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 June 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 - 147,442,204 shares outstanding
on July 31, 1994.
<PAGE>
<TABLE>
Page of
BALTIMORE GAS AND ELECTRIC COMPANY
PART I. FINANCIAL INFORMATION
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
<CAPTION>
Quarter Ended June 30, Six Months Ended June 30,
1994 1993 1994 1993
(In Thousands, Except Per-Share Amounts)
<S> <C> <C> <C> <C>
Revenues
Electric ............................................... $ 500,177 $ 469,741 $ 1,017,325 $ 945,170
Gas ....................................................... 67,885 75,930 273,071 257,710
Diversified businesses .................................... 62,289 19,050 88,230 45,666
Total revenues ............................................ 630,351 564,721 1,378,626 1,248,546
Expenses Other Than Interest and Income Taxes
Electric fuel and purchased energy ........................ 120,960 109,677 247,513 244,048
Gas purchased for resale .................................. 31,582 39,059 158,507 149,459
Operations ................................................ 135,932 127,595 285,481 259,676
Maintenance ............................................... 43,544 58,778 88,991 100,555
Diversified businesses - selling, general, and administrati 51,787 16,383 66,904 32,821
Depreciation and amortization ............................. 67,934 61,893 137,713 123,267
Taxes other than income taxes ............................. 43,734 43,949 96,529 95,239
Total expenses other than interest and income taxes ....... 495,473 457,334 1,081,638 1,005,065
Income From Operations ...................................... 134,878 107,387 296,988 243,481
Other Income
Allowance for equity funds used during construction ....... 5,542 3,621 10,616 7,157
Equity in earnings of Safe Harbor Water Power Corporation . 1,088 1,068 2,178 2,136
Net other income and deductions ........................... 1,495 709 2,551 984
Total other income ........................................ 8,125 5,398 15,345 10,277
Income Before Interest and Income Taxes ..................... 143,003 112,785 312,333 253,758
Interest Expense
Interest charges .......................................... 53,569 52,633 105,769 105,367
Capitalized interest ...................................... (3,010) (5,032) (5,811) (9,097)
Allowance for borrowed funds used during construction ..... (2,998) (2,004) (5,739) (4,083)
Net interest expense ...................................... 47,561 45,597 94,219 92,187
Income Before Income Taxes .................................. 95,442 67,188 218,114 161,571
Income Taxes
Current ................................................... 10,742 (8,573) 23,886 21,108
Deferred .................................................. 20,033 21,974 49,456 23,044
Investment tax credit adjustments ......................... (2,041) (2,089) (4,081) (4,253)
Total income taxes ........................................ 28,734 11,312 69,261 39,899
Net Income .................................................. 66,708 55,876 148,853 121,672
Preferred and Preference Stock Dividends .................... 10,021 10,576 20,052 21,095
Earnings Applicable to Common Stock ...................... $ 56,687 $ 45,300 $ 128,801 $ 100,577
Average Shares of Common Stock Outstanding ................. 146,947 144,757 146,692 144,471
Total Earnings Per Share of Common Stock .................... $0.39 $0.31 $0.88 $0.70
Dividends Declared Per Share of Common Stock ................ $0.3 $0.37 $0.75 $0.74
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)
CONSOLIDATED BALANCE SHEETS June 30, December 31,
<CAPTION>
1994* 1993
(In Thousands)
<S> <C> <C>
ASSETS
Current Assets
Cash and cash equivalents ................................... $ 49,672 $ 84,236
Accounts receivable (net of allowance for uncollectibles).... 427,585 401,853
Fuel stocks ................................................... 66,060 70,233
Materials and supplies ........................................ 144,855 145,130
Prepaid taxes other than income taxes ......................... 2,706 54,237
Other ......................................................... 31,365 38,971
Total current assets .......................................... 722,243 794,660
Investments and Other Assets
Real estate projects .......................................... 470,913 487,397
Power generation systems ...................................... 298,006 298,514
Financial investments ......................................... 224,771 213,315
Nuclear decommissioning trust fund ............................ 62,806 56,207
Safe Harbor Water Power Corporation ........................... 34,156 34,138
Senior living facilities ...................................... 10,839 2,005
Other ........................................................ 60,643 65,355
Total investments and other assets ............................ 1,162,134 1,156,931
Utility Plant
Plant in service
Electric .................................................... 5,791,670 5,713,259
Gas ......................................................... 578,106 557,942
Common ...................................................... 501,013 487,740
Total plant in service ...................................... 6,870,789 6,758,941
Accumulated depreciation ......................................(2,212,205) (2,161,984)
Net plant in service .......................................... 4,658,584 4,596,957
Construction work in progress ................................. 482,659 436,440
Nuclear fuel (net of amortization) ............................ 153,508 139,424
Plant held for future use ..................................... 24,070 24,066
Net utility plant ............................................. 5,318,821 5,196,887
Deferred Charges
Regulatory Assets
Income taxes recoverable through future rates ................ 262,720 259,856
Deferred fuel costs (net of reserve for possible disallowance) 133,024 130,052
Deferred termination benefit costs (net of amortization)...... 88,455 96,793
Deferred nuclear expenditures (net of amortization) .......... 88,744 86,726
Deferred postemployment benefit costs ........................ 67,900 62,892
Deferred cost of decommissioning federal uranium
enrichment facilities (net of amortization) ................. 53,567 49,562
Deferred energy conservation expenditures (net of amortizatio 37,669 38,655
Deferred environmental costs (net of amortization) ........... 36,298 32,966
Other ........................................................ (3,286) 10,623
Total regulatory assets ...................................... 765,091 768,125
Other ......................................................... 70,612 70,436
Total deferred charges ........................................ 835,703 838,561
TOTAL ASSETS .................................................. $ 8,038,901 $ 7,987,039
</TABLE>
* Unaudited
See Notes to Consolidated Financial Statements.
<PAGE>
<TABLE>
PART I. FINANCIAL INFORMATION (Continued)
CONSOLIDATED BALANCE SHEETS June 30, December 31,
<CAPTION>
1994* 1993
(In Thousands)
<S> <C> <C>
LIABILITIES AND CAPITALIZATION
Current Liabilities
Short-term borrowings ....................................... $ 94,800 $ 0
Current portions of long-term debt and preference stock ....... 45,032 44,516
Accounts payable .............................................. 144,347 195,534
Customer deposits ............................................. 24,275 22,345
Accrued taxes ................................................. 3,317 20,623
Accrued interest .............................................. 61,397 58,541
Dividends declared ............................................ 65,863 63,966
Accrued vacation costs ........................................ 37,771 35,546
Other ......................................................... 17,886 38,716
Total current liabilities ..................................... 494,688 479,787
Deferred Credits and Other Liabilities
Deferred income taxes ......................................... 1,118,778 1,067,611
Deferred investment tax credits ............................... 153,419 157,426
Pension and postemployment benefits ........................... 134,215 183,043
Decommissioning of federal uranium enrichment facilities ...... 48,249 46,858
Other ......................................................... 52,464 56,974
Total deferred credits and other liabilities .................. 1,507,125 1,511,912
Capitalization
Long-term Debt
First refunding mortgage bonds of BGE ......................... 1,763,599 1,802,148
Other long-term debt of BGE ................................... 544,550 482,550
Long-term debt of Constellation Companies ..................... 579,409 597,716
Unamortized discount and premium .............................. (18,698) (17,754)
Current portion of long-term debt ............................. (42,032) (41,516)
Total long-term debt .......................................... 2,826,828 2,823,144
Preferred Stock ................................................. 59,185 59,185
Redeemable Preference Stock ..................................... 344,000 345,500
Current portion of redeemable preference stock ................ (3,000) (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 .................................................. 1,414,426 1,391,464
Retained earnings ............................................. 1,269,882 1,251,140
Pension liability adjustment ................................ (22,093) (22,093)
Net unrealized loss on available-for-sale securities ........ (2,140) 0
Total common shareholders' equity ............................. 2,660,075 2,620,511
Total capitalization .......................................... 6,037,088 5,995,340
TOTAL LIABILITIES AND CAPITALIZATION ......... ................. $ 8,038,901 $ 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>
Six Months Ended June 30,
1994 1993
(In Thousands)
<S> <C> <C>
Cash Flows From Operating Activities
Net income ................................................... $ 148,853 $ 121,672
Adjustments to reconcile to net cash provided by operating activities
Depreciation and amortization .............................. 161,641 146,898
Deferred income taxes ...................................... 49,456 23,044
Investment tax credit adjustments .......................... (4,081) (4,253)
Deferred fuel costs ........................................ (2,972) 42,033
Accrued pension and postemployment benefits ................ (53,833) 4,866
Allowance for equity funds used during construction......... (10,616) (7,157)
Equity in earnings of affiliates and joint ventures (1,697) 5,300
Changes in current assets ......................... 36,880 27,639
Changes in current liabilities, other than short-te......... (80,522) (40,790)
Other ...................................................... 17,672 (2,108)
Net cash provided by operating activities .................... 260,781 317,144
Cash Flows From Financing Activities
Proceeds from issuance of
Short-term borrowings (net) ................................ 94,800 (10,400)
Long-term debt ............................................. 203,018 702,794
Preference stock ........................................... 0 39,650
Common stock ............................................... 22,945 26,133
Reacquisition of long-term debt .............................. (213,319) (680,366)
Redemption of preference stock ............................... (1,500) 0
Common stock dividends paid .................................. (108,234) (103,684)
Preferred and preference stock dividends paid ................ (19,964) (21,040)
Other ........................................................ (36) (261)
Net cash used in financing activities ........................ (22,290) (47,174)
Cash Flows From Investing Activities
Utility construction expenditures ............................ (227,091) (202,864)
Allowance for equity funds used during construction .......... 10,616 7,157
Nuclear fuel expenditures .................................... (35,078) (10,458)
Deferred nuclear expenditures ................................ (4,066) (5,408)
Deferred energy conservation expenditures .................... (18,661) (12,063)
Contributions to nuclear decommissioning trust fund .......... (4,890) (4,450)
Purchases of marketable equity securities .................... (31,076) (19,795)
Sales of marketable equity securities ........................ 20,146 20,778
Other financial investments .................................. (676) 1,682
Real estate projects ......................................... 25,090 (14,252)
Power generation systems ..................................... (5,066) (18,738)
Other ........................................................ (2,303) (730)
Net cash used in investing activities ........................ (273,055) (259,141)
.........
Net Increase (Decrease) in Cash and Cash Equivalents ........... (34,564) 10,829
Cash and Cash Equivalents at Beginning of Period ...... 84,236 27,122
.........
Cash and Cash Equivalents at End of Period ............ $ 49,672 $ 37,951
Other Cash Flow Information
Cash paid during the period for: .........
Interest (net of amounts capitalized) ...................... $ 89,395 $ 90,404
Income taxes ............................................... $ 41,025 $ 35,304
Certain prior-year amounts have been restated to conform with the current year's presentation.
</TABLE>
See Notes to Consolidated Financial Statements.
<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.
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 June 30, 1994, marketable equity securities totaling
$40.7 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 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 is
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 nitrogen oxide (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 2000 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
7
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
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 June 30, 1994, BGE has an
accrual of approximately $27.8 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. Although BGE maintains the various insurance policies
currently available to provide coverage for portions of these
contingencies, BGE does not consider the available insurance to be
adequate to cover the costs that could result from a major accident
or an extended outage at either of the Calvert Cliffs units.
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 $9.2 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.
8
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
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
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
9
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
respect to any given generating plant outage, which could result in
the disallowance of replacement energy costs by the PSC.
Since the two units at BGE's Calvert Cliffs Nuclear Power
Plant utilize BGE's lowest cost fuel, replacement energy costs
associated with outages at these units can be significant. BGE
cannot estimate the amount of replacement energy costs that could
be challenged or disallowed in future fuel rate proceedings, but
such amounts could be material.
In October 1988, BGE filed its first fuel rate application
for a change in its electric fuel rate under GUPP. The resultant
case before the PSC covers BGE's operating performance in calendar
year 1987, and BGE's filing demonstrated that it met the system-
wide and individual nuclear plant performance targets for 1987. In
November 1989, testimony was filed on behalf of the Maryland
People's Counsel (People's Counsel) alleging that seven outages at
the Calvert Cliffs plant in 1987 were due to management imprudence
and that the replacement energy costs associated with those outages
should be disallowed by the Commission. Total replacement energy
costs associated with the 1987 outages were approximately $33
million.
In May 1989, BGE filed its fuel rate case in which 1988
performance was examined. BGE met the system-wide and nuclear
plant performance targets in 1988. People's Counsel alleged that
BGE imprudently managed several outages at Calvert Cliffs, and BGE
estimates that the total replacement energy costs associated with
these 1988 outages were approximately $2 million. On November 14,
1991, a Hearing Examiner at the PSC issued a proposed Order, which
became final on December 17, 1991 and concluded that no
disallowance was warranted. The Hearing Examiner found that BGE
maintained the productive capacity of the Plant at a reasonable
level, noting that it produced a near record amount of power and
exceeded the GUPP standard. Based on this record, the Order
concluded there was sufficient cause to excuse any avoidable
failures to maintain productive capacity at higher levels.
During 1989, 1990, and 1991, BGE experienced extended outages
at its Calvert Cliffs Nuclear Power Plant. In the Spring of 1989,
a leak was discovered around the Unit 2 pressurizer heater sleeves
during a refueling outage. BGE shut down Unit 1 as a precautionary
measure on May 6, 1989, to inspect for similar leaks and none were
found. However, Unit 1 was out of service for the remainder of
1989 and 285 days of 1990 to undergo maintenance and modification
work to enhance the reliability of various safety systems, to
repair equipment, and to perform required periodic surveillance
tests. Unit 2, which returned to service on May 4, 1991, remained
out of service for the remainder of 1989, 1990, and the first part
of 1991 to repair the pressurizer, perform maintenance and
modification work, and complete the refueling. The replacement
energy costs associated with these extended outages for both units
at Calvert Cliffs, concluding with the return to service of Unit 2,
are estimated to be $458 million.
10
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
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 SIX MONTHS ENDED JUNE 30,
1994 COMPARED WITH THE CORRESPONDING PERIODS OF 1993
Earnings per Share of Common Stock
Consolidated earnings per share for the quarter and six months
ended June 30, 1994 were $.39 and $.88, respectively, which
represent increases of $.08 and $.18 compared to the earnings for
the corresponding periods of 1993. These increases in earnings per
share reflect a higher level of earnings applicable to common
stock, offset slightly by the larger number of common shares
outstanding. The earnings per share are summarized as follows:
Quarter Ended Six Months Ended
June 30 June 30
1994 1993 1994 1993
Utility operations............. $.38 $.28 $.86 $.66
Diversified businesses......... .01 .03 .02 .04
Total.......................... $.39 $.31 $.88 $.70
Earnings Applicable to Common Stock
Earnings applicable to common stock increased $11.4 million
during the quarter and $28.2 million during the six months ended
June 30, 1994. These increases reflect significantly higher
earnings from the utility operations, offset slightly by lower
earnings from diversified businesses.
Earnings from utility operations increased during the second
quarter of 1994 primarily as a result of increased electric sales
and lower maintenance expenses compared to the second quarter of
1993. Two principal factors produced the increase in sales of
electricity: the spring and early summer of 1994 were significantly
hotter than 1993; and the number of customers increased moderately.
The effect of weather on utility sales is discussed on pages 13 and
14.
12
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
In addition to the factors noted above for the second quarter
of 1994, earnings from utility operations during the six months
ended June 30, 1994 also reflect increased electric system sales
and gas sales caused by colder winter weather and a moderate
increase in the number of customers during the first quarter of
1994 as compared to the first quarter of 1993. These increases
were offset partially by higher operations expense, depreciation
and amortization expenses, and the effect of the Omnibus Budget
Reconciliation Act of 1993 (1993 Tax Act), which increased the
federal corporate income tax rate to 35% from 34%.
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), were
slightly lower during the quarter and six months ended June 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 below presents information regarding heating and
cooling degree days for the quarter and six months ended June 30,
1994 and 1993.
13
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
Quarter Ended Six Months Ended
June 30 June 30
1994 1993 1994 1993
Heating degree days............ 444 5413,196
3,104
Percent change compared to
prior period.................. (17.9)% 3.0%
Cooling degree days............ 320 213 320 213
Percent change compared to
prior period.................. 50.2% 50.2%
BGE Utility Revenues and Sales
Electric revenues changed during 1994 because of the following
factors:
Quarter Ended Six Months Ended
June 30 June 30
1994 vs. 1993 1994 vs. 1993
(In millions)
System sales volumes.......... $17.7 $53.9
Base rates.................... 3.1 15.4
Fuel rates.................... 0.3 (9.4)
Revenues from system sales.... 21.1 59.9
Interchange sales............. 9.8 13.6
Other revenues................ (0.5) (1.3)
Total......................... $30.4 $72.2
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 Six Months Ended
June 30 June 30
1994 vs. 1993 1994 vs. 1993
Residential................... 2.7% 8.4%
Commercial.................... 2.9 1.6
Industrial.................... 29.5 18.1
Total......................... 6.9 6.7
Sales to all classes of electric customers reflect the
positive impact of hotter spring and early summer weather and
moderate customer growth during the second quarter of 1994 as
compared to the second quarter of 1993. Sales to industrial
customers also 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.
In addition to the factors noted above for the second quarter
of 1994, electric system sales for the six months ended June 30,
1994 reflect severe winter weather conditions during the first
quarter of 1994. The increase in sales to commercial customers was
partially offset by lower usage-per-customer.
Base rates increased in 1994 for two principal reasons: the
PSC's April 1993 rate order and an increased 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 rate revenues are expected to increase during the
remainder of 1994 as a result of recovering a higher level of
electric conservation program costs under the energy conservation
surcharge. However, 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. BGE has been earning in excess of its authorized rate of
return on electric operations since September 30, 1993. As a
result, BGE has deferred the portion of electric energy
conservation revenues subject to refund beginning in December 1993.
The deferral of these billings is expected to average approximately
$1.7 million each month these deferrals continue. The amounts
deferred during a surcharge year will begin to be refunded to
customers with interest in the ensuing July when the annual
15
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
resetting of the conservation surcharge rates occurs. The deferral
will continue as long as BGE exceeds its authorized rate of return
on electric operations, as determined by the PSC.
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 were essentially flat during the second
quarter of 1994 as the effect of increased electric system sales
volumes offset the lower fuel rate. Fuel rate revenues decreased
during the six months ended June 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 1994 because of a less-costly
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 six months ended June 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.
Gas revenues changed during 1994 because of the following
factors:
Quarter Ended Six Months Ended
June 30 June 30
1994 vs. 1993 1994 vs. 1993
(In millions)
Sales volumes................. $(1.2) $5.0
Base rates.................... 0.5 1.2
Gas cost adjustment revenues.. (6.9) 10.1
Other revenues................ (0.4) (0.9)
Total......................... $(8.0) $15.4
16
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
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 Six Months Ended
June 30 June 30
1994 vs. 1993 1994 vs. 1993
Residential................... 0.7% 6.4%
Commercial.................... (10.8) (3.9)
Industrial.................... 4.7 (5.6)
Total......................... (1.0) (0.3)
Total gas sales for the second quarter of 1994 decreased
slightly compared to last year as the lower sales to commercial
customers offset the higher sales to residential and industrial
customers. Sales to commercial customers were affected negatively
by warmer weather conditions and lower usage-per-customer. The
increase in sales to industrial customers reflects primarily the
greater usage of natural gas by Bethlehem Steel in its production
process.
Total gas sales for the six months ended June 30, 1994 were
essentially flat compared to 1993 because higher sales to
residential customers were offset by lower sales to commercial and
industrial 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 commercial and industrial customers
decreased primarily 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 in
exchange for BGE's right to interrupt service during periods of
peak demand.
Base rates increased slightly during 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 in 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
17
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
Form 10-K.) Changes in gas cost adjustment revenues normally do
not affect earnings.
Gas cost adjustment revenues decreased during the second
quarter of 1994 because of lower sales volumes subject to gas cost
adjustment clauses and decreased prices of purchased gas. During
the six months ended June 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 Six Months Ended
June 30 June 30
1994 1993 1994 1993
(In millions)
Actual costs.................. $119.9 $105.0 $273.2 $227.8
Net (deferral) recovery of
costs under electric fuel
rate clause (see Note 1 of
the Form 10-K)............... 1.1 4.7 (25.7) 16.2
Total......................... $121.0 $109.7 $247.5 $244.0
Electric fuel and purchased energy expenses increased during
the quarter and six months ended June 30, 1994 because of
significant increases in actual fuel costs, offset partially by
changes in deferred fuel costs as a result of the operation of the
electric fuel rate clause.
Actual electric fuel and purchased energy costs increased
during the quarter ended June 30, 1994 as a result of higher net
output of electricity generated to meet the demand of BGE's system
and the PJM system and a more costly generation mix.
Actual electric fuel and purchased energy costs increased
during the six months ended June 30, 1994 primarily due to the
higher cost of BGE's generation mix. The cost of the generation
mix increased due to refueling and maintenance outages at Calvert
Cliffs Nuclear Power Plant and higher purchased energy costs during
the first quarter.
18
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
Purchased gas expenses were as follows:
Quarter Ended Six Months Ended
June 30 June 30
1994 1993 1994 1993
(In millions)
Actual costs.................. $30.5 $44.5 $153.2 $141.5
Net (deferral) recovery of
costs under purchased gas
adjustment clause (see Note
1 of the Form 10-K).......... 1.1 (5.4) 5.3 8.0
Total......................... $31.6 $39.1 $158.5 $149.5
Actual purchased gas costs decreased during the quarter ended
June 30, 1994 as a result of lower output associated with the
reduced demand for BGE gas and, to a lesser extent, lower gas
prices. The lower gas prices primarily reflect $6.5 million of
take-or-pay refunds and other market conditions.
Actual purchased gas costs increased during the six months
ended June 30, 1994 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 the take-or-pay and other supplier refunds.
The take-or-pay refunds 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. A portion of this refund was returned to customers during
June, 1994. The remainder of the refund will be returned to BGE's
gas customers over the next three quarters pursuant to an agreement
with the PSC.
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 gas
pipeline suppliers. These transition costs, if approved by FERC,
will be passed on to BGE customers through the purchased gas
adjustment clause.
19
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
Other Operating Expenses
Operations expense increased during the quarter and six months
ended June 30, 1994 because the quarter ended June 30, 1993
reflected a reduction in utility operations expense equivalent to
the $9.8 million cost of termination benefits associated with the
Company's 1992 Voluntary Special Early Retirement Program (VSERP).
Excluding this factor, operations expense for the second quarter of
1994 was approximately $1.5 million lower than last year as the
labor savings achieved from employee reduction programs exceeded
the higher amortization of the deferred VSERP costs (See Note 7 of
the Form 10-K), higher uncollectible expenses, and increased
pension costs and postretirement benefit expenses resulting from
the implementation of Statement of Financial Accounting Standards
No. 106 (see Note 6 of the Form 10-K).
In addition to the factors noted above for the second quarter
of 1994, operations expense for the six months ended June 30, 1994
reflects a one-time bonus paid to employees during the first
quarter of 1994 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 six
months ended June 30, 1994 primarily because of lower costs at the
Calvert Cliffs Nuclear Power Plant.
Depreciation and amortization expense increased during the
second quarter of 1994 because of a higher level of energy
conservation program costs, higher depreciable plant in service,
and amortization of deferred environmental costs for certain
Company-owned sites beginning in October 1993. (See Environmental
Matters on page 23.) 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.
20
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
Other Income and Expenses
The allowance for funds used during construction (AFC)
increased during the quarter and six months ended June 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.
Interest charges increased slightly during both periods of
1994 as the impact of a higher level of outstanding debt was offset
substantially by a decline in the level of interest rates and the
redemption of higher cost coupon debt of BGE.
Capitalized interest decreased during the quarter and six
months ended June 30, 1994 due to lower capitalized interest on the
Constellation Companies' power generation systems projects. The
decrease during the six 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 increased during both periods of 1994
because of higher pre-tax earnings and the effect of the 1993 Tax
Act, which increased the federal corporate income tax rate to 35%
from 34%.
Diversified Businesses Earnings
Earnings per share from diversified businesses were:
Quarter Ended Six Months Ended
June 30 June 30
1994 1993 1994 1993
Power generation systems...... $.00 $.03 $.01 $.04
Financial investments......... .01 .01 .02 .02
Real estate development and
senior living facilities..... .00 (.01) (.01) (.02)
Total......................... $.01 $.03 $.02 $.04
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 lower
for both periods of 1994 as the second quarter of 1993 included the
recognition of $8 million of energy tax credits related to the Puna
geothermal plant, offset partially by a $4 million after-tax charge
related to fuel supply problems at the Panther Creek waste-coal
project.
21
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
The Constellation Companies' investment in wholesale power
generating projects includes $161 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 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.
The Company cannot predict the impact these matters 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 unchanged in 1994.
The Constellation Companies' real estate development business
includes land under development; office buildings; retail projects;
commercial projects; an entertainment, dining and retail complex in
Orlando, Florida; a mixed-use planned-unit-development; and senior
living facilities. The majority of these projects are in the
Baltimore-Washington corridor. They have been affected adversely by
the depressed real estate market and economic conditions, resulting
in reduced demand for the purchase or lease of available land,
office, and retail space. Earnings from real estate development
and senior living facilities for the quarter and six months ended
June 30, 1994 improved slightly 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 both periods 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
22
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
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.
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.
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 and 8 of this Report.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity
For the twelve months ended June 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 3.27 and 2.55, respectively.
23
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
Capital Requirements
The Company's capital requirements reflect the capital-
intensive nature of the utility business. Actual capital
requirements for the six months ended June 30, 1994, along with
estimated annual amounts for the years 1994 through 1996, are
reflected below.
Six Months Ended
June 30 Calendar Year Estimate
1994 1994 1995 1996
(In millions)
Utility Business:
Construction expenditures
(excluding AFC)
Electric........................ $173 $345 $241 $223
Gas............................. 24 52 53 69
Common.......................... 14 53 56 48
Total construction expenditures. 211 450 350 340
AFC............................. 16 34 34 20
Deferred nuclear expenditures... 4 13 - -
Deferred energy conservation
expenditures.................... 19 48 45 40
Nuclear fuel (uranium purchases
and processing charges)......... 35 49 56 59
Retirement of long-term debt
and redemption of preference
stock .......................... 180 203 268 98
Total utility business.......... 465 797 753 557
Diversified Businesses:
Retirement of long-term debt.... 34 37 88 60
Investment requirements......... 26 59 65 19
Total diversified businesses.... 60 96 153 79
Total............................ $525 $893 $906 $636
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 the 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 June 30, 1994, the internal
generation of cash from utility operations provided 66% 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
24
<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 $3 million, respectively, exclusive
of any redemption premiums or discounts. The amount and timing of
future issuances and redemptions will depend upon market conditions
and BGE's actual capital requirements.
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 23
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.
25
<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 24 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.
26
<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 $81.1 million. In
addition, the Constellation Companies had loaned $5.5 million
(including accrued interest) to the other partner in PGV for use
in funding venture costs but such loan has been repaid. 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 24 includes $11 million for the year
1994 and $14 million for the year 1995 relating to the Puna
project. Of this amount, approximately $11 million is additional
costs to deal with the problems with the production wells
described below and approximately $14 million 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.
PGV currently has two production wells that provide steam to
power the project. During November 1993, one of the production
wells changed from a steam dominated resource to a brine
dominated resource. The result is that the well produces
considerably more fluid to inject back into the ground. As a
result certain modifications to the brine handling system have
recently been completed. In addition, during April 1994, an
obstruction in the well casing was detected in the other
production well during routine testing. PGV is in the process of
removing the obstruction in the casing. Until certain of the
27
<PAGE>
PART II. OTHER INFORMATION (Continued)
above-mentioned actions are completed, along with the possible
drilling of additional wells, if required, the project is not
expected to operate at its full capacity.
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. A
tentative settlement has been agreed to which requires no
additional capital contributions from the Constellation
Companies.
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.
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
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
28
<PAGE>
PART II. OTHER INFORMATION (Continued)
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. During the second
quarter of 1994, an additional environmental action was
instituted.
On May 3, 1994 Constellation Energy was named as a defendant in
Republic Imperial Acquisition v. Stockmar Energy, Inc., et al.
Civil No. 940120R(LSP) (Dist. Ct., So. Dist. California). The
plaintiffs are owners of a non-hazardous waste landfill located
in Imperial County, California. The plaintiffs allege that
defendants delivered hazardous materials consisting of spent
geothermal filters containing certain metals used in the
operation of four geothermal projects. The claims are made under
the Federal Comprehensive Environmental Response, Compensation
and Liability Act (Superfund statute) and state and common law
against the operators, project owners and others.
Certain Constellation Energy subsidiaries have ownership
interests in three of the projects. These Constellation
Companies have indemnification rights from project lessees and
operators. There are approximately 45 other potentially
responsible parties in addition to the Constellation Companies.
The Constellation Companies are currently evaluating the claims
and site investigation is at a preliminary stage. As a result,
total investigation and clean up costs, as well as the
Constellation Companies' share of such costs, cannot presently be
estimated.
29
<PAGE>
Item 4. Submission of Matters to a Vote of Security Holders
On April 20, 1994, BGE held its annual meeting of shareholders.
At that meeting, the following matters were voted upon:
1. All of the Directors nominated by BGE were elected as
follows:
COMMON SHARES CAST:
FOR AGAINST ABSTAIN
H. F. Baldwin 121,153,040 757,152 1,401,613
B. B. Byron 120,740,613 1,169,579 1,401,613
J. O. Cole 121,287,153 623,039 1,401,613
D. A. Colussy 121,276,540 633,652 1,401,613
E. A. Crooke 121,009,627 900,565 1,401,613
J. R. Curtiss 121,169,009 741,183 1,401,613
J. W. Geckle 121,289,166 621,026 1,401,613
F. A. Hrabowski,III 121,010,751 899,441 1,401,613
N. Lampton 121,013,321 896,871 1,401,613
G. V. McGowan 120,998,755 911,437 1,401,613
P. G. Miller 121,045,351 864,841 1,401,613
C. H. Poindexter 119,359,874 2,550,318 1,401,613
G. L. Russell, Jr. 121,088,049 822,143 1,401,613
M. D. Sullivan 118,142,899 3,767,292 1,401,613
2. Coopers and Lybrand was reelected as auditor, and with
respect to holders of common stock, the number of affirmative
votes cast were 121,517,116. The number of negative votes cast
were 958,416, and the number of abstentions were 1,244,814.
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) Form 8-K None
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act
of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned thereunto duly authorized.
BALTIMORE GAS AND ELECTRIC COMPANY
(Registrant)
Date August 12, 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.
32
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
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
June December December December December December
1994 1993 1992 1991 1990 1989
(In Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
Net Income $337,047 $309,866 $264,347 $233,681 $175,446 $276,291
Taxes on Income 170,242 140,833 105,994 88,041 22,818 84,704
Adjusted Net Income $507,289 $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 $202,934 $199,415 $200,848 $213,616 $194,656 167,503
Capitalized Interest 12,881 16,167 13,800 20,953 25,748 5,842
Interest Factor in Rentals 1,975 2,144 2,033 1,801 1,840 2,388
Total Fixed Charges $217,790 $217,726 $216,681 $236,370 $222,244 $175,733
Preferred and Preference
Dividend Requirements: (1)
Preferred and Preference Dividends $ 40,795 $ 41,839 $ 42,247 $ 42,746 $ 40,261 $ 32,381
Income Tax Required 20,344 18,763 6,729 15,916 5,166 9,779
Total Preferred and Preference
Dividend Requirements $ 61,139 $ 60,602 $ 58,976 $ 58,662 $ 45,427 $ 42,160
Total Fixed Charges and Preferred
and Preference Dividend Requirements $278,929 $278,328 $275,657 $295,032 $267,671 $217,893
Earnings (2) $712,198 $652,258 $573,222 $537,139 $394,760 $530,886
Ratio of Earnings to Fixed Charges 3.27 3.00 2.65 2.27 1.78 3.02
Ratio of Earnings to Combined Fixed
Charges and Preferred and Preference
Dividend Requirements 2.55 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>
