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FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended March 31, 1994
Commission file number 1-1910
BALTIMORE GAS AND ELECTRIC COMPANY
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(Exact name of registrant as specified in its charter)
Maryland 52-0280210
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(State of incorporation) (IRS Employer Identification No.)
Gas and Electric Building, Charles Center,
Baltimore, Maryland 21201
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code 410-783-5920
Not Applicable
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(Former name, former address and former fiscal year, if changed
since last report)
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months,
and (2) has been subject to such filing requirements for the past
90 days.
Yes X No
Common Stock, without par value - 146,902,361 shares outstanding
on April 30, 1994.
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BALTIMORE GAS AND ELECTRIC COMPANY
PART I. FINANCIAL INFORMATION
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
Quarter Ended March 31,
1994 1993
(In Thousands, Except Per-Share Amounts)
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Revenues
Electric ................................................ $ 517,147 $ 475,429
Gas ..................................................... 205,186 181,780
Diversified businesses .................................. 25,942 26,616
Total revenues ............................................. 748,275 683,825
Expenses Other Than Interest and In
Electric fuel and purchased energy ...................... 126,554 134,371
Gas purchased for resale ................................ 126,926 110,400
Operations .............................................. 171,924 151,036
Maintenance ............................................. 45,566 41,896
Depreciation ............................................ 62,400 58,738
Taxes other than income taxes ........................... 52,795 51,290
Total expenses other than interest and income taxes ..... 586,165 547,731
Income From Operations .................................... 162,110 136,094
Other Income
Allowance for equity funds used during construction ..... 5,074 3,535
Equity in earnings of Safe Harbor Water Power Corporation 1,089 1,068
Net other income and deductions ......................... 1,056 276
Total other income ...................................... 7,219 4,879
Income Before Interest and Income Taxes ................... 169,329 140,973
Interest Expense
Interest charges ........................................ 52,199 52,733
Capitalized interest .................................... (2,801) (4,065)
Allowance for borrowed funds used during construction ... (2,742) (2,078)
Net interest expense .................................... 46,656 46,590
Income Before Income Taxes ................................ 122,673 94,383
Income Taxes
Current ................................................. 13,144 29,681
Deferred ................................................ 29,423 1,070
Investment tax credit adjustments ....................... (2,039) (2,164)
Total income taxes ...................................... 40,528 28,587
Net Income ................................................ 82,145 65,796
Preferred and Preference Stock Dividends .................. 10,031 10,520
Earnings Applicable to Common Stock ....................... $ 72,114 $ 55,276
Average Shares of Common Stock Outstanding ............... 146,437 144,184
Earnings Per Share of Common Stock ........................ $0.49 $0.38
Dividends Declared Per Share of Common Stock .............. $0.3 $0.36
Certain prior-year amounts have been restated to conform with the current year's presentation.
See Notes to Consolidated Financial Statements.
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PART I. FINANCIAL INFORMATION (Continued)
CONSOLIDATED BALANCE SHEETS March 31, December 31,
1994* 1993
(In Thousands)
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ASSETS
Current Assets
Cash and cash equivalents ................................... $ 100,386 $ 84,236
Accounts receivable (net of allowance for uncollectibles).... 438,661 401,853
Fuel stocks ................................................... 39,568 70,233
Materials and supplies ........................................ 141,584 145,130
Prepaid taxes other than income taxes ......................... 25,399 54,237
Other ......................................................... 33,494 38,971
Total current assets .......................................... 779,092 794,660
Investments and Other Assets
Real estate projects .......................................... 488,042 487,397
Power generation systems ...................................... 295,997 298,514
Financial investments ......................................... 223,424 213,315
Nuclear decommissioning trust fund ............................ 62,073 56,207
Safe Harbor Water Power Corporation ........................... 34,147 34,138
Senior living facilities ...................................... 2,073 2,005
Other ........................................................ 64,963 65,355
Total investments and other assets ............................ 1,170,719 1,156,931
Utility Plant
Plant in service
Electric .................................................... 5,753,691 5,713,259
Gas ......................................................... 566,732 557,942
Common ...................................................... 493,021 487,740
Total plant in service ...................................... 6,813,444 6,758,941
Accumulated depreciation ......................................(2,212,954) (2,161,984)
Net plant in service .......................................... 4,600,490 4,596,957
Construction work in progress ................................. 468,594 436,440
Nuclear fuel (net of amortization) ............................ 136,571 139,424
Plant held for future use ..................................... 24,069 24,066
Net utility plant ............................................. 5,229,724 5,196,887
Deferred Charges
Regulatory Assets
Income taxes recoverable through future rates ................ 260,123 259,856
Deferred fuel costs (net of reserve for possible disallowance) 143,589 130,052
Deferred termination benefit costs (net of amortization) ..... 93,360 96,793
Deferred nuclear expenditures (net of amortization) .......... 87,849 86,726
Deferred postemployment benefit costs (net of amortization) .. 65,625 62,892
Deferred cost of decommissioning federal uranium
enrichment facilities (net of amortization) ................. 48,661 49,562
Deferred energy conservation expenditures (net of amortization 37,122 38,655
Deferred environmental costs (net of amortization) ........... 32,432 32,966
Other regulatory assets ...................................... 2,854 10,623
Total regulatory assets ...................................... 771,615 768,125
Other ......................................................... 72,340 70,436
Total deferred charges ........................................ 843,955 838,561
TOTAL ASSETS .................................................. $ 8,023,490 $ 7,987,039
* Unaudited
See Notes to Consolidated Financial Statements.
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PART I. FINANCIAL INFORMATION (Continued)
CONSOLIDATED BALANCE SHEETS March 31, December 31,
1994* 1993
(In Thousands)
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LIABILITIES AND CAPITALIZATION
Current Liabilities
Current portions of long-term debt and preference stock ..... $ 74,396 $ 44,516
Accounts payable .............................................. 168,218 195,534
Customer deposits ............................................. 23,496 22,345
Accrued taxes ................................................. 40,616 20,623
Accrued interest .............................................. 56,878 58,541
Dividends declared ............................................ 64,232 63,966
Accrued vacation costs ........................................ 37,767 35,546
Other ......................................................... 14,804 38,716
Total current liabilities ..................................... 480,407 479,787
Deferred Credits and Other Liabilities
Deferred income taxes ......................................... 1,097,607 1,067,611
Deferred investment tax credits ............................... 155,423 157,426
Pension and postemployment benefits ........................... 146,723 183,043
Decommissioning of federal uranium enrichment facilities ...... 46,858 46,858
Other ......................................................... 53,875 56,974
Total deferred credits and other liabilities .................. 1,500,486 1,511,912
Capitalization
Long-term Debt
First refunding mortgage bonds of BGE ......................... 1,867,237 1,802,148
Other long-term debt of BGE ................................... 469,550 482,550
Long-term debt of Constellation Companies ..................... 592,696 597,716
Unamortized discount and premium .............................. (17,755) (17,754)
Current portion of long-term debt ............................. (71,396) (41,516)
Total long-term debt .......................................... 2,840,332 2,823,144
Preferred Stock ................................................. 59,185 59,185
Redeemable Preference Stock ..................................... 345,500 345,500
Current portion of redeemable preference stock ................ (3,000) (3,000)
Total redeemable preference stock ............................. 342,500 342,500
Preference Stock Not Subject to Mandatory Redemption ............ 150,000 150,000
Common Shareholders' Equity
Common stock without par value, 175,000,000 shares authorized;
146,489,290 and 146,034,014 shares issued and outstanding at
March 31, 1994 and December 31, 1993, respectively ......... 1,403,052 1,391,464
Retained earnings ........................................... 1,269,053 1,251,140
Pension Liability adjustment ................................ (22,093) (22,093)
Net unrealized gain on available-for-sale securities ........ 568 0
Total common shareholders' equity ............................. 2,650,580 2,620,511
Total capitalization .......................................... 6,042,597 5,995,340
TOTAL LIABILITIES AND CAPITALIZATION .......................... $ 8,023,490 $ 7,987,039
* Unaudited
See Notes to Consolidated Financial Statements.
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PART I. FINANCIAL INFORMATION (Continued)
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Quarter Ended March 31,
1994 1993
(In Thousands)
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Cash Flows From Operating Activities
Net income ................................................... $ 82,145 $ 65,796
Adjustments to reconcile to net cash provided by operating activities
Depreciation and amortization .............................. 81,598 75,124
Deferred income taxes ...................................... 29,423 1,070
Investment tax credit adjustments .......................... (2,039) (2,164)
Deferred fuel costs ........................................ (13,537) 34,489
Accrued pension and postemployment benefits ................ (38,426) 2,676
Allowance for equity funds used during construction......... (5,074) (3,535)
Equity in earnings of affiliates and joint ventures 2,870 8,515
Changes in current assets ......................... 30,119 22,139
Changes in current liabilities, other than short-te......... (29,277) 8,576
Other ...................................................... 13,397 2,593
Net cash provided by operating activities .................... 151,199 215,279
Cash Flows From Financing Activities
Proceeds from issuance of
Short-term borrowings (net) ................................ - (11,900)
Long-term debt ............................................. 124,090 406,072
Common stock ............................................... 11,588 10,703
Reacquisition of long-term debt .............................. (79,180) (122,333)
Common stock dividends paid .................................. (54,033) (51,762)
Preferred and preference stock dividends paid ................ (9,934) (10,520)
Other ........................................................ 11 (255)
Net cash provided by (used in) financing activities .......... (7,458) 220,005
Cash Flows From Investing Activities
Utility construction expenditures ............................ (93,357) (80,016)
Allowance for equity funds used during construction .......... 5,074 3,535
Nuclear fuel expenditures .................................... (7,659) (6,133)
Deferred nuclear expenditures ................................ (2,132) (2,451)
Deferred energy conservation expenditures .................... (9,495) (4,978)
Contributions to nuclear decommissioning trust fund .......... (2,445) (2,225)
Purchases of marketable equity securities .................... (21,809) (9,583)
Sales of marketable equity securities ........................ 10,815 13,435
Other financial investments .................................. 533 491
Real estate projects ......................................... (3,383) (6,455)
Power generation systems ..................................... (4,412) (9,422)
Other ........................................................ 679 (122)
Net cash used in investing activities ........................ (127,591) (103,924)
.........
Net Increase in Cash and Cash Equivalents ...................... 16,150 331,360
Cash and Cash Equivalents at Beginning of Period ...... 84,236 27,122
.........
Cash and Cash Equivalents at End of Period ............ $ 100,386 $ 358,482
Other Cash Flow Information
Cash paid during the period for: .........
Interest (net of amounts capitalized) ...................... $ 47,470 $ 43,345
Income taxes ............................................... $ 64 $ 8,755
Certain prior-year amounts have been restated to conform with the current year's presentation.
See Notes to Consolidated Financial Statements.
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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 March 31, 1994, marketable equity securities
totaling $42.4 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. The premiums paid 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
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PART I. FINANCIAL INFORMATION (Continued)
Redemption
Price as a
Principal % of the
Amount RedemptionPrincipal
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
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 Companies 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 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.
7
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PART I. FINANCIAL INFORMATION (Continued)
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. In 1993, BGE accrued a
liability of approximately $25.4 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 $9.3 billion. If
third party claims relating to such an incident exceed $200
million (the amount of primary insurance), BGE's share of the
total liability for third party claims could be up to $159
million per incident, that would be payable at a rate of $20
million per year.
BGE and other operators of commercial nuclear power plants
in the United States are required to purchase insurance to cover
claims of certain nuclear workers. Other non-governmental
commercial nuclear facilities may also purchase such insurance.
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PART I. FINANCIAL INFORMATION (Continued)
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 respect to any given generating plant outage,
which could result in the disallowance of replacement energy
costs by the PSC.
9
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PART I. FINANCIAL INFORMATION (Continued)
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
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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
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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 ENDED MARCH 31, 1994 COMPARED
WITH THE CORRESPONDING PERIOD OF 1993
Earnings per Share of Common Stock
Consolidated earnings per share were $.49 for the quarter ended
March 31, 1994 and $.38 for the quarter ended March 31, 1993. The
$.11 increase in earnings per share reflects a higher level of
earnings applicable to common stock, offset slightly by the larger
number of outstanding common shares. The earnings-per-share are
summarized as follows:
Quarter Ended
March 31
1994 1993
Utility businesses........................... $.48 $.37
Diversified businesses....................... .01 .01
Total........................................ $.49 $.38
Earnings Applicable to Common Stock
Earnings applicable to common stock increased $16.8 million
during the quarter ended March 31, 1994. The 1994 increase reflects
higher utility earnings and essentially unchanged earnings from
diversified businesses.
Utility earnings increased during the quarter as a result of
increased electric and gas sales and increased base rates compared to
the first quarter of 1993. Two principal factors produced the increase
in sales of electricity: the winter of 1994 was colder than 1993; and
the number of customers increased moderately. The effect of weather on
utility sales is discussed below. The 1994 earnings increases were
partially offset by higher operations and maintenance expenses,
depreciation expense, and property taxes, and the effect of the
Omnibus Budget Reconciliation Act of 1993 (1993 Tax Act) enacted in
June 1993, 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 will affect 1994 utility
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PART I. FINANCIAL INFORMATION (Continued)
earnings favorably. Several electric fuel rate cases now pending
before the PSC as 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. During 1993, unfavorable economic conditions
diminished electric and gas sales growth in BGE's service territory.
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 essentially
unchanged during the quarter ended March 31, 1994. Diversified
businesses earnings are discussed on pages 19 through 21.
Effect of Weather on Utility Sales
Weather conditions affect BGE's utility sales. BGE measures weather
conditions using degree days. A degree day is the difference between
the average daily actual temperature and the baseline temperature of
65 degrees. Colder weather during the winter, as measured by greater
heating degree days, results in greater demand for electricity and gas
to operate heating systems. Conversely, warmer weather during the
winter, measured by fewer heating degree days, results in less demand
for electricity and gas to operate heating systems. Hotter weather
during the summer, measured by more cooling degree days, results in
greater demand for electricity to operate cooling systems.
Conversely, cooler weather during the summer, measured by fewer
cooling degree days, results in less demand for electricity to operate
cooling systems. The degree-days chart below presents information
regarding heating degree days for 1994 and 1993.
Quarter Ended
March 31
1994 1993
Heating degree days......................... 2,753 2,564
Percentage change compared to prior
period..................................... 7.4%
13
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
BGE Utility Revenues and Sales
Electric revenues increased during 1994 because of the following
factors:
Quarter Ended
March 31
1994 vs. 1993
(In millions)
System sales volumes........................ $36.2
Base rates.................................. 12.3
Fuel rates.................................. (9.7)
Revenues from system sales.................. 38.8
Interchange sales........................... 3.8
Other revenues.............................. (0.9)
Total....................................... $41.7
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.
Quarter Ended
March 31
1994 vs. 1993
Residential................................. 12.6%
Commercial.................................. 0.5
Industrial.................................. 6.4
Total....................................... 6.4
Severe winter weather conditions during the first quarter of 1994
was the main reason for the increase in total sales compared to last
year. The increases in sales to residential and commercial customers
reflect the colder winter weather and moderate customer growth. The
increase in sales to commercial customers was partially offset by
lower usage-per-customer. The sales increase to industrial customers
reflects an increase in the sale of electricity to Bethlehem Steel,
offset partially by lower usage-per-customer by the remaining
industrial customers.
Base rates increased in 1994 for two principal reasons: the PSC's
April 1993 rate order and an increased recovery of eligible electric
14
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
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%.
The April 1993 rate order and a continued higher level of
recovery of electric conservation program costs under the energy
conservation surcharge will continue to favorably affect base rate
revenues in 1994. However, if the PSC determines that BGE is earning
in excess of its authorized rate of return, BGE will have to refund 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 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 were to disallow recovery of any part of these
costs, earnings would be reduced as discussed in Note 13 of the Form
10-K.
Fuel rate revenues decreased during the first quarter of 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 from greater generation at the
Calvert Cliffs Nuclear Power Plant compared to the first quarter of
1993. BGE expects electric fuel rate revenues to decrease during 1994
because of a continued 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 first quarter of
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 generation from Brandon Shores and continued operation
of the Calvert Cliffs Nuclear Power Plant.
15
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
Gas revenues increased during 1994 because of the following factors:
Quarter Ended
March 31
1994 vs. 1993
(In millions)
Sales volumes................................ $6.2
Base rates................................... 0.7
Gas cost adjustment revenues................. 17.0
Other revenues............................... (0.5)
Total........................................ $23.4
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
March 31
1994 vs. 1993
Residential.................................. 8.3%
Commercial................................... (0.8)
Industrial................................... (14.4)
Total........................................ (0.1)
Total gas sales were flat compared to 1993 because higher sales
to residential customers were offset by lower sales to industrial
customers. The increase in sales to residential customers reflects
the extremely cold winter weather during the first quarter of 1994.
Sales to industrial customers decreased primarily because delivery
service customers, including Bethlehem Steel, either voluntarily
switched their fuel source from natural gas to alternate fuels, or
were involuntarily interrupted by BGE as a result of the extreme
weather conditions. These interruptible customers maintain alternate
fuel sources and pay reduced rates for natural gas in exchange for
BGE's right to interrupt service during periods of peak demand.
Base rates increased 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
favorably affect base rate revenues in 1994.
Changes in gas cost adjustment revenues result from the operation
of the purchased gas adjustment (PGA) clause, which is designed to
recover the actual gas costs incurred (See Note 1 of the Form 10-K).
Changes in gas cost adjustment revenues normally do not affect
earnings. Gas cost adjustment revenues increased during the first
16
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
quarter of 1994 because of higher sales volumes subject to the PGA
clause and increased prices to recover higher costs of purchased gas.
Delivery service sales volumes are not subject to the PGA clause
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
March 31
1994 1993
(In millions)
Actual costs............................... $153.4 $122.8
Net (deferral) recovery of costs
under electric fuel rate
clause (see Note 1 of the
Form 10-K)............................... (26.8) 11.6
Total...................................... $126.6 $134.4
Electric fuel and purchased energy expenses decreased as a result
of the operation of the electric fuel rate clause. BGE deferred $26.8
million of fuel costs during the first quarter of 1994 compared to
recovering $11.6 million of deferred fuel costs during the first
quarter of 1993. This decrease was offset partially by the increase
in actual fuel costs.
Actual electric fuel and purchased energy costs increased during
the first quarter of 1994 for two principal reasons: a more costly
generation mix; and a higher net output of electricity generated to
meet the demand of BGE's system and the PJM system resulting from the
severely cold winter weather during the first quarter of 1994. The
cost of BGE's generation mix increased because of the timing of
refueling and maintenance outages at the Calvert Cliffs Nuclear Power
Plant and higher purchased energy costs.
Purchased gas expenses were as follows:
Quarter Ended
March 31
1994 1993
(In millions)
Actual costs............................... $122.7 $97.0
Net recovery of costs under
purchased gas adjustment
clause (see Note 1 of the
Form 10-K)............................... 4.2 13.4
Total...................................... $126.9 $110.4
17
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
Actual purchased gas costs went up in 1994 for four principal
reasons: higher output to meet greater demand for BGE gas; higher gas
prices caused by market conditions; higher reservation charges; and
higher transition costs related to the implementation of Federal
Energy Regulatory Commission (FERC) Order No. 636. 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.
Other Operating Expenses
Operations expense increased during the first quarter of 1994
primarily because of a one-time bonus paid to employees in lieu of a
general wage increase during 1994, a higher level of amortization of
energy conservation program costs, the accrual of postretirement
benefit expenses resulting from the implementation of Statement of
Financial Accounting Standards No. 106 (see Note 6 of the Form 10-K),
amortization of the deferred Voluntary Special Early Retirement
Program (VSERP) costs, and increased pension costs.
Operations expense is expected to be reduced during the remainder
of 1994 by three factors: cost savings from the 1993 employee
reduction programs are expected to be realized beginning in 1994; the
Company charged to expense a portion of the one-time cost of employee
reduction programs in December 1993; and the expected reduction in
1994 operations expense resulting from the November 1993 sale of a
significant portion of the Constellation Companies' investment in
senior living facilities (see page 20 for a discussion of the sale of
senior living facilities). These decreases will be offset partially
by the continued increase in the level of amortization of the deferred
VSERP costs and energy conservation program costs and other increases
in operations expenses.
Maintenance expense increased in 1994 because of higher labor
costs related to the extreme winter weather conditions during the
first quarter of 1994 and higher costs at the Calvert Cliffs Nuclear
Power Plant.
Depreciation expense increased during the first quarter of 1994
primarily because of higher depreciable plant in service. 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 1993 and
1994.
Taxes other than income taxes increased during 1994 because of
higher franchise taxes and property taxes. The increase in franchise
taxes resulted from the increase in total electric and gas revenues.
18
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
Other Income and Expenses
The allowance for funds used during construction (AFC) increased
during the first quarter of 1994 as the effect of a higher level of
construction work in progress was offset partially by the lower AFC
rate approved in the April 1993 PSC rate order.
Interest charges decreased slightly during the first quarter of
1994 as a decline in the level of interest rates and the redemption of
higher cost coupon debt of BGE was offset substantially by an
increased level of outstanding debt.
Capitalized interest decreased during the first quarter due to
lower capitalized interest on the Constellation Companies' power
generation systems projects, 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 the first quarter of 1994
because of higher pre-tax earnings and the effect of the 1993 Tax Act
enacted in June 1993, which increased the federal corporate income tax
rate to 35% from 34%.
Diversified Businesses Earnings
Earnings per share from diversified businesses were:
Quarter Ended
March 31
1994 1993
Power generation systems.................. $.01 $.01
Financial investments..................... .01 .01
Real estate development and senior........
living facilities...................... (.01) (.01)
Total..................................... $.01 $.01
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 essentially
unchanged during the first quarter of 1994.
The Constellation Companies' investment in wholesale power
generating projects includes $158 million representing ownership
interests in 16 projects which 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
19
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
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 essentially
unchanged during the first quarter.
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 were essentially unchanged during the first quarter
of 1994.
The Constellation Companies sold the nursing home portion of the
investment in senior living facilities in November 1993. The senior
living facilities which were sold contributed real estate revenues and
operating expenses of approximately $17 million and $16 million,
respectively, in 1993. Additionally, the Constellation Companies'
real estate portfolio has experienced continuing carrying costs and
depreciation, and the Constellation Companies are expensing rather
than capitalizing interest on certain undeveloped land where
development activities are 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
20
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
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 Note 13 and Item 1.Business -
Environmental Matters of the Form 10-K.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity
For the twelve months ended March 31, 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 3.14
and 2.45, respectively.
Capital Requirements
The Company's capital requirements reflect the capital-intensive
nature of the utility business. Actual capital requirements for the
quarter ended March 31, 1994, along with estimated annual amounts for
the years 1994 through 1996, are reflected below.
21
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
Quarter Ended
March 31
Calendar Year Estimate
1994 1994 1995 1996
(In millions)
Utility Business:
Construction expenditures
(excluding AFC)
Electric.......................... $ 71 $345 $319 $300
Gas............................... 8 54 60 56
Common............................ 7 51 46 44
Total construction expenditures... 86 450 425 400
AFC............................... 8 34 35 25
Deferred nuclear expenditures..... 2 12 - -
Deferred energy conservation
expenditures.................... 9 48 45 40
Nuclear fuel (uranium purchases
and processing charges)......... 8 42 46 51
Retirement of long-term debt and
redemption of preference stock.. 74 201 281 98
Total utility business............ 187 787 832 614
Diversified Businesses:
Retirement of long-term debt...... 5 10 80 77
Investment requirements........... 22 64 67 21
Total diversified businesses...... 27 74 147 98
Total.............................. $ 214 $861 $979 $712
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 March 31, 1994, the internal
generation of cash from utility operations provided 67% of the funds
required for BGE's capital requirements exclusive retirements and
22
<PAGE>
PART I. FINANCIAL INFORMATION (Continued)
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 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 $22 million, respectively. During the same period, retirements
and redemptions of BGE's long-term debt and preference stock totaled
$177 million and $2 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 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 page 20 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.
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 22 because of the type and number of
projects selected for development, the impact of market conditions on
those projects, the ability to obtain financing, and the availability
of internally generated cash. The Constellation Companies have met
their investment requirements in the past through the internal
generation of cash and through borrowings from institutional lenders.
23
<PAGE>
PART II. OTHER INFORMATION (Continued)
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 $80.8 million. In
addition, the Constellation Companies have loaned $5 million
(including accrued interest) to the other partner in PGV for use
in funding venture costs. 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 22 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. To
operate this well at full capacity, certain modifications to the
brine handling system are required and an additional well may
also be required. In addition, during April 1994, an obstruction
in the well casing was detected in the other production well
during routine testing. PGV plans to remove the obstruction in
24
<PAGE>
PART II. OTHER INFORMATION (Continued)
the casing during the third quarter of 1994. Until certain of
the above-mentioned actions are completed, including the drilling
of the additional well, 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.
During 1993, EPA informed PGV that it was investigating the
circumstances regarding two air releases of hydrogen sulfide from
the Puna project's well drilling activities. EPA issued a final
preliminary assessment report giving the PGV site a low priority
for further assessment action based on the fact there is no
residual hydrogen sulfide problem at the site to be remediated.
The Constellation Companies' partner in the Puna project
continues to experience financial difficulties. The partner has
not been meeting its funding obligation to PGV for over two
years. Also, the partner is currently in default under the $5
million loan it obtained from the Constellation Companies. On
February 22, 1994, the Constellation Companies reached agreement
with the partner and certain of the partner's direct and indirect
shareholders which would result in recapitalization of the
project, and repayment of the $5.0 million loan to Constellation.
This agreement is subject certain approvals by shareholders of
the partner. There are no assurances that these approvals will
be obtained.
Asbestos
During 1993, BGE was served in several actions concerning
asbestos. The actions are collectively titled In re Baltimore
City Personal Injuries Asbestos Cases in the Circuit Court for
Baltimore City, Maryland. The actions are based upon the theory
25
<PAGE>
PART II. OTHER INFORMATION (Continued)
of "premises liability," alleging that BGE knew of and exposed
individuals to an asbestos hazard. The actions relate to two
types of claims.
The first type, direct claims by individuals exposed to
asbestos, were described in a Report on Form 8-K filed August 20,
1993. BGE and approximately 70 other defendants are involved.
The 260 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
Fiberglass 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
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.
26
<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 May 16, 1994 /s/ C. W. Shivery
C. W. Shivery, Vice President
on behalf of the Registrant and
as Principal Financial Officer
27
<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.
28
<PAGE>
<TABLE>
EXHIBIT 12
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND
COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND
PREFERRED AND PREFERENCE DIVIDEND REQUIREMENTS
<CAPTION>
12 Months Ended
March December December December December December
1994 1993 1992 1991 1990 1989
(In Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
Net Income................... $326,215 $309,866 $264,347 $233,681 $175,446 $276,291
Taxes on Income.............. 152,798 140,833 105,994 88,041 22,818 84,704
Adjusted Net Income.......... $479,013 $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................ $200,062 $199,415 $200,848 $213,616 $194,656 167,503
Capitalized Interest........ 14,904 16,167 13,800 20,953 25,748 5,842
Interest Factor in Rentals.. 2,048 2,144 2,033 1,801 1,840 2,388
Total Fixed Charges....... $217,014 $217,726 $216,681 $236,370 $222,244 $175,733
Preferred and Preference
Dividend Requirements: (1)
Preferred and
Preference Dividends....... $41,350 $41,839 $42,247 $42,746 $40,261 $32,381
Income Tax Required......... 19,112 18,763 16,729 15,916 5,166 9,779
Total Preferred and Preference
Dividend Requirements....... $60,462 $60,602 $58,976 $58,662 $45,427 $42,160
Total Fixed Charges and
Preferred and Preference
Dividend Requirements....... $277,476 $278,328 $275,657 $295,032 $267,671 $217,893
Earnings (2)................ $681,123 $652,258 $573,222 $537,139 $394,760 $530,886
Ratio of Earnings to
Fixed Charges............... 3.14 3.00 2.65 2.27 1.78 3.02
Ratio of Earnings to
Combined Fixed Charges and
Preferred and Preference
Dividend Requirements....... 2.45 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
which would be required to meet dividend requirements on preferred stock and preference stock.
(2) Earnings are deemed to consist of net income which 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.
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