<PAGE>
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, 1994
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 October 31, 1994.
<PAGE>
<TABLE>
BALTIMORE GAS AND ELECTRIC COMPANY
PART I. FINANCIAL INFORMATION
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
<CAPTION>
Quarter Ended Sept. 30, Nine Months Ended Sept. 30,
1994 1993 1994 1993
(In Thousands, Except Per-Share Amounts)
<S> <C> <C> <C> <C>
Revenues
Electric ............................................... $ 649,223 $ 686,998 $ 1,666,548 $ 1,632,168
Gas ....................................................... 51,450 49,580 324,520 307,291
Diversified businesses .................................... 53,205 57,445 181,750 140,253
Total revenues ............................................ 753,878 794,023 2,172,818 2,079,712
Expenses Other Than Interest and Income Taxes
Electric fuel and purchased energy ........................ 148,082 143,369 395,595 387,418
Gas purchased for resale .................................. 19,868 21,193 178,376 170,652
Operations ................................................ 133,161 146,740 420,187 409,677
Maintenance ............................................... 35,550 37,204 124,540 137,759
Diversified businesses - selling, general, and administrati 37,006 35,379 140,281 102,505
Depreciation and amortization ............................. 90,767 66,151 228,480 189,418
Taxes other than income taxes ............................. 56,971 56,113 153,500 151,352
Total expenses other than interest and income taxes ....... 521,405 506,149 1,640,959 1,548,781
Income From Operations ...................................... 232,473 287,874 531,859 530,931
Other Income
Allowance for equity funds used during construction ....... 5,565 3,534 16,180 10,690
Equity in earnings of Safe Harbor Water Power Corporation . 1,088 1,068 3,266 3,204
Net other income and deductions ........................... 213 1,168 366 2,577
Total other income ........................................ 6,866 5,770 19,812 16,471
Income Before Interest and Income Taxes ..................... 239,339 293,644 551,671 547,402
Interest Expense
Interest charges .......................................... 54,071 55,232 159,840 160,599
Capitalized interest ...................................... (3,161) (3,935) (8,972) (13,033)
Allowance for borrowed funds used during construction ..... (3,009) (1,912) (8,749) (5,994)
Net interest expense ...................................... 47,901 49,385 142,119 141,572
Income Before Income Taxes .................................. 191,438 244,259 409,552 405,830
Income Taxes
Current ................................................... 51,442 61,604 75,329 82,712
Deferred .................................................. 15,440 27,679 64,896 50,723
Investment tax credit adjustments ......................... (2,060) (2,082) (6,142) (6,335)
Total income taxes ........................................ 64,822 87,201 134,083 127,100
Net Income .................................................. 126,616 157,058 275,469 278,730
Preferred and Preference Stock Dividends .................... 9,902 10,547 29,954 31,642
Earnings Applicable to Common Stock ...................... $ 116,714 $ 146,511 $ 245,515 $ 247,088
Average Shares of Common Stock Outstanding ................. 147,487 145,367 146,957 144,770
Total Earnings Per Share of Common Stock .................... $0.79 $1.01 $1.67 $1.71
Dividends Declared Per Share of Common Stock ................ $0.3 $0.37 $1.13 $1.10
Certain prior-year amounts have been restated to conform with the current year's presentation.
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
<TABLE>
PART I. FINANCIAL INFORMATION (Continued)
<CAPTION>
CONSOLIDATED BALANCE SHEETS September 30, December 31,
1994* 1993
(In Thousands)
<S> <C> <C>
ASSETS
Current Assets
Cash and cash equivalents ................................... $ 61,228 $ 84,236
Accounts receivable (net of allowance for uncollectibles).... 424,086 401,853
Fuel stocks ................................................... 67,458 70,233
Materials and supplies ........................................ 144,595 145,130
Prepaid taxes other than income taxes ......................... 83,990 54,237
Other ......................................................... 20,160 38,971
Total current assets .......................................... 801,517 794,660
Investments and Other Assets
Real estate projects .......................................... 467,048 487,397
Power generation systems ...................................... 304,456 298,514
Financial investments ......................................... 229,174 213,315
Nuclear decommissioning trust fund ............................ 66,463 56,207
Safe Harbor Water Power Corporation ........................... 34,165 34,138
Senior living facilities ...................................... 10,722 2,005
Other ........................................................ 69,256 65,355
Total investments and other assets ............................ 1,181,284 1,156,931
Utility Plant
Plant in service
Electric .................................................... 5,835,841 5,713,259
Gas ......................................................... 592,463 557,942
Common ...................................................... 500,196 487,740
Total plant in service ...................................... 6,928,500 6,758,941
Accumulated depreciation ......................................(2,260,552) (2,161,984)
Net plant in service .......................................... 4,667,948 4,596,957
Construction work in progress ................................. 511,298 436,440
Nuclear fuel (net of amortization) ............................ 144,737 139,424
Plant held for future use ..................................... 24,238 24,066
Net utility plant ............................................. 5,348,221 5,196,887
Deferred Charges
Regulatory Assets
Income taxes recoverable through future rates ................ 263,152 259,856
Deferred fuel costs (net of reserve for possible disallowance) 125,516 130,052
Deferred termination benefit costs (net of amortization)...... 83,550 96,793
Deferred nuclear expenditures (net of amortization) .......... 89,295 86,726
Deferred postemployment benefit costs ........................ 70,772 62,892
Deferred cost of decommissioning federal uranium
enrichment facilities (net of amortization) ................. 53,736 49,562
Deferred energy conservation expenditures (net of amortizatio 38,935 38,655
Deferred environmental costs (net of amortization) ........... 35,656 32,966
Other ........................................................ 3,904 10,623
Total regulatory assets ...................................... 764,516 768,125
Other ......................................................... 87,782 70,436
Total deferred charges ........................................ 852,298 838,561
TOTAL ASSETS .................................................. $ 8,183,320 $ 7,987,039
</TABLE>
* Unaudited
See Notes to Consolidated Financial Statements.
<PAGE>
<TABLE>
PART I. FINANCIAL INFORMATION (Continued)
<CAPTION>
CONSOLIDATED BALANCE SHEETS September 30, December 31,
1994* 1993
(In Thousands)
<S> <C> <C>
LIABILITIES AND CAPITALIZATION
Current Liabilities
Short-term borrowings ....................................... $ 69,400 $ 0
Current portions of long-term debt and preference stock ....... 41,618 44,516
Accounts payable .............................................. 176,616 195,534
Customer deposits ............................................. 25,205 22,345
Accrued taxes ................................................. 46,270 20,623
Accrued interest .............................................. 59,617 58,541
Dividends declared ............................................ 66,040 63,966
Accrued vacation costs ........................................ 34,383 35,546
Other ......................................................... 23,236 38,716
Total current liabilities ..................................... 542,385 479,787
Deferred Credits and Other Liabilities
Deferred income taxes ......................................... 1,134,673 1,067,611
Deferred investment tax credits ............................... 151,399 157,426
Pension and postemployment benefits ........................... 146,776 183,043
Decommissioning of federal uranium enrichment facilities ...... 49,786 46,858
Other ......................................................... 67,926 56,974
Total deferred credits and other liabilities .................. 1,550,560 1,511,912
Capitalization
Long-term Debt
First refunding mortgage bonds of BGE ......................... 1,744,385 1,802,148
Other long-term debt of BGE ................................... 544,550 482,550
Long-term debt of Constellation Companies ..................... 577,891 597,716
Unamortized discount and premium .............................. (18,119) (17,754)
Current portion of long-term debt ............................. (40,118) (41,516)
Total long-term debt .......................................... 2,808,589 2,823,144
Preferred Stock ................................................. 59,185 59,185
Redeemable Preference Stock ..................................... 342,500 345,500
Current portion of redeemable preference stock ................ (1,500) (3,000)
Total redeemable preference stock ............................. 341,000 342,500
Preference Stock Not Subject to Mandatory Redemption ............ 150,000 150,000
Common Shareholders' Equity
Common stock .................................................. 1,425,254 1,391,464
Retained earnings ............................................. 1,330,536 1,251,140
Pension liability adjustment ................................ (22,093) (22,093)
Net unrealized loss on available-for-sale securities ........ (2,096) 0
Total common shareholders' equity ............................. 2,731,601 2,620,511
Total capitalization .......................................... 6,090,375 5,995,340
TOTAL LIABILITIES AND CAPITALIZATION .......................... $ 8,183,320 $ 7,987,039
</TABLE>
* Unaudited
See Notes to Consolidated Financial Statements.
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
<TABLE>
<CAPTION>
Nine Months Ended September 30,
1994 1993
(In Thousands)
<S> <C> <C>
Cash Flows From Operating Activities
Net income ................................................... $ 275,469 $ 278,730
Adjustments to reconcile to net cash provided by operating activities
Depreciation and amortization .............................. 266,945 231,097
Deferred income taxes ...................................... 64,896 50,723
Investment tax credit adjustments .......................... (6,142) (6,335)
Deferred fuel costs ........................................ 4,536 52,361
Accrued pension and postemployment benefits ................ (44,210) 9,910
Allowance for equity funds used during construction......... (16,180) (10,690)
Equity in earnings of affiliates and joint ventures (12,551) (2,375)
Changes in current assets ......................... (42,073) (122,238)
Changes in current liabilities, other than short-te......... (6,296) 37,994
Other ...................................................... 24,105 (12,649)
Net cash provided by operating activities .................... 508,499 506,528
Cash Flows From Financing Activities
Proceeds from issuance of
Short-term borrowings (net) ................................ 69,400 (11,900)
Long-term debt ............................................. 207,018 1,030,995
Preference stock ........................................... (4) 89,213
Common stock ............................................... 33,762 44,490
Reacquisition of long-term debt .............................. (238,571) (962,238)
Redemption of preference stock ............................... (2,906) (102,410)
Common stock dividends paid .................................. (164,092) (157,275)
Preferred and preference stock dividends paid ................ (29,970) (32,217)
Other ........................................................ (214) (623)
Net cash used in financing activities ........................ (125,577) (101,965)
Cash Flows From Investing Activities
Utility construction expenditures ............................ (344,993) (309,948)
Allowance for equity funds used during construction .......... 16,180 10,690
Nuclear fuel expenditures .................................... (38,337) (33,501)
Deferred nuclear expenditures ................................ (5,674) (7,972)
Deferred energy conservation expenditures .................... (29,712) (21,170)
Contributions to nuclear decommissioning trust fund .......... (7,335) (6,675)
Purchases of marketable equity securities .................... (43,505) (24,756)
Sales of marketable equity securities ........................ 25,418 24,715
Other financial investments .................................. 2,751 30,830
Real estate projects ......................................... 21,048 (21,433)
Power generation systems ..................................... (2,330) (22,692)
Other ........................................................ 559 (938)
Net cash used in investing activities ........................ (405,930) (382,850)
.........
Net Increase (Decrease) in Cash and Cash Equivalents ........... (23,008) 21,713
Cash and Cash Equivalents at Beginning of Period ...... 84,236 27,122
.........
Cash and Cash Equivalents at End of Period ............ $ 61,228 $ 48,835
Other Cash Flow Information
Cash paid during the period for: .........
Interest (net of amounts capitalized) ...................... $ 137,982 $ 139,912
Income taxes ............................................... $ 58,408 $ 57,910
Certain prior-year amounts have been restated to conform with the current year's presentation.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
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.
Effective July 1, 1994, BGE formed a wholly owned
subsidiary, BGE Home Products & Services, Inc. (HPS), consisting
of BGE's existing merchandise and gas and appliance service
operations. HPS' revenues and expenses are included in
diversified businesses revenues and diversified businesses
selling, general and administrative expenses, respectively.
Prior-period amounts have been restated to conform with the
current year's presentation.
Statement of Financial Accounting Standards No. 115
The Company adopted Statement of Financial Accounting
Standards No. 115 (Statement No. 115), "Accounting for Certain
Investments in Debt and Equity Securities," effective January 1,
1994. As of September 30, 1994, marketable equity securities
totaling $48.5 million, which are included in financial
investments in the consolidated balance sheets, and the nuclear
decommissioning trust fund have been classified as available-for-
sale in accordance with the requirements of Statement No. 115.
Changes in the fair value of these securities are included in
common shareholders' equity.
Long-term Debt of BGE
The following is a summary of issuances and early
redemptions of long-term debt that have occurred or have been
announced during the period January 1, 1994 through the date of
this Report. The net proceeds from the new issuances were used
for general corporate purposes relating to BGE's utility
business, including the redemptions. Gains and losses on the
reacquisition of debt are amortized over the remaining original
lives of the issuances.
Principal
Amount Issue Net
Issuances Issued Date Proceeds
(Amounts in Thousands)
First Refunding Mortgage Bonds
Floating Rate Series due 4/15/99 $125,000 3/21/94 $124,438
6.00% Pollution Control Revenue
Refunding Loan due 4/1/24 75,000 4/14/94 73,971
6
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
Redemption
Price as a
Principal % of the
Amount Redemption Principal
Early Redemptions Redeemed Date Amount
(Amounts in Thousands)
First Refunding Mortgage Bonds:
7 1/4% Series due 4/15/01 $59,911 3/11/94 101.88%
6.80% Series due 9/15/04 20,000 4/14/94 101.00
6.90% Installment Series due 9/15/09 55,000 4/14/94 101.00
7% Series due 1998 28,638 4/18/94 101.11
In addition, in connection with the annual sinking fund
required by BGE's mortgage, on August 1, 1994, the following
principal amounts of First Refunding Mortgage Bonds were
redeemed: $11,986,000 of the 9-1/8% Series due October 15, 1995,
$3,775,000 of the 8.40% Series due October 15, 1999, $2,550,000
of the 8-3/8% Series due August 15, 2001, and $473,000 from
various other series.
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
the Constellation Company and its subsidiaries.
Environmental Matters
The Clean Air Act of 1990 (the Act) contains provisions
designed to reduce sulfur dioxide and nitrogen oxide (NOx)
emissions from electric generating stations in two separate
phases. Under Phase I of the Act, which must be implemented by
1995, BGE expects to incur expenditures of approximately $55
million, most of which are attributable to its portion of the
cost of installing a flue gas desulfurization system at the
Conemaugh generating station, in which BGE owns a 10.56%
interest. BGE is currently examining what actions will be
required in order to comply with Phase II of the Act, which must
be implemented by 2000. 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 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
7
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
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 $70 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. Although the cleanup costs for certain
environmentally contaminated sites could be significant, BGE
believes that the resolution of these matters will not have a
material effect on its financial position or results of
operations.
Also, BGE is coordinating investigation of several former gas
manufacturing plant sites, including exploration of corrective
action options to remove coal tar. However, no formal legal
proceedings have been instituted. As of September 30, 1994, BGE
has an accrual of approximately $27 million for estimated future
environmental costs at these sites. Based on previous actions of
the Public Service Commission of Maryland (PSC), BGE has deferred
these estimated future costs, as well as actual costs which have
been incurred to date, 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. In the past, BGE had
purchased all available insurance for these contingencies.
However, BGE decided not to purchase additional property
insurance that recently became available because the added
premium expense appeared high relative to the risk being covered.
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 $9.0 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
8
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
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
$6.2 million in any one year.
For physical damage to Calvert Cliffs, BGE has $2.75
billion of property insurance, including $1.4 billion from an
industry mutual insurance company. 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
$14.6 million.
If an outage at Calvert Cliffs is caused by an insured
physical damage loss and lasts more than 21 weeks, BGE has up to
$426 million per unit of insurance, provided by a different
industry mutual insurance company for replacement power costs.
This amount can be reduced by up to $85 million per unit if an
outage to both units at Calvert Cliffs is caused by a singular
insured physical damage loss. If an outage at any insured plant
causes a shortfall of funds at the industry mutual, BGE and all
policyholders could be assessed, with BGE's share being up to
$9.4 million.
Recoverability of Electric Fuel Costs
By statute, actual electric fuel costs are recoverable so
long as the PSC finds that BGE demonstrates that, among other
things, it has maintained the productive capacity of its
generating plants at a reasonable level. The PSC and Maryland's
highest appellate court have interpreted this as permitting a
subjective evaluation of each unplanned outage at BGE's
generating plants to determine whether or not BGE had implemented
all reasonable and cost-effective maintenance and operating
control procedures appropriate for preventing the outage.
Effective January 1, 1987, the PSC authorized the establishment
of 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
9
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
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
10
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
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.
11
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
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, 1994 COMPARED WITH THE CORRESPONDING PERIODS OF
1993
Earnings per Share of Common Stock
Consolidated earnings per share for the quarter and nine
months ended September 30, 1994 were $.79 and $1.67,
respectively, which represent decreases of $.22 and $.04 compared
to the earnings for the corresponding periods of 1993. These
decreases in earnings per share reflect a lower level of earnings
applicable to common stock and a slight increase in the number of
common shares outstanding. The earnings per share are summarized
as follows:
Quarter Ended Nine Months Ended
September 30 September 30
1994 1993 1994 1993
Utility operations............. $.75 $.99 $1.61 $1.65
Diversified businesses......... .04 .02 .06 .06
Total.......................... $.79 $1.01 $1.67 $1.71
Earnings Applicable to Common Stock
Earnings applicable to common stock decreased $29.8 million
during the quarter and $1.6 million during the nine months ended
September 30, 1994. These decreases are the result of lower
earnings from utility operations.
Earnings from utility operations decreased during the third
quarter of 1994 primarily as a result of lower sales of
electricity due to cooler late summer weather and the write-off
of a portion of the construction work in progress at BGE's
Perryman site. These factors were offset partially by labor
savings achieved through the Company's employee reduction
programs and a moderate increase in the number of electric
customers. The effect of weather on utility sales is discussed
12
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
on pages 13 and 14. The Perryman write-off is discussed on pages
20 and 21.
Earnings from utility operations decreased during the nine
months ended September 30, 1994 due to the factors noted above
for the third quarter of 1994, offset partially by increased
electric system sales as a result of significantly hotter weather
during the spring and early summer and increased electric system
and gas sales caused by colder winter weather in 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. The
base rate increases authorized by the PSC in April 1993 favorably
affected utility earnings through April 1994. 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, 1993
(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.
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), were higher during the
quarter and unchanged for the nine months ended September 30,
1994. Diversified businesses' earnings are discussed on pages 21
through 23.
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 on the following
13
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
page presents information regarding heating and cooling degree
days for the quarter and nine months ended September 30, 1994 and
1993.
Quarter Ended Nine Months Ended
September 30 September 30
1994 1993 1994 1993
Heating degree days............ 79 883,275
3,192
Percent change compared to
prior period.................. (10.2)% 2.6%
Cooling degree days............ 615 640 935
853
Percent change compared to
prior period.................. (3.9)% 9.6%
BGE Utility Revenues and Sales
Electric revenues changed during 1994 because of the
following factors:
Quarter Ended Nine Months Ended
September 30 September 30
1994 vs. 1993 1994 vs. 1993
(In millions)
System sales volumes.......... $(31.3) $22.6
Base rates.................... (9.3) 6.1
Fuel rates.................... (7.6) (17.0)
Revenues from system sales.... (48.2) 11.7
Interchange sales............. 10.2 23.8
Other revenues................ 0.6 (0.8)
Total......................... $(37.4) $34.7
Electric system sales represent volumes sold to customers
within BGE's service territory at rates determined by the PSC.
These amounts exclude interchange sales, discussed separately
later. As of December 31, 1993, BGE changed its classification of
commercial and industrial customers to present this information
on a basis which is more consistent with predominant industry
practices. Prior-period amounts have been reclassified to conform
to the current period's presentation. Below is a comparison of
the changes in electric system sales volumes.
14
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
Quarter Ended Nine Months Ended
September 30 September 30
1994 vs. 1993 1994 vs. 1993
Residential................... (6.5)% 2.9%
Commercial.................... (3.4) (0.2)
Industrial.................... 15.1 17.1
Total......................... (2.3) 3.4
Cooler weather in the third quarter of 1994 as compared to
the third quarter of 1993 produced the overall decrease in sales
to electric customers. This decrease was offset partially by
moderate customer growth. Sales to industrial customers reflect
an increase in the sale of electricity to Bethlehem Steel, which
purchased more electricity from BGE due to increased steel
production and the fact that Bethlehem Steel is now purchasing
its full electricity requirements from BGE. 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.
Electric system sales for the nine months ended September
30, 1994 reflect the positive impact of hotter spring and early
summer weather and severe winter weather conditions during 1994,
partially offset by the factors noted above for the third
quarter. Sales to commercial customers also reflect a decline in
usage-per-customer.
Base rates are affected by two principal items: the PSC's
April 1993 rate order and recovery of eligible electric
conservation program costs through the energy conservation
surcharge. The April 1993 rate order provided for an annualized
electric base rate increase of $84.9 million including a return
on BGE's higher level of electric rate base. The order also
reduced the authorized rate of return to 9.40% from the previous
rate of 9.94%.
Base rates decreased during the quarter ended September 30,
1994 due to the continuing deferral of the portion of
conservation surcharge billings subject to refund, as described
below. Base rates increased during the nine months ended
September 30, 1994 due to the remaining favorable impact of the
April 1993 rate order on results for the first four months of the
year.
Base rate revenues are expected to decrease during the
remainder of 1994 compared to 1993 as a result of the continued
deferral of a portion of conservation surcharge revenues. 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
15
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
incentives for achieving conservation goals. BGE earned in excess
of its authorized rate of return on electric operations for the
period September 30, 1993 through June 30, 1994. As a result,
BGE deferred the portion of electric energy conservation revenues
subject to refund beginning in December 1993. The deferral of
these billings has averaged approximately $1.7 million each month
and is expected to cease after November 1994. The amounts
deferred during a surcharge year will begin to be refunded to
customers with interest in the ensuing July when the annual
resetting of the conservation surcharge rates occurs.
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. (See Notes 1 and 13 of the Form 10-K.)
Changes in fuel rate revenues and interchange sales normally do
not affect earnings. However, if the PSC was 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 decreased during the third quarter of
1994 as a result of decreased electric system sales volumes and a
lower fuel rate. Fuel rate revenues decreased during the nine
months ended September 30, 1994 due to a lower fuel rate, offset
partially by increased electric system sales volumes. The fuel
rate was lower because of a less costly twenty-four month
generation mix due to greater generation at the Calvert Cliffs
Nuclear Power Plant compared to 1993. BGE expects electric fuel
rate revenues will decrease during the remainder of 1994 because
of a less-costly twenty-four month generation mix.
Interchange sales are sales of BGE's energy to the
Pennsylvania - New Jersey - Maryland Interconnection (PJM), a
regional power pool of eight member companies including BGE.
Interchange 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 to PJM utilities. Interchange sales
increased during the quarter and nine months ended September 30,
1994 because BGE had a less costly generation mix than other PJM
utilities. The less costly mix relative to other PJM companies
during 1994 reflects greater generation from the Brandon Shores
Power Plant and continued operation of the Calvert Cliffs Nuclear
Power Plant.
16
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
Gas revenues increased during 1994 because of the following factors:
Quarter Ended Nine Months Ended
September 30 September 30
1994 vs. 1993 1994 vs. 1993
(In millions)
Sales volumes................. $2.8 $7.9
Base rates.................... 0.4 1.5
Gas cost adjustment revenues.. (0.9) 9.2
Other revenues................ (0.4) (1.4)
Total......................... $1.9 $17.2
As of December 31, 1993, BGE changed its classification of
commercial and industrial customers to present this information
on a basis which is more consistent with predominant industry
practices. Prior-period amounts have been reclassified to conform
to the current period's presentation. Below is a comparison of
the changes in gas sales volumes:
Quarter Ended Nine Months Ended
September 30 September 30
1994 vs. 1993 1994 vs. 1993
Residential................... 7.4% 6.5%
Commercial.................... 7.8 (2.0)
Industrial.................... 18.8 2.5
Total......................... 13.8 2.6
Gas sales for the quarter ended September 30, 1994 increased
for all classes of customers as compared with the same period in
1993. Sales to residential and commercial customers increased
due to greater usage-per-customer and an increase in the number
of customers. Sales to industrial customers increased due to
greater usage of delivery service gas by Bethlehem Steel. Total
gas sales for the nine months ended September 30, 1994 were
higher compared to 1993 because of higher sales to residential
and industrial customers were offset partially by lower sales to
commercial customers. The increase in sales to residential
customers reflects the colder winter weather during the first
quarter of 1994 as compared to 1993, and to a lesser extent
customer growth. Sales to industrial customers reflects primarily
the greater usage of natural gas by Bethlehem Steel in its
production process. Sales to commercial and industrial customers
were negatively impacted because delivery service customers
either voluntarily switched their fuel source from natural gas to
alternate fuels, or were involuntarily interrupted by BGE as a
result of the extreme winter weather conditions. Interruptible
customers maintain alternate fuel sources and pay reduced rates
17
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
in exchange for BGE's right to interrupt service during periods
of peak demand.
Base rates increased slightly in 1994 due to an increased
recovery of eligible gas conservation program costs through the
energy conservation surcharge. The continued recovery of gas
conservation program costs under the energy conservation
surcharge will continue to increase base rate revenues during the
remainder of 1994.
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 slightly during the
third quarter of 1994 because of lower prices for purchased gas,
offset partially by higher sales volumes subject to gas cost
adjustment clauses. During the nine months ended September 30,
1994, gas cost adjustment revenues increased over last year due
to the combination of higher sales volumes subject to gas cost
adjustment clauses and increased prices of purchased gas during
the first quarter. Delivery service sales volumes are not
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
1994 1993 1994 1993
(In millions)
Actual costs.................. $141.5 $131.9 $414.7 $359.7
Net (deferral) recovery of
costs under electric fuel
rate clause (see Note 1 of
the Form 10-K)............... 6.6 11.5 (19.1) 27.7
Total......................... $148.1 $143.4 $395.6 $387.4
Electric fuel and purchased energy expenses increased during
the quarter and nine months ended September 30, 1994 due to
increases in actual fuel costs, offset partially by the impact on
expenses of changes in deferred fuel costs as a result of the
operation of the electric fuel rate clause.
18
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
Actual electric fuel and purchased energy costs increased
for the quarter and nine months ended September 30, 1994 as a
result of a more costly actual generation mix and, during the
nine months ended September 30, 1994, due to an increase in the
net output of electricity generated to meet the demand of BGE's
system and the PJM system. The cost of the actual generation mix
increased due to refueling and maintenance outages at the Calvert
Cliffs Nuclear Power Plant and, during the first quarter of 1994,
higher purchased energy costs.
Purchased gas expenses were as follows:
Quarter Ended Nine Months Ended
September 30 September 30
1994 1993 1994 1993
(In millions)
Actual costs.................. $21.4 $25.4 $174.6 $166.9
Net (deferral) recovery of costs
under purchased gas adjustment
clause (see Note 1 of the
Form 10-K)................... (1.5) (4.2) 3.8 3.8
Total......................... $19.9 $21.2 $178.4 $170.7
Actual purchased gas costs decreased during the quarter
ended September 30, 1994 as the result of lower gas prices,
offset partially by higher output associated with increased
demand for BGE gas. The lower gas prices primarily reflect
favorable market conditions and additional take-or-pay refunds
(discussed below).
Actual purchased gas costs increased during the nine months
ended September 30, 1994. This increase was due to higher gas
prices and to a lesser extent the higher output associated with
the increased demand for BGE gas during the first quarter. The
higher gas prices reflect primarily higher reservation charges,
greater transition costs related to the implementation of Federal
Energy Regulatory Commission (FERC) Order No. 636, and market
conditions, offset partially by take-or-pay and other supplier
refunds.
The take-or-pay refunds primarily represent a $16.6 million
refund received during the second quarter of 1994 from Columbia
Gas Transmission Corporation (Columbia Gas). The refund resulted
from a FERC action regarding the reallocation of take-or-pay
amounts charged to BGE by Columbia Gas between September 1988 and
December 1990. This refund is being returned to BGE's gas
customer's over a twelve-month period beginning in June 1994
pursuant to an agreement with the PSC.
19
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
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 continue to increase due to additional transition
costs incurred by BGE's gas pipeline suppliers. These transition
costs, if approved by FERC, will be passed on to BGE's customers
through the purchased gas adjustment clause.
Other Operating Expenses
Operations expense decreased during the quarter ended
September 30, 1994 due primarily to decreased labor costs as a
result of the Company's employee reduction programs. The decrease
was offset partially by the higher amortization of the deferred
Voluntary Special Early Retirement Program (VSERP) costs (see
Note 7 of the Form 10-K).
Operations expense increased for the nine months ended
September 30, 1994 because the nine months ended September 30,
1993 reflected a credit to utility operations expense equivalent
to the $9.8 million cost of termination benefits associated with
the Company's 1992 VSERP program. In addition, operations expense
for 1994 reflects a $10.0 million one-time bonus paid to
employees in lieu of a general wage increase.
In June 1994, BGE reclassified the amortization of deferred
energy conservation expenditures and deferred nuclear
expenditures from operations expense to depreciation and
amortization expense. In addition, BGE reclassified diversified
businesses' expenses from operations expense to diversified
businesses - selling, general, and administrative expense. Prior-
period amounts have been restated to conform with the current
presentation.
Operations expense is expected to be reduced during the
remainder of 1994 due to continued cost savings realized from the
1993 employee reduction programs and the absence of the December
1993 one-time cost of employee reduction programs. These lower
costs are expected to exceed the continued increase in the
amortization of deferred VSERP costs and other increases in
operations expenses.
Maintenance expense decreased during the quarter and nine
months ended September 30, 1994 due primarily to lower costs at
the Calvert Cliffs Nuclear Power Plant.
Depreciation and amortization expense increased during the
quarter and nine months ended September 30, 1994 because of the
write-off of certain Perryman costs discussed below, higher
levels of energy conservation program costs, higher depreciable
plant in service, and amortization of deferred environmental
20
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
costs for certain Company-owned sites beginning in October 1993
(see Environmental Matters on page 24). The increase in
depreciable plant in service resulted from the addition of
electric transmission and distribution plant and certain capital
additions at the Calvert Cliffs Nuclear Power Plant during 1994
and 1993.
Initially, BGE had planned to build two combined cycle
generating units at its Perryman site. However, due to
significant changes in the environment in which utilities
operate, BGE now has no plans to construct the second combined
cycle generating unit. Accordingly, during the third quarter of
1994, BGE wrote off $15.7 million of the costs associated with
that second combined cycle unit. This write-off reduced after-tax
earnings for the quarter and the nine months ended September 30,
1994 by $11 million, or 7 cents per share.
Other Income and Expenses
The allowance for funds used during construction (AFC)
increased during the quarter and nine months ended September 30,
1994 because of a higher level of construction work in progress
which was offset partially by the lower AFC rate established by
the PSC in the April 1993 rate order.
Capitalized interest decreased during the quarter and nine
months ended September 30, 1994 due to lower capitalized interest
on the Constellation Companies' power generation systems
projects. The decrease during the nine month period was offset
partially by BGE beginning to accrue carrying charges on electric
deferred fuel costs excluded from rate base. (See Note 5 of the
Form 10-K.)
Income tax expense decreased during the quarter ended
September 30,1994 because of lower taxable income and increased
for the nine months ended September 30, 1994 because of higher
taxable income.
Diversified Businesses Earnings
Earnings per share from diversified businesses were:
Quarter Ended Nine Months Ended
September 30 September 30
1994 1993 1994 1993
Power generation systems...... $.05 $.03 $.06 $.07
Financial investments......... .00 .05 .02 .08
Real estate development and
senior living facilities..... (.01) (.02) (.02) (.05)
21
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
Effect of 1993 Tax Act........ .00 (.04) .00 (.04)
Total......................... $.04 $.02 $.06 $.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 were higher for the quarter ended September 30, 1994
than the same period of 1993 due to higher earnings on various
energy projects, and the effect of $2 million in after-tax
charges related to fuel supply problems at the Panther Creek
waste-coal project during 1993. Power generation systems earnings
were lower for the nine months ended September 30, 1994 as 1993
results included the recognition of $8 million of energy tax
credits related to the Puna geothermal plant, offset partially by
total after-tax charges of $6 million related to fuel supply
problems at the Panther Creek waste-coal project.
The Constellation Companies' investment in wholesale power
generating projects includes $170 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 $25.1 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
22
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
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 lower for the quarter and nine months
ended September 30, 1994 as the third quarter of 1993 reflected a
gain from the sale of a portion of an investment in a financial
guaranty insurance company.
The Constellation Companies' real estate development
business includes land under development; office buildings;
retail 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
nine months ended September 30, 1994 increased due to gains
recognized from the sale of two retail centers, an office
building and Constellation's interests in two senior living
facilities. The increases in diversified businesses' revenues and
in selling, general and administrative expenses for the nine
months ended September 30, 1994 reflect the proceeds of these
sales and the cost of the facilities sold, respectively.
The Constellation Companies' real estate portfolio has
experienced continuing carrying costs and depreciation. During
1991, the Constellation Companies began expensing rather than
capitalizing interest on certain undeveloped land where
development activities were at minimal levels. These factors have
affected earnings negatively during 1994 and 1993 and are
expected to continue to do so until current market conditions
improve. 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.
Until the real estate market shows sustained improvement,
earnings from real estate activities are expected to remain
depressed.
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.
23
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
The Constellation Companies' Management believes that although
the real estate market is beginning to show signs of improvement,
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.
Earnings from the Constellation Companies increased during
the quarter and nine months ended September 30, 1994 because the
same periods of 1993 reflect a $6.0 million charge to income tax
expense for the impact of the 1993 Tax Act.
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 7, 8, and
30 of this Report.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity
For the twelve months ended September 30, 1994, the
Company's ratio of earnings to fixed charges and ratio of
earnings to combined fixed charges and preferred and preference
dividend requirements were 3.04 and 2.39, respectively.
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, 1994, along
with estimated annual amounts for the years 1994 through 1996,
are reflected on the following page.
24
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
Nine Months Ended
September 30 Calendar Year Estimate
1994 1994 1995 1996
(In millions)
Utility Business:
Construction expenditures
(excluding AFC)
Electric........................ $251 $350 $231 $219
Gas............................. 44 55 63 71
Common.......................... 25 45 56 50
Total construction expenditures. 320 450 350 340
AFC............................. 25 34 34 20
Deferred nuclear expenditures... 6 13 - -
Deferred energy conservation
expenditures................... 30 48 45 40
Nuclear fuel (uranium purchases
and processing charges)........ 38 49 56 59
Retirement of long-term debt
and redemption of preference
stock ......................... 201 203 268 98
Total utility business.......... 620 797 753 557
Diversified Businesses:
Retirement of long-term debt.... 35 37 69 57
Investment requirements......... 31 60 65 19
Total diversified businesses.... 66 97 134 76
Total............................ $686 $894 $887 $633
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, scheduled to be placed in service in
1995; the construction of a 140-megawatt combustion turbine at
Perryman, scheduled to be placed in service in 1995, which the
PSC authorized in an order dated March 25, 1993; and improvements
in BGE's existing generating plants and its transmission and
distribution facilities. Future electric construction
expenditures do not include additional generating units in light
of the competitive bidding process established by the PSC. The
Company estimates currently that expenditures for compliance with
the sulfur dioxide provisions of the Clean Air Act of 1990 will
total approximately $55 million through 1995.
During the twelve months ended September 30, 1994, the
internal generation of cash from utility operations provided 62%
of the funds required for BGE's capital requirements exclusive of
retirements and redemptions of debt and preference stock. During
the three-year period 1994 through 1996, the Company expects to
provide through utility operations approximately 70% of the funds
25
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
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. From January 1, 1994 through the date of this
Report, BGE's issuances of long-term debt and common stock were
$200 million and $34 million, respectively. During the same
period, retirements and redemptions of BGE's long-term debt and
preference stock totaled $196 million and $4.5 million,
respectively, exclusive of any redemption premiums. The amount
and timing of future issuances and redemptions will depend upon
market conditions and BGE's actual capital requirements.
The Constellation Companies' capital requirements are
discussed below in the section titled "Diversified Businesses
Capital Requirements - Debt and Liquidity." 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.
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 21 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 may enter into
additional credit facilities.
26
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
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 1994 through 1996 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 (Continued)
ITEM 1. Legal Proceedings
Puna Project
As discussed in previous filings made by the Company under
the Securities Exchange Act of 1934, the Constellation Companies
have a 50% ownership interest in a joint venture, Puna Geothermal
Venture (PGV). PGV developed and is operating a 25-megawatt
geothermal energy project on the island of Hawaii (the Big
Island) in the State of Hawaii (the Puna project). Construction
of the Puna project was scheduled to be completed during 1991;
however, it began generating electricity on April 22, 1993. PGV
sells the electricity it generates to Hawaii Electric Light
Company, Inc. ("Hawaii Electric") under a power purchase
agreement that calls for the supply by PGV of at least 22
megawatts.
Through the date of this Report, the Constellation
Companies' investment in the Puna project was $81.5 million. PGV
has outstanding a $93.4 million construction loan. In connection
with the construction loan, Constellation Investments, Inc. (CII)
provided a guarantee to the lending institution that requires CII
to put up to $15 million of equity into the Puna project in
certain events. The lender has the right to call the guarantee
but has not done so. Negotiations are ongoing with the project
lenders to convert the construction loan to permanent financing.
The diversified businesses section of the capital
requirements chart on page 25 includes $4.2 million for the year
1994 and $14 million for the year 1995 relating to the Puna
project. The majority of this amount is additional equity that
the Constellation Companies will be required to contribute to PGV
under the CII guarantee.
The Company cannot predict the impact that the matters
involving the Puna project discussed below may have on the
Constellation Companies or the Company, but such impact could be
material.
Previously reported issues involving production and resource
wells have been addressed.
On April 13, 1993, Hawaii Electric filed suit, Hawaii
Electric Light Company, Inc. v. Puna Geothermal Venture Company,
Inc., Civil No. 93-234 (3rd Circuit Vt., Hawaii), seeking to
require PGV to pay contractual penalties of $7.5 million (for
delays in the scheduled delivery of power to Hawaii Electric) and
seeking to require PGV to pay consequential damages. PGV asserts
that the delay was caused by a "force majeure" event.
Negotiation of a tentative settlement, which requires no
additional capital contributions from the Constellation
Companies, is near completion.
28
<PAGE>
PART II. OTHER INFORMATION (Continued)
PGV intervened in Wao Kele O Puna, et al. v. Waihee, et al.,
Civil No. 91-3553-10 (1st Circuit Court, Hawaii) on the grounds
that plaintiffs improperly are seeking to include the Puna
project in an existing suit against the State of Hawaii and the
County regarding an unrelated project. If plaintiffs succeed,
the State and the County could be enjoined from any further
permit review and issuance and from monitoring activity for the
Puna project, effectively shutting down the Puna project. The
Constellation Companies understand that the unrelated project has
been cancelled, but the effect, if any, on this lawsuit are
uncertain.
Litigation, captioned Pele Defense Fund, et al. v. Puna
Geothermal Venture, et al. No. 16098 (originally Civil No. 90-106
(Hilo)) was described in previous reports filed under the
Securities Exchange Act of 1934 by the registrant. The
litigation involved the administrative procedures used in the
issuance of PGV's authority-to-construct permits. On September
23, 1994, the Hawaii Supreme Court issued a decision in an appeal
concerning jurisdiction over the matter, and remanded the case to
the Third Circuit Court. Prior to issuance of the decision, the
authority-to-construct permits were superseded by operating
permits. It is not clear whether the plaintiffs intend to
continue to prosecute their case at the circuit court level, and,
if so, what the affect, if any, might be upon the PGV operating
permits.
Asbestos
During 1993, BGE was served in several actions concerning
asbestos. BGE was served with more actions during 1994. 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 500 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
29
<PAGE>
PART II. OTHER INFORMATION (Continued)
relate to approximately 1,500 individual plaintiffs who have
settled with the manufacturers. 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 and in Part II. Other
Information - Environmental Matters of the Second Quarter 1994
Form 10-Q. During the third quarter of 1994, an additional
environmental action was instituted.
On August 30, 1994, BGE was served in litigation instituted by
EPA in the United States District Court for the Middle District
of Pennsylvania involving contamination of the Keystone
Sanitation Company landfill Superfund site located in Adams
County, Pennsylvania. BGE was named as a third party defendant
based upon allegations that BGE had drums of asbestos shipped to
the site. There are eleven original defendants and approximately
150 other third party defendants. Neither the costs of future
site remediation, nor the extent of BGE's potential liability can
be estimated at this time.
30
<PAGE>
ITEM 6. Exhibits and Reports on Form 8-K
A) 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.
B) Exhibit No. 27 Financial Data Schedule.
C) 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 November 11, 1994 /s/ C. W. Shivery
C. W. Shivery, Vice President
on behalf of the Registrant and
as Principal Financial Officer
31
<PAGE>
EXHIBIT INDEX
Exhibit
Number
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.
32
<PAGE>
EXHIBIT 12
<TABLE>
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND
COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND
PREFERRED AND PREFERENCE DIVIDEND REQUIREMENTS
<CAPTION>
12 Months Ended
September December December December December December
1994 1993 1992 1991 1990 1989
(In Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
Net Income $306,606 $309,866 $264,347 $233,681 $175,446 $276,291
Taxes on Income 147,886 140,833 105,994 88,041 22,818 84,704
Adjusted Net Income $454,492 $450,699 $370,341 $321,722 $198,264 $360,995
Fixed Charges:
Interest and Amortization of Debt Discount
and Expense and Premium on all Indebtedness$202,469$199,415 $200,848 $213,616 $194,656 167,503
Capitalized Interest 12,106 16,167 13,800 20,953 25,748 5,842
Interest Factor in Rentals 2,001 2,144 2,033 1,801 1,840
2,388
Total Fixed Charges $216,576 $217,726 $216,681 $236,370 $222,244 $175,733
Preferred and Preference
Dividend Requirements: (1)
Preferred and Preference Dividends$ 40,161$ 41,839$ 42,247 $ 42,746 $ 40,261 $ 32,381
Income Tax Required 19,111 18,763 6,729 15,916 5,166 9,779
Total Preferred and Preference
Dividend Requirements $ 59,272 $ 60,602 $ 58,976 $ 58,662 $ 45,427 $ 42,160
Total Fixed Charges and Preferred
and Preference Dividend Requirements $275,848 $278,328 $275,657 $295,032 $267,671 $217,893
Earnings (2) $658,961 $652,258 $573,222 $537,139 $394,760 $530,886
Ratio of Earnings to Fixed Charges 3.04 3.00 2.65 2.27 1.78 3.02
Ratio of Earnings to Combined Fixed
Charges and Preferred and Preference
Dividend Requirements 2.39 2.34 2.08 1.82 1.47 2.44
(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>
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM BGE'S
CONSOLIDATED INCOME STATEMENT, BALANCE SHEET AND STATEMENT OF CASH FLOWS
AND IS QUALIFIED IN ITS ENTIRITY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-START> JAN-01-1994
<PERIOD-END> SEP-30-1994
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 5,348,221
<OTHER-PROPERTY-AND-INVEST> 1,181,284
<TOTAL-CURRENT-ASSETS> 801,517
<TOTAL-DEFERRED-CHARGES> 852,298
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 8,183,320
<COMMON> 1,425,254
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 1,330,536
<TOTAL-COMMON-STOCKHOLDERS-EQ> 2,731,601
341,000
209,185
<LONG-TERM-DEBT-NET> 2,808,589
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 69,400
<LONG-TERM-DEBT-CURRENT-PORT> 40,118
1,500
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,981,927
<TOT-CAPITALIZATION-AND-LIAB> 8,183,320
<GROSS-OPERATING-REVENUE> 2,172,818
<INCOME-TAX-EXPENSE> 134,083
<OTHER-OPERATING-EXPENSES> 1,640,959
<TOTAL-OPERATING-EXPENSES> 1,775,042
<OPERATING-INCOME-LOSS> 397,776
<OTHER-INCOME-NET> 19,812
<INCOME-BEFORE-INTEREST-EXPEN> 417,588
<TOTAL-INTEREST-EXPENSE> 142,119
<NET-INCOME> 275,469
29,954
<EARNINGS-AVAILABLE-FOR-COMM> 245,515
<COMMON-STOCK-DIVIDENDS> 166,166
<TOTAL-INTEREST-ON-BONDS> 159,840
<CASH-FLOW-OPERATIONS> 508,499
<EPS-PRIMARY> 1.67
<EPS-DILUTED> 1.67
</TABLE>
