnings to
Fixed Charges 3.16 3.14 3.00 2.65 2.27 1.78
Ratio of Earnings to
Combined Fixed Charges
and Preferred and Preference
Dividend Requirements 2.50 2.47 2.34 2.08 1.82 1.47
</TABLE>
(1) Preferred and preference dividend requirements consist of an amount
equal to the pre-tax earnings that would be required to meet dividend
requirements on preferred stock and preference stock.
(2) Earnings are deemed to consist of net income that includes earnings of
BGE's consolidated subsidiaries, equity in the net income of BGE's
unconsolidated subsidiary, income taxes (including deferred income
taxes and investment tax credit adjustments), and fixed charges other
than capitalized interest.
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> SEP-30-1995
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 5,473,722
<OTHER-PROPERTY-AND-INVEST> 1,220,999
<TOTAL-CURRENT-ASSETS> 725,389
<TOTAL-DEFERRED-CHARGES> 703,475
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 8,123,585
<COMMON> 1,424,993
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 1,396,467
<TOTAL-COMMON-STOCKHOLDERS-EQ> 2,808,610
253,500
269,185
<LONG-TERM-DEBT-NET> 2,509,119
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 13,800
<LONG-TERM-DEBT-CURRENT-PORT> 329,046
87,500
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,852,825
<TOT-CAPITALIZATION-AND-LIAB> 8,123,585
<GROSS-OPERATING-REVENUE> 2,209,087
<INCOME-TAX-EXPENSE> 143,303
<OTHER-OPERATING-EXPENSES> 1,640,201
<TOTAL-OPERATING-EXPENSES> 1,783,504
<OPERATING-INCOME-LOSS> 425,583
<OTHER-INCOME-NET> 7,950
<INCOME-BEFORE-INTEREST-EXPEN> 433,533
<TOTAL-INTEREST-EXPENSE> 148,455
<NET-INCOME> 285,078
30,135
<EARNINGS-AVAILABLE-FOR-COMM> 254,943
<COMMON-STOCK-DIVIDENDS> 169,656
<TOTAL-INTEREST-ON-BONDS> 165,746
<CASH-FLOW-OPERATIONS> 530,457
<EPS-PRIMARY> 1.73
<EPS-DILUTED> 1.73
</TABLE>
