SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
---------
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended September 30, 1996
Commission file number 1-1910
BALTIMORE GAS AND ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
Maryland 52-0280210
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(State of incorporation) (IRS Employer Identification No.)
39 W. Lexington Street Baltimore, Maryland 21201
---------------------- ------------------- -----
(Address of principal executive offices) (Zip Code)
410-783-5920
(Registrant's telephone number, including area code)
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 - 147,567,114 shares outstanding on October 31,
1996.
1
BALTIMORE GAS AND ELECTRIC COMPANY
PART I. FINANCIAL INFORMATION
-----------------------------
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
Quarter Ended Nine Months Ended
September 30, September 30,
---------------------------- -----------------------------
1996 1995 1996 1995
------------ ----------- ------------ -------------
(In Thousands, Except Per-Share Amounts)
Revenues
Electric ........................................................... $ 664,364 $ 713,769 $ 1,736,587 $ 1,726,220
Gas ................................................................ 62,874 49,477 375,653 270,229
Diversified businesses ............................................. 98,722 85,535 306,756 212,638
----------- ----------- ----------- -----------
Total revenues ..................................................... 825,960 848,781 2,418,996 2,209,087
----------- ----------- ----------- -----------
Expenses Other Than Interest and Income Taxes
Electric fuel and purchased energy ................................. 134,241 155,085 415,561 435,667
Gas purchased for resale ........................................... 28,099 18,339 206,511 129,330
Operations ......................................................... 131,447 135,056 393,812 401,184
Maintenance ........................................................ 40,310 34,478 135,562 122,720
Diversified businesses - selling, general, and administrative ...... 71,351 54,590 223,175 148,337
Depreciation and amortization ...................................... 83,655 93,559 251,385 245,574
Taxes other than income taxes ...................................... 61,190 57,930 167,372 157,389
----------- ----------- ----------- -----------
Total expenses other than interest and income taxes ................ 550,293 549,037 1,793,378 1,640,201
----------- ----------- ----------- -----------
Income From Operations ............................................. 275,667 299,744 625,618 568,886
----------- ----------- ----------- -----------
Other Income
Allowance for equity funds used during construction ................ 1,007 2,026 4,979 12,227
Equity in earnings of Safe Harbor Water Power Corporation .......... 1,208 1,108 3,454 3,323
Net other income and deductions .................................... (341) (1,661) (4,439) (7,600)
----------- ----------- ----------- -----------
Total other income ................................................. 1,874 1,473 3,994 7,950
----------- ----------- ----------- -----------
Income Before Interest and Income Taxes ............................ 277,541 301,217 629,612 576,836
----------- ----------- ----------- -----------
Interest Expense
Interest charges ................................................... 55,966 55,436 161,737 165,746
Capitalized interest ............................................... (4,523) (3,509) (11,091) (10,676)
Allowance for borrowed funds used during construction .............. (546) (1,096) (2,692) (6,615)
----------- ----------- ----------- -----------
Net interest expense ............................................... 50,897 50,831 147,954 148,455
----------- ----------- ----------- -----------
Income Before Income Taxes ......................................... 226,644 250,386 481,658 428,381
----------- ----------- ----------- -----------
Income Taxes
Current ............................................................ 66,194 64,611 136,325 69,523
Deferred ........................................................... 15,883 24,470 39,256 79,865
Investment tax credit adjustments .................................. (1,915) (2,030) (5,739) (6,085)
----------- ----------- ----------- -----------
Total income taxes ................................................. 80,162 87,051 169,842 143,303
----------- ----------- ----------- -----------
Net Income ......................................................... 146,482 163,335 311,816 285,078
Preferred and Preference Stock Dividends ........................... 8,620 10,231 30,387 30,135
----------- ----------- ----------- -----------
Earnings Applicable to Common Stock ................................ $ 137,862 $ 153,104 $ 281,429 $ 254,943
=========== =========== =========== ===========
Average Shares of Common Stock Outstanding 147,565 147,527 147,540 147,527
Earnings Per Share of Common Stock $0.93 $1.04 $1.91 $1.73
Dividends Declared Per Share of Common Stock $0.40 $0.39 $1.19 $1.16
See Notes to Consolidated Financial Statements.
2
PART I. FINANCIAL INFORMATION (Continued)
-----------------------------------------
CONSOLIDATED BALANCE SHEETS September 30, December 31,
1996* 1995
---------- -----------
(In Thousands)
ASSETS
Current Assets
Cash and cash equivalents ........................................................ $ 42,244 $ 23,443
Accounts receivable (net of allowance for uncollectibles ......................... 414,643 400,005
of $17,569 and $16,390 respectively)
Fuel stocks ...................................................................... 78,093 59,614
Materials and supplies ........................................................... 143,182 145,900
Prepaid taxes other than income taxes ............................................ 92,498 60,508
Deferred income taxes ............................................................ 4,551 36,831
Trading securities ............................................................... 66,838 47,990
Other ............................................................................ 15,897 31,487
----------- -----------
Total current assets ............................................................. 857,946 805,778
----------- -----------
Investments and Other Assets
Real estate projects ............................................................. 510,919 479,344
Power generation systems ......................................................... 370,843 358,629
Financial investments ............................................................ 198,062 205,841
Nuclear decommissioning trust fund ............................................... 107,845 85,811
Net pension asset ................................................................ 81,301 60,077
Safe Harbor Water Power Corporation .............................................. 34,422 34,327
Senior living facilities ......................................................... 34,488 16,045
Other ............................................................................ 81,114 71,894
----------- -----------
Total investments and other assets ............................................... 1,418,994 1,311,968
----------- -----------
Utility Plant
Plant in service
Electric ....................................................................... 6,463,998 6,360,624
Gas ............................................................................ 753,586 692,693
Common ......................................................................... 523,713 522,450
----------- -----------
Total plant in service ......................................................... 7,741,297 7,575,767
Accumulated depreciation ......................................................... (2,569,036) (2,481,801)
----------- -----------
Net plant in service ............................................................. 5,172,261 5,093,966
Construction work in progress .................................................... 215,462 247,296
Nuclear fuel (net of amortization) ............................................... 145,280 130,782
Plant held for future use ........................................................ 25,737 25,552
----------- -----------
Net utility plant ................................................................ 5,558,740 5,497,596
----------- -----------
Deferred Charges
Regulatory assets (net) .......................................................... 616,989 637,915
Other deferred charges ........................................................... 76,250 63,406
----------- -----------
Total deferred charges ........................................................... 693,239 701,321
----------- -----------
TOTAL ASSETS ....................................................................... $ 8,528,919 $ 8,316,663
=========== ===========
* Unaudited
See Notes to Consolidated Financial Statements.
3
PART I. FINANCIAL INFORMATION (Continued)
CONSOLIDATED BALANCE SHEETS September 30, December 31,
1996* 1995
---------- ----------
(In Thousands)
LIABILITIES AND CAPITALIZATION
Current Liabilities
Short-term borrowings ............................................................ $ 389,160 $ 279,305
Current portions of long-term debt and preference stock .......................... 268,173 146,969
Accounts payable ................................................................. 143,664 177,092
Customer deposits ................................................................ 28,324 26,857
Accrued taxes .................................................................... 40,198 8,244
Accrued interest ................................................................. 52,045 56,670
Dividends declared ............................................................... 67,379 67,198
Accrued vacation costs ........................................................... 31,175 33,403
Other ............................................................................ 28,901 39,417
----------- -----------
Total current liabilities ........................................................ 1,049,019 835,155
----------- -----------
Deferred Credits and Other Liabilities
Deferred income taxes ............................................................ 1,312,473 1,311,530
Pension and postemployment benefits .............................................. 161,773 148,594
Decommissioning of federal uranium enrichment facilities ......................... 43,694 43,695
Other ............................................................................ 63,905 55,568
----------- -----------
Total deferred credits and other liabilities ..................................... 1,581,845 1,559,387
----------- -----------
Capitalization
Long-term Debt
First refunding mortgage bonds of BGE ............................................ 1,619,357 1,538,528
Other long-term debt of BGE ...................................................... 622,000 649,500
Long-term debt of Constellation Companies ........................................ 570,041 546,903
Unamortized discount and premium ................................................. (14,431) (15,708)
Current portion of long-term debt ................................................ (173,673) (120,969)
----------- -----------
Total long-term debt ............................................................. 2,623,294 2,598,254
----------- -----------
Preferred Stock .................................................................... -- 59,185
----------- -----------
Redeemable Preference Stock ........................................................ 240,500 268,000
Current portion of redeemable preference stock ................................... (94,500) (26,000)
----------- -----------
Total redeemable preference stock ................................................ 146,000 242,000
----------- -----------
Preference Stock Not Subject to Mandatory Redemption ............................... 210,000 210,000
----------- -----------
Common Shareholders' Equity
Common stock ..................................................................... 1,426,746 1,425,805
Retained earnings ................................................................ 1,487,272 1,381,417
Net unrealized gain on available-for-sale securities ............................. 4,743 5,460
----------- -----------
Total common shareholders' equity ................................................ 2,918,761 2,812,682
----------- -----------
Total capitalization ............................................................. 5,898,055 5,922,121
----------- -----------
TOTAL LIABILITIES AND CAPITALIZATION ............................................... $ 8,528,919 $ 8,316,663
=========== ===========
* Unaudited
See Notes to Consolidated Financial Statements.
4
PART I. FINANCIAL INFORMATION (Continued)
-----------------------------------------
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) Nine Months Ended September 30,
--------------------------------
1996 1995
---------- ----------
(In Thousands)
Cash Flows From Operating Activities
Net income ............................................................................... $ 311,816 $ 285,078
Adjustments to reconcile to net cash provided by operating activities
Depreciation and amortization .......................................................... 288,491 288,698
Deferred income taxes .................................................................. 39,256 79,865
Investment tax credit adjustments ...................................................... (5,739) (6,085)
Deferred fuel costs .................................................................... 14,962 21,690
Disallowance of replacement energy costs ............................................... 6,763 --
Accrued pension and postemployment benefits ............................................ (11,277) (10,540)
Allowance for equity funds used during construction .................................... (4,979) (12,227)
Equity in earnings of affiliates and joint ventures (net) .............................. (42,130) (14,854)
Changes in current assets, other than sale of accounts receivable ...................... (61,729) (57,784)
Changes in current liabilities, other than short-term borrowings ....................... (16,853) (38,415)
Other .................................................................................. 8,907 (767)
--------- ---------
Net cash provided by operating activities ................................................ 527,488 534,659
--------- ---------
Cash Flows From Financing Activities
Proceeds from issuance of
Short-term borrowings (net) ............................................................ 97,855 (49,900)
Long-term debt ......................................................................... 217,655 56,164
Preference Stock ....................................................................... -- 59,475
Common stock ........................................................................... 798 140
Reacquisition of long-term debt .......................................................... (140,046) (67,002)
Redemption of preferred and preference stock ............................................. (89,559) --
Common stock dividends paid .............................................................. (174,082) (169,656)
Preferred and preference stock dividends paid ............................................ (28,697) (29,856)
Other .................................................................................... (917) 325
--------- ---------
Net cash used in financing activities .................................................... (116,993) (200,310)
--------- ---------
Cash Flows From Investing Activities
Utility construction expenditures ........................................................ (258,846) (262,533)
Allowance for equity funds used during construction ...................................... 4,979 12,227
Nuclear fuel expenditures ................................................................ (45,695) (45,434)
Deferred energy conservation expenditures ................................................ (21,731) (30,068)
Contributions to nuclear decommissioning trust fund ...................................... (21,075) (7,335)
Purchases of marketable equity securities ................................................ (28,196) (12,055)
Sales of marketable equity securities .................................................... 32,152 40,856
Other financial investments .............................................................. 10,390 7,941
Real estate projects ..................................................................... (37,127) (3,898)
Power generation systems ................................................................. (11,341) (29,949)
Other .................................................................................... (15,204) (14,610)
--------- ---------
Net cash used in investing activities .................................................... (391,694) (344,858)
--------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents ....................................... 18,801 (10,509)
Cash and Cash Equivalents at Beginning of Period ........................................... 23,443 38,590
--------- ---------
Cash and Cash Equivalents at End of Period ................................................. $ 42,244 $ 28,081
========= =========
Other Cash Flow Information Cash paid during the period for:
Interest (net of amounts capitalized) .................................................. $ 151,456 $ 148,018
Income taxes ........................................................................... $ 90,901 $ 46,197
See Notes to Consolidated Financial Statements.
Certain prior period amounts have been reclassified to conform with the current
period presentation.
5
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.
BGE Financing Activity
- ----------------------
Long-Term Debt
- --------------
The following reflects issuances and redemptions of long-term debt that
occurred or were announced during the period from January 1, 1996 through the
date of this report:
Date Net
Issuance Principal Issued Proceeds
-------- --------- ------ --------
First Refunding Mortgage Bonds
Remarketed Floating Rate Series
Due September 1, 2006 $125,000,000 6/24/96 $124,875,000
Medium-Term Notes, Series D
6.68% Due October 11, 2001 $50,000,000 10/11/96 $49,750,000
6.90% Due February 1, 2005 $20,000,000 10/23/96 $19,890,000
6.46% Due November 5, 2001 $10,000,000 11/5/96 $ 9,950,000
6.79% Due November 15, 2004 $20,000,000 11/5/96 $19,890,000
6.70% Due December 1, 2006 $10,000,000 11/15/96 $ 9,940,000
The $125,000,000 Remarketed Floating Rate Series Due September 1, 2006
Mortgage Bonds include a provision that allows the bondholders the option to
tender their bonds back to BGE on an annual basis. BGE is required to repurchase
and retire any bonds tendered that are not remarketed or purchased by the
remarketing agent. In addition, BGE has the option to call the bonds annually at
par on each remarketing date.
On August 1, 1996, BGE redeemed $5,541,000 principal amount of the 7-1/8%
Series Due January 1, 2002 and $418,000 from several other series of First
Refunding Mortgage Bonds at various prices tendered in connection with the
annual sinking fund required by BGE's mortgage. In addition, on August 29, 1996,
BGE redeemed $11,420,000 principal amount of the 7-1/8% Series Due January 1,
2002 at par to complete the sinking fund for 1996.
BGE may purchase First Refunding Mortgage Bonds of various series in open
market transactions, from time to time in the future, depending upon market
conditions and BGE's assessment of optimal capital structure, including the mix
of secured and unsecured debt.
Preferred and Preference Stock
- ------------------------------
On May 28, 1996, BGE redeemed its entire class of Preferred Stock. The
following is a summary of the series redeemed:
Cumulative Preferred Stock, Price
$100 Par Value Shares Per Share
-------------- ------ ---------
Series B, 4-1/2% 222,921 $110
Series C, 4% 68,928 $105
Series D, 5.40% 300,000 $101
In addition, BGE exercised its option to double-up the required sinking
fund on certain series of Preference Stock. The total shares redeemed, including
the optional redemptions, were as follows:
6
Cumulative Preference Stock, Date Price
$100 Par Value Shares Redeemed Per Share
-------------- ------ -------- ---------
8.625% 1990 Series 260,000 7/1/96 $100
8.25% 1989 Series 200,000 10/1/96 $100
7.50% 1986 Series 30,000 10/1/96 $100
Common Stock
- ------------
During the period July 1, 1996 through the date of this Report, BGE issued
a total of 140,000 shares of Common Stock, without par value, through its Common
Stock Continuous Offering Program with net proceeds to BGE of approximately
$3,987,000.
Diversified Business Financing Matters
- --------------------------------------
See Management's Discussion and Analysis of Financial Condition and Results
of Operations-Diversified Businesses Capital Requirements for additional
information about the debt of Constellation Holdings, Inc. and its subsidiaries.
Pending Merger with Potomac Electric Power Company
- --------------------------------------------------
BGE, Potomac Electric Power Company (PEPCO), and Constellation Energy
Corporation (formerly named "RH Acquisition Corp.") (CEC), have entered into an
Agreement and Plan of Merger, dated as of September 22, 1995 (the Merger
Agreement). CEC was formed to accomplish the merger and its outstanding capital
stock is owned 50% by BGE and 50% by PEPCO. The Merger Agreement provides for a
strategic business combination that will be accomplished by merging both BGE and
PEPCO into CEC (the Merger). The Merger, which was unanimously approved by the
Boards of Directors of BGE and PEPCO and approved by the shareholders of both
companies, is expected to close during 1997 after all other conditions to the
consummation of the Merger, including obtaining applicable regulatory approvals
(described below), are met or waived. In connection with the Merger, BGE common
shareholders will receive one share of CEC common stock for each BGE share and
PEPCO common shareholders will receive 0.997 of a share of CEC common stock for
each PEPCO share.
Preliminary estimates by the managements of PEPCO and BGE indicate that the
synergies resulting from the combination of their utility operations could
generate net cost savings of up to $1.3 billion over a period of 10 years
following the Merger. These estimates indicate that about two-thirds of the
savings will come from reduced labor costs, with the remaining savings split
between nonfuel purchasing and corporate and administrative programs. These
savings are net of costs to achieve, presently estimated to be approximately
$150 million, and are expected to be allocated among shareholders and customers.
This allocation will depend upon the results of regulatory proceedings in the
various jurisdictions in which BGE and PEPCO operate their utility businesses
(see discussion of the issues raised in regulatory proceedings regarding the
allocation and other matters). The analyses employed in order to develop
estimates of the potential savings as a result of the Merger were necessarily
based upon various assumptions which involve judgments with respect to, among
other things, future national and regional economic and competitive conditions,
inflation rates, regulatory treatment, weather conditions, financial market
conditions, interest rates, future business decisions and other uncertainties,
all of which are difficult to predict and many of which are beyond the control
of BGE and PEPCO. Accordingly, while BGE believes that such assumptions are
reasonable for purposes of the development of estimates of potential savings,
there can be no assurance that such assumption will approximate actual
experience or that all such savings will be realized.
Major regulatory proceedings, together with an indication of the current
status of the proceeding, which must be concluded in order to proceed with the
merger are listed below. The Merger Agreement provides that a condition to
closing is that no such approvals shall impose terms and conditions that would
have, or would be reasonably likely to have, a material adverse effect on the
business, operations, properties, assets, condition (financial or otherwise),
prospects, or results of operations of the new company.
Federal Energy Regulatory Commission (FERC) - The merger has been set
for hearing to explore the merged company's generation market power,
including the appropriate geographic markets, and to consider
appropriate remedies if the merged company is found to possess
generation market power. Testimony of FERC staff included the
suggestion that a significant portion of generation (approximately
7
2400-3600 megawatts) be divested or transmission capability be
upgraded or both due to the perceived market power of the merged
company in both the wholesale and retail markets.
Maryland Public Service Commission (PSC) - Hearings are in progress
and testimony has been filed by all parties to the proceeding. Since
the Report on Form 10-Q for the second quarter 1996 was filed,
rebuttal and surrebuttal testimony has been filed. Office of People's
Counsel (the advocates for residential customers) recommended that the
PSC not approve the Merger until the Applicants demonstrate that
Maryland customers will not be harmed by potential restrictions on
competition due to the market power of the new company. If, however,
the PSC decides to approve the Merger, People's Counsel continues to
recommend rate decreases. Due to the use of a different test period,
the amounts are somewhat different than reported in the second quarter
Report on Form 10-Q. Based on a test period proposed by People's
Counsel in recent testimony, they recommend a pre-merger rate
reduction of approximately $108.3 million ($84.7 million to BGE
customers and $23.6 million to PEPCO customers) with Merger savings
being reflected in further reduced rates of approximately $65 million
($45 million to BGE customers and $20 million to PEPCO customers)
contemporaneously with the date of the Merger. A number of other
recommendations are also included in People's Counsel testimony. The
Maryland Energy Administration (MEA) continues to recommend that the
PSC adopt an alternative regulatory plan and also asks that rates be
examined. PSC Staff testimony also utilizes the new test period. Based
on the new test period PSC Staff recommends an immediate decrease of
$63.6 million (BGE's rates reduced by $54.3 million and PEPCO's by
$9.3 million) at the time of the Merger. PSC Staff's surrebuttal
testimony also recommends that CEC be required to make a rate filing
15 months after the Merger becomes effective.
District of Columbia Public Service Commission - Testimony was filed
by the parties in September 1996. The D.C. Office of People's Counsel
(the advocates for residential customers) opposes the Merger based on
its contention that BGE and PEPCO have not proved that the Merger is
in the public interest. Testimony of the D.C. People's Counsel also
provides that should the Merger be approved, an immediate rate
reduction of $44.2 million be imposed at the time of the Merger,
followed by a 5-year moratorium on rate increases. Further, testimony
of D.C. People's Counsel advocates divestiture of all nonutility
affiliate companies, exclusion of BGE's Calvert Cliffs Nuclear Plant
from production plant assigned to D.C., and a 5-year $23.37 million
per year economic development program. GSA, a major D.C. customer,
requests that any approval should be coupled with an imposition of
retail competition access for ratepayers such as GSA, a 25-year
amortization of costs to achieve the Merger, and elimination of
Calvert Cliffs from the generating mix. In addition to these matters,
D.C. People's Counsel, an intervenor, Washington Gas Light Company,
and the D.C. Corporation Counsel have questioned the interpretation by
BGE and PEPCO that a D.C. statute known as the Antimerger Law is
inapplicable to this transaction. Should such statute be deemed to be
applicable, authorization of the Merger by Congress would be required.
Allegations also were made that BGE and PEPCO should have received
Congressional approval for their owning 50% of the shell company, CEC,
prior to consummation of the Merger.
The reasons for the Merger, the terms and conditions contained in the
Merger Agreement, the regulatory approvals required prior to closing the Merger,
and other matters concerning the Merger, PEPCO, and CEC are discussed in more
detail in the Registration Statement on Form S-4 (Registration No. 33-64799)
which is included as an exhibit to this Report on Form 10-Q by incorporation by
reference.
The Merger Agreement provides that, upon consummation of the Merger, the
CEC Board of Directors will consist of 16 persons - 9 designated by BGE and 7
designated by PEPCO. However, disclosure in the Registration Statement on Form
S-4 stated the number of Directors might be reconsidered because of a District
of Columbia public utility law. That law, which precluded utilities serving the
District of Columbia from having more than 15 directors, was recently amended.
As a result, at the effective time of the Merger CEC will have 16 Directors as
specified in the Merger Agreement.
Environmental Matters
- ---------------------
The Clean Air Act of 1990 (the Act) contains two titles designed to reduce
emissions of sulfur dioxide and nitrogen oxide (NOx) from electric generating
stations. Title IV contains provisions for compliance in two separate phases.
Phase I of Title IV became effective January 1, 1995, and Phase II of Title IV
must be implemented by
8
2000. BGE met the requirements of Phase I by installing flue gas desulfurization
systems and fuel switching and through unit retirements. BGE is currently
examining what actions will be required in order to comply with Phase II of the
Act. However, BGE anticipates that compliance will be attained by some
combination of fuel switching, flue gas desulfurization, unit retirements, or
allowance trading.
At this time, plans for complying with NOx control requirements under Title
I of the Act are less certain because all implementation regulations have not
yet been finalized by the government. It is expected that by the year 1999 these
regulations will require additional NOx controls for ozone attainment at BGE's
generating plants and at other BGE facilities. The controls will result in
additional expenditures that are difficult to predict prior to the issuance of
such regulations. Based on existing and proposed ozone nonattainment
regulations, BGE currently estimates that the NOx controls at BGE's generating
plants will cost approximately $90 million. BGE is currently unable to predict
the cost of compliance with the additional requirements at other BGE facilities.
BGE has been notified by the Environmental Protection Agency and several
state agencies that it is being considered a potentially responsible party with
respect to the cleanup of certain environmentally contaminated sites owned and
operated by third parties. In addition, a subsidiary of Constellation Holdings,
Inc. has been named as a defendant in a case concerning an alleged
environmentally contaminated site owned and operated by a third party. Cleanup
costs for these sites cannot be estimated, except that BGE's 15.79% share of the
possible cleanup costs at one of these sites, Metal Bank of America, a metal
reclaimer in Philadelphia, could exceed amounts BGE has recognized by up to
approximately $7 million based on the highest estimate of costs in the range of
reasonably possible alternatives. Although the cleanup costs for certain of the
remaining sites could be significant, BGE believes that the resolution of these
matters will not have a material effect on its financial position or results of
operations.
Also, BGE is coordinating investigation of several former gas manufacturing
plant sites, including exploration of corrective action options to remove tar.
However, no formal legal proceedings have been instituted against BGE. The
technology for cleaning up such sites is still developing, and remedies for
these sites are being determined. BGE has recognized estimated environmental
costs at these sites which are considered probable totaling $50 million in
nominal dollars. These costs, net of accumulated amortization, have been
deferred as a regulatory asset (see Note 5 of the Form 10-K for the year ended
December 31, 1995). Accounting rules also require BGE to disclose additional
costs deemed by BGE to be less likely than probable costs, but still "reasonably
possible" of being incurred at these sites. Because of the results of recent
studies at these sites, it is reasonably possible that these additional costs
could exceed the amount recognized by approximately $48 million in nominal
dollars ($11 million in current dollars, plus the impact of inflation at 3.1%
over a period of up to 60 years).
Nuclear Insurance
- -----------------
An accident or an extended outage at either unit of the Calvert Cliffs
Nuclear Power Plant could have a substantial adverse effect on BGE. The primary
contingencies resulting from an incident at the Calvert Cliffs plant would
involve the physical damage to the plant, the recoverability of replacement
power costs, and BGE's liability to third parties for property damage and bodily
injury. BGE maintains various insurance policies for these contingencies. The
costs that could result from a major accident or an extended outage at either of
the Calvert Cliffs units could exceed the coverage limits.
In addition, in the event of an incident at any commercial nuclear power
plant in the country, BGE could be assessed for a portion of any third party
claims associated with the incident. Under the provisions of the Price Anderson
Act, the limit for third party claims from a nuclear incident is $8.92 billion.
If third party claims relating to such an incident exceed $200 million (the
amount of primary insurance), BGE's share of the total liability for third party
claims could be up to $159 million per incident, that would be payable at a rate
of $20 million per year.
BGE and other operators of commercial nuclear power plants in the United
States are required to purchase insurance to cover claims of certain nuclear
workers. Other non-governmental commercial nuclear facilities may also purchase
such insurance. Coverage of up to $400 million is provided for claims against
BGE or others insured by these policies for radiation injuries. If certain
claims were made under these policies, BGE and all policyholders could be
assessed, with BGE's share being up to $6.02 million in any one year.
9
For physical damage to Calvert Cliffs, BGE has $2.75 billion of property
insurance from industry mutual insurance companies. If an outage at Calvert
Cliffs is caused by an insured physical damage loss and lasts more than 21
weeks, BGE has up to $473.2 million per unit of insurance, provided by an
industry mutual insurance company, for replacement power costs. This amount can
be reduced by up to $94.6 million per unit if an outage to both units at Calvert
Cliffs is caused by a singular insured physical damage loss. If accidents at any
insured plants cause a shortfall of funds at the industry mutuals, BGE and all
policyholders could be assessed, with BGE's share being up to $43.6 million.
Recoverability of Electric Fuel Costs
- -------------------------------------
By statute, actual electric fuel costs are recoverable so long as the
Maryland Public Service Commission (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 fuel rate hearings, actual generating performance after
adjustment for planned outages will be compared to the system-wide target and,
if met, should signify that BGE has complied with the requirements of Maryland
law. Failure to meet the system-wide target will result in review of each unit's
adjusted actual generating performance versus its performance target in
determining compliance with the law and the basis for possibly imposing a
penalty on BGE. Parties to fuel rate hearings may still question the prudence of
BGE's actions or inactions with respect to any given generating plant outage,
which could result in the disallowance of replacement energy costs by the PSC.
Since the two units at BGE's Calvert Cliffs Nuclear Power Plant utilize
BGE's lowest cost fuel, replacement energy costs associated with outages at
these units can be significant. BGE cannot estimate the amount of replacement
energy costs that could be challenged or disallowed in future fuel rate
proceedings, but such amounts could be material.
In October 1988, BGE filed its first fuel rate application for a change in
its electric fuel rate under GUPP. The resultant case before the PSC covers
BGE's operating performance in calendar year 1987, and BGE's filing demonstrated
that it met the system-wide and individual nuclear plant performance targets for
1987. In November 1989, testimony was filed on behalf of the Maryland People's
Counsel (People's Counsel) alleging that seven outages at the Calvert Cliffs
plant in 1987 were due to management imprudence and that the replacement energy
costs associated with those outages should be disallowed by the Commission.
Total replacement energy costs associated with the 1987 outages were
approximately $33 million. On January 23, 1995, the Hearing Examiner issued his
decision in the 1987 fuel rate proceeding and found that the Company had met the
GUPP standard which establishes a presumption that BGE had operated the plant at
a reasonably productive capacity level. However, the Order found that the
presumption of reasonableness would be overcome by a showing of mismanagement
and that such a showing was made with respect to the environmental
qualifications outage time. The Hearing Examiner had mitigated the disallowance
of replacement energy costs due to the fact the GUPP standard was met. The
Hearing Examiner's Order was appealed to the PSC by both BGE and People's
Counsel. The PSC upheld the Hearing Examiner's findings with respect to the
environmental qualification related outage time, but disagreed with certain
methodologies applied by the Hearing Examiner. The impact of the PSC's decision
on the Company's earnings was approximately $4.5 million which equaled BGE's
previous estimate reported in the Form 10-Q for the quarter ended March 31,
1996. People's Counsel has filed a motion for rehearing.
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
10
Order concluded there was sufficient cause to excuse any avoidable failures to
maintain productive capacity at higher levels.
During 1989, 1990, and 1991, BGE experienced extended outages at its
Calvert Cliffs Nuclear Power Plant. In the Spring of 1989, a leak was discovered
around the Unit 2 pressurizer heater sleeves during a refueling outage. BGE shut
down Unit 1 as a precautionary measure on May 6, 1989, to inspect for similar
leaks and none were found. However, Unit 1 was out of service for the remainder
of 1989 and 285 days of 1990 to undergo maintenance and modification work to
enhance the reliability of various safety systems, to repair equipment, and to
perform required periodic surveillance tests. Unit 2, which returned to service
on May 4, 1991, remained out of service for the remainder of 1989, 1990, and the
first part of 1991 to repair the pressurizer, perform maintenance and
modification work, and complete the refueling. The replacement energy costs
associated with these extended outages for both units at Calvert Cliffs,
concluding with the return to service of Unit 2, are estimated to be $458
million.
In a December 1990 Order issued by the PSC in a BGE base rate proceeding,
the PSC found that certain operations and maintenance expenses incurred at
Calvert Cliffs during the test year should not be recovered from ratepayers. The
PSC found that this work, which was performed during the 1989-1990 Unit 1 outage
and fell within the test year, was avoidable and caused by BGE actions which
were deficient.
The PSC noted in the Order that its review and findings on these issues
pertain to the reasonableness of BGE's test-year operations and maintenance
expenses for purposes of setting base rates and not to the responsibility for
replacement power costs associated with the outages at Calvert Cliffs. The PSC
stated that its decision in the base rate case will have no res judicata
(binding) effect in the fuel rate proceeding examining the 1989- 1991 outages.
The work characterized as avoidable significantly increased the duration of the
Unit 1 outage. Despite the PSC's statement regarding no binding effect, BGE
recognizes that the views expressed by the PSC make the full recovery of all of
the replacement energy costs associated with the Unit 1 outage doubtful.
Therefore, in December 1990, BGE recorded a provision of $35 million against the
possible disallowance of such costs. BGE cannot determine whether replacement
energy costs may be disallowed in the present fuel rate proceeding in excess of
the provision, but such amounts could be material. Hearings in this proceeding
took place in August 1996, but an initial decision is not expected until some
time in 1997.
11
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 Subsidiaries (collectively, the Company) are set
forth in the Consolidated Financial Statements and Notes to Consolidated
Financial Statements sections of this Report. Factors significantly affecting
results of operations, liquidity, and capital resources are discussed below.
RESULTS OF OPERATIONS FOR THE QUARTER AND NINE MONTHS ENDED SEPTEMBER 30, 1996
COMPARED WITH THE CORRESPONDING PERIODS OF 1995:
Earnings per Share of Common Stock
- ----------------------------------
Consolidated earnings per share for the quarter and nine months ended
September 30, 1996 were $.93 and $1.91, respectively, which represent a decrease
of $.11 and an increase of $.18 compared to the earnings for the corresponding
periods of 1995, respectively. These changes in earnings per share reflect the
levels of earnings applicable to common stock for those periods. The earnings
per share are summarized as follows:
Quarter Ended Nine Months Ended
September 30 September 30
------------ ------------
1996 1995 1996 1995
---- ---- ---- ----
Utility operations $.86 $ .96 $1.70 $1.59
Diversified businesses .07 .08 .21 .14
--- --- --- ---
Total $.93 $1.04 $1.91 $1.73
==== ===== ===== =====
Earnings Applicable to Common Stock
- -----------------------------------
Earnings applicable to common stock decreased $15.2 million during the
quarter and increased $26.5 million during the nine months ended September 30,
1996. These changes reflect the levels of earnings for those periods from both
utility operations and diversified businesses.
Earnings from utility operations decreased during the quarter ended
September 30, 1996 as compared to the corresponding period last year primarily
due to lower electric system sales resulting from the milder summer weather in
1996, offset partially by lower depreciation and amortization expenses. Earnings
from utility operations increased during the nine months ended September 30,
1996 primarily due to higher electric and gas system sales resulting from the
colder winter weather and an increased number of customers in 1996. This was
offset partially by lower electric system sales in the third quarter, higher
expenses other than interest and income taxes, and a decrease in the allowance
for funds used during construction. The effect of weather on utility sales is
discussed below under the heading "Effect of Weather on Utility Sales."
The following factors influence BGE's utility operations earnings:
regulation by the Maryland Public Service Commission (PSC), the effect of
weather and economic conditions on sales, and competition in the generation and
sale of electricity. The gas base rate increase authorized by the PSC in
November 1995 favorably affected utility earnings during the quarter and nine
months ended September 30, 1996. The electric fuel rate cases now pending before
the PSC discussed in the Notes to Consolidated Financial Statements under the
heading "Recoverability of Electric Fuel Costs" could also affect future years'
earnings.
Future competition may also affect earnings in ways that are not possible
to predict (see the discussion of "Response to Regulatory Change" in the Form
10-K).
Earnings from diversified businesses, which primarily represent the
operations of Constellation Holdings, Inc. and Subsidiaries (collectively, the
Constellation Companies), BGE Home Products & Services, Inc. and Subsidiary
(HP&S), BGE Energy Projects & Services, Inc. and Subsidiaries (EP&S) and BNG,
Inc., decreased during the quarter and increased during the nine months ended
September 30, 1996 compared to the corresponding periods of 1995. These changes
are discussed under the heading "Diversified Businesses Earnings."
12
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 nine months ended September 30, 1996 and 1995.
Quarter Ended Nine Months Ended
September 30 September 30
------------ ------------
1996 1995 1996 1995
---- ---- ---- ----
Heating degree days 102 53 3,324 2,772
Percent change compared
to prior period 92.5% 19.9%
Cooling degree days 491 746 770 997
Percent change compared
to prior period (34.2)% (22.8)%
BGE Utility Revenues and Sales
- ------------------------------
Electric revenues changed for the quarter and nine months ended September
30, 1996 because of the following factors:
Quarter Ended Nine Months Ended
September 30 September 30
1996 vs. 1995 1996 vs. 1995
------------- -------------
(In millions)
System sales volumes $(37.6) $12.1
Base rates 8.5 17.7
Fuel rates (9.1) (9.9)
---- ----
Revenues from system sales (38.2) 19.9
Interchange and other sales (11.7) (10.0)
Other revenues 0.5 0.5
--- ---
Total $(49.4) $10.4
====== =====
Electric system sales represent volumes sold to customers within BGE's
service territory at rates determined by the PSC. These amounts exclude
interchange sales and sales to other utilities, which are discussed separately.
Following is a comparison of the changes in electric system sales volumes:
Quarter Ended Nine Months Ended
September 30 September 30
1996 vs. 1995 1996 vs. 1995
------------- -------------
Residential (10.3)% 4.4%
Commercial (3.4) 0.2
Industrial (0.4) 1.9
Total (5.7) 2.1
Sales to residential, commercial, and industrial customers decreased during
the quarter ended September 30, 1996 compared to the same period last year due
primarily to milder summer weather, offset partially by greater usage per
customer and by increases in the number of customers. Sales to residential,
commercial, and industrial customers increased during the nine months ended
September 30, 1996 compared to the same period last year due to colder winter
weather, greater usage per customer, and an increase in the number of customers,
offset partially by milder summer weather.
13
Base rates are affected by two principal items: rate orders by the PSC and
recovery of eligible electric conservation program costs through the energy
conservation surcharge. Base rates increased for the quarter and nine months
ended September 30, 1996 compared to last year due to recovery of a higher level
of eligible electric conservation program costs.
Under the energy conservation surcharge, if the PSC determines that BGE is
earning in excess of its authorized rate of return, BGE will have to refund (by
means of lowering future surcharges) a portion of energy conservation surcharge
revenues to its customers. This determination is now made on an annual basis at
the end of each year. The portion subject to the refund is compensation for
foregone sales from conservation programs and incentives for achieving
conservation goals and will be refunded to customers with interest beginning in
the ensuing July when the annual resetting of the conservation surcharge rates
occurs.
Changes in fuel rate revenues result from the operation of the electric
fuel rate formula. The fuel rate formula is designed to recover the actual cost
of fuel, net of revenues from interchange sales and sales to other utilities
(See Notes 1 and 12 of the Form 10-K). Changes in fuel rate revenues and
interchange and other sales normally do not affect earnings. However, if the PSC
were to disallow recovery of any part of these costs, earnings would be reduced
as discussed in Note 12 of the Form 10-K.
Fuel rate revenues were lower for the quarter ended September 30, 1996 as
compared to the same period in 1995 as a result of a lower fuel rate and lower
electric system sales volumes. Fuel rate revenues were lower for the nine months
ended September 30, 1996 as compared to the same period in 1995 as a result of a
lower fuel rate, offset partially by higher electric system sales volumes
primarily during the first quarter of 1996. The fuel rate was lower for the
quarter and nine months ended September 30, 1996 as compared to the same periods
last year because of a less costly twenty-four month generation mix at the
Company's generating plants. BGE expects electric fuel rate revenues to remain
relatively constant through the remainder of 1996.
Interchange and other sales represent sales of BGE's energy to the
Pennsylvania - New Jersey - Maryland Interconnection (PJM), a regional power
pool of eight member companies including BGE, and sales to other parties. These
sales occur after BGE has satisfied the demand for its own system sales of
electricity. Interchange and other sales decreased for the quarter and nine
months ended September 30, 1996 compared to the same periods last year because
of lower generation from the Calvert Cliffs Nuclear Power Plant, offset
partially by a higher price per megawatt of electricity sold.
Gas revenues changed for the quarter and nine months ended September 30,
1996 because of the following factors:
Quarter Ended Nine Months Ended
September 30 September 30
1996 vs. 1995 1996 vs. 1995
------------- -------------
(In millions)
Sales volumes $0.1 $ 9.2
Base rates 3.7 16.6
Gas cost adjustment revenues 1.8 57.4
--- ----
Revenues from system sales 5.6 83.2
Off-system Sales 8.0 21.3
Other revenues (0.2) 0.9
---- ---
Total $13.4 $105.4
===== ======
Below is a comparison of the changes in gas sales volumes:
Quarter Ended Nine Months Ended
September 30 September 30
1996 vs. 1995 1996 vs. 1995
------------- -------------
Residential 6.5% 15.9%
Commercial (6.8) 4.0
Industrial 2.0 (3.6)
Total 0.8 5.1
14
Gas sales to residential customers increased during the quarter ended
September 30, 1996 as compared to the same period last year due to greater usage
per customer and an increase in the number of customers. Sales to commercial
customers decreased compared to last year due primarily to decreased usage per
customer, offset partially by an increase in the number of customers. Sales to
industrial customers increased compared to last year due to increased usage per
customer which more than offset decreased usage by Bethlehem Steel.
Gas sales to residential customers increased during the nine months ended
September 30, 1996 as compared to the same period last year primarily due to
colder winter and early spring weather, an increase in the number of customers,
and an increase in usage per customer. Sales to commercial customers also
increased compared to last year due to colder winter weather and an increase in
the number of customers, but this was offset partially by lower usage per
customer. Sales to industrial customers decreased compared to last year due to
decreased usage by Bethlehem Steel and a greater number of interruptions caused
by the colder winter weather this year, offset partially by increased usage by
other industrial customers and by an increase in the number of customers.
Base rates increased during the quarter and nine months ended September 30,
1996 compared to the same period last year primarily as a result of the PSC's
November 1995 rate order, which increased annual base rate revenues by $19.3
million, including $2.4 million to recover higher depreciation expense.
Changes in gas cost adjustment revenues result primarily from the operation
of the purchased gas adjustment clause, commodity charge adjustment clause, and
the actual cost adjustment clause which are designed to recover actual gas
costs. (See Note 1 of the Form 10-K.) Changes in gas cost adjustment revenues
normally do not affect earnings. Gas cost adjustment revenues increased for the
quarter and nine months ended September 30, 1996 because of higher prices for
purchased gas. Gas cost adjustment revenues also increased for the nine months
ended September 30, 1996 because of higher sales volumes subject to gas cost
adjustment clauses. Delivery service sales volumes are not subject to gas cost
adjustment clauses because these customers purchase their gas directly from
third parties.
Off-system gas sales volumes represent direct sales to end users of natural
gas outside BGE's service territory and are not subject to gas cost adjustment
clauses. BGE began sales of off- system gas during the first quarter of 1996.
Pursuant to a sharing arrangement approved by the PSC, the gross margin earned
on these sales reduces gas cost adjustment charges to customers and increases
income available to common shareholders.
BGE Utility Fuel and Energy Expenses
- ------------------------------------
Electric fuel and purchased energy expenses were as follows:
Quarter Ended Nine Months Ended
September 30 September 30
------------ ------------
1996 1995 1996 1995
---- ---- ---- ----
(In millions)
Actual costs $140.4 $156.7 $419.6 $420.2
Net (deferral) recovery
of costs under electric
fuel rate clause (see
Note 1 of the Form 10-K) (6.2) (1.6) (10.8) 15.5
Disallowed deferred fuel costs 0.0 0.0 6.8 0.0
--- --- --- ---
Total $134.2 $155.1 $415.6 $435.7
====== ====== ====== ======
Total electric fuel and purchased energy expenses decreased during the
quarter ended September 30, 1996 as a result lower actual costs and the
operation of the electric fuel rate clause. Total electric fuel and purchased
energy expenses decreased during the nine months ended September 30, 1996 as a
result of slightly lower actual costs and the operation of the electric fuel
rate clause, offset partially by the write-off of previously deferred fuel costs
which were disallowed by the PSC in a May 1996 Order.
Actual electric fuel and purchased energy costs decreased for the quarter
ended September 30, 1996 compared to the same period last year as a result of a
lower net output of electricity and lower purchased energy
15
costs. Actual electric fuel and purchased energy costs were essentially
unchanged for the nine months ended September 30, 1996 compared to the same
period last year.
Purchased gas expenses were as follows:
Quarter Ended Nine Months Ended
September 30 September 30
------------ ------------
1996 1995 1996 1995
---- ---- ---- ----
(In millions)
Actual costs $28.6 $ 16.9 $203.8 $135.6
Net (deferral) recovery
of costs under purchased gas
adjustment clause (see
Note 1 of the Form 10-K) (.5) 1.4 2.7 (6.3)
--- --- --- ----
Total $28.1 $ 18.3 $206.5 $129.3
===== ====== ====== ======
Total purchased gas expenses increased for the quarter and nine months
ended September 30, 1996 compared to last year due to an increase in actual gas
costs. Total purchased gas expenses also increased for the nine months ended
September 30, 1996 due to the operation of the purchased gas adjustment clause.
Actual gas costs increased for the quarter and nine months ended September 30,
1996 due to higher gas prices compared to last year and the purchase of gas for
off-system sales which began in 1996. Actual gas costs also increased for the
nine months ended September 30, 1996 due to higher sales volumes. Purchased gas
costs exclude gas purchased by delivery service customers, including Bethlehem
Steel, who obtain gas directly from third parties.
Other Operating Expenses
- ------------------------
Operations and maintenance expense increased $2.2 million and $5.5 million,
respectively, during the quarter and nine months ended September 30, 1996
compared to the same periods last year, primarily due to higher nuclear outage
maintenance costs. Operations and maintenance expense also increased during the
nine months ended September 30, 1996 compared to the same period last year due
to increased labor costs.
Depreciation and amortization expense decreased $9.9 million during the
quarter ended September 30, 1996 compared to the same period last year because
depreciation and amortization expense during the third quarter of 1995 reflected
a $14.2 million write-off of certain Perryman costs. Depreciation and
amortization expense increased $5.8 million during the nine months ended
September 30, 1996 compared to the same period last year because of a higher
level of depreciable plant in service and higher amortization of deferred energy
conservation surcharge expenditures, offset partially by the write-off mentioned
above.
Taxes other than income taxes increased $3.3 million and $10.0 million,
respectively, during the quarter and nine months ended September 30, 1996 due to
an increase in property taxes resulting from plant additions during 1995 and
higher payroll taxes due to greater incentive-based payouts and a 3% general
wage increase granted March 1, 1996. Taxes other than income taxes also
increased during the nine months ended September 30, 1996 due to higher gross
receipts taxes as a result of increased revenues.
Other Income and Expenses
- -------------------------
The Allowance for Funds Used During Construction (AFC) decreased $1.6
million and $11.2 million, respectively, for the quarter and nine months ended
September 30, 1996 due primarily to a significant reduction in construction work
in progress and a lower gas AFC rate. The reduction in construction work in
progress resulted from both a lower level of new construction activity and the
placement of several projects in service during the past year.
Interest charges were essentially unchanged for the quarter ended September
30, 1996. Interest charges decreased $4.0 million for the nine months ended
September 30, 1996 due primarily to the maturity of long-term debt as well as
lower interest rates compared to last year, offset partially by a higher overall
level of debt outstanding.
16
Income tax expense decreased $6.9 million for the quarter ended September
30, 1996 and increased $26.5 million for the nine months ended September 30,
1996 due primarily to changes in the level of taxable income from utility
operations and diversified businesses during those periods.
Diversified Businesses Earnings
- -------------------------------
Earnings per share from diversified businesses were as follows:
Quarter Ended Nine Months Ended
September 30 September 30
------------ ------------
1996 1995 1996 1995
---- ---- ---- ----
Constellation Holdings, Inc.
Power generation systems $.03 $.07 $.14 $.11
Financial investments .04 .02 .08 .06
Real estate development and
senior living facilities (.01) (.01) (.02) (.02)
Other .00 .00 (.01) (.01)
--- --- ---- ----
Total Constellation Holdings, Inc. .06 .08 .19 .14
Other Subsidiaries. .01 .00 .02 .00
--- --- --- ---
Total diversified businesses $.07 $.08 $.21 $.14
==== ==== ==== ====
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 decreased for the
quarter ended September 30, 1996 due primarily to the $6.2 million after-tax
write-off of an investment in a solar power project in which the Constellation
Companies have a minority ownership interest and which is being restructured
pursuant to negotiation with the lender. Power generation systems earnings
increased for the nine months ended September 30, 1996 due primarily to higher
equity earnings from the Constellation Companies' energy projects and a $14.6
million after-tax gain on the sale by a Constellation partnership of a power
purchase agreement with Jersey Central Power & Light back to that utility. These
increases were partially offset by the $7.0 million after-tax write-off of the
investment in two geothermal wholesale power generating plants, discussed below
in connection with the Interim Standard Offer No. 4 power purchase agreements,
the $3.0 million after-tax write-off of development costs of a proposed
coal-fired power project that will not be built, and the $6.2 million after-tax
write-off of the solar power project investment mentioned above.
The Constellation Companies' investment in wholesale power generating
projects includes $216 million representing ownership interests in 16 projects,
including the two geothermal projects which were written-off as discussed below,
that sell electricity in California under Interim Standard Offer No. 4 (SO4)
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 thereafter at fixed capacity payments plus variable energy
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 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. At current avoided cost levels, the
Constellation Companies could experience reduced earnings or incur losses
associated with these projects, which could be significant. While nine projects
(including the two geothermal projects that have been written-off) transition
from fixed to variable energy rates in the 1996 through 1998 timeframe, revenues
from the other projects having SO4 contracts are expected to continue to
increase during this period tending to offset revenue declines on the nine
projects. Six of the seven largest revenue producing projects will not make the
transition to variable energy rates until the 1999-2000 timeframe such that any
material reductions in revenues would not be anticipated until the years 2000
and 2001.
The Constellation Companies are investigating and pursuing alternatives for
certain of these power generation projects including, but not limited to,
repowering the projects to reduce operating costs, changing fuels,
17
renegotiating the power purchase agreements, restructuring financings, and
selling its ownership interests in the projects. During the second quarter of
1996, the Constellation Companies determined that successful mitigation measures
for two geothermal power plants are now unlikely and that the investment in
these plants was impaired. Accordingly, the Constellation Companies recorded a
$7.0 million after-tax write off of the investment in these plants. Two of the
other wholesale power generating projects, in which the Constellation Companies'
investment totals $34 million, have executed agreements with Pacific Gas &
Electric (PG&E) providing for the curtailment of output through the end of the
fixed price period in return for payments from PG&E. The payments from PG&E
during the curtailment period will be sufficient to fully amortize the existing
project finance debt. However, following the curtailment period, the projects
remain contractually obligated to commence production of electricity at the
avoided cost rates, which could result in reduced earnings or losses for the
reasons described above. The Company cannot predict the impact that these
matters regarding any of these projects may have on the Constellation Companies
or the Company, but the impact could be material.
Earnings from the Constellation Companies' portfolio of financial
investments include capital gains and losses, dividends, income from financial
limited partnerships, and income from financial guaranty insurance companies.
Financial investment earnings were higher for the quarter and nine months ended
September 30, 1996 because of higher earnings realized from various financial
limited partnerships.
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 oversupply of and limited demand for land and office space due
to modest economic growth and corporate downsizings. Earnings from real estate
development and senior living facilities for the quarter and nine months ended
September 30, 1996 are essentially unchanged from the prior year.
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 until the economy reflects sustained growth that results in a demand
for new development, 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.
The Constellation Companies' real estate portfolio has experienced
continuing carrying costs and depreciation. Additionally, the Constellation
Companies have been expensing rather than capitalizing interest on certain
undeveloped land for which substantially all development activities have been
suspended. These factors have affected earnings negatively and are expected to
continue to do so until the levels of undeveloped land are reduced. Cash flow
from real estate operations has been insufficient to cover the debt service
requirements of certain of these projects. Resulting cash shortfalls have been
satisfied through cash infusions from Constellation Holdings, Inc., which
obtained the funds through a combination of cash flow generated by other
Constellation Companies and its corporate borrowings. Applicable accounting
rules would require a write-down of a real estate project to market value if one
of two situations occur. The first is if the Constellation Companies change
their intent about any project from an intent to hold to an intent to sell and
the market value of the project is below the book value. The second is if the
expected future cash flows from the project are less than the investment in the
project. Currently, the Constellation Companies are reevaluating their real
estate strategy in the context of competing financial demands, changes in the
utility industry, and the proposed merger with PEPCO.
The earnings of other subsidiaries, which include HP&S, EP&S, and BNG,
Inc., increased slightly during the quarter and nine months ended September 30,
1996 compared to the same periods last year, due primarily to improved operating
results from HP&S.
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
18
former operating sites, including Environmental Protection Agency Superfund
sites. Details regarding these matters, including financial information, are
presented in the Notes to Consolidated Financial Statements under the heading
"Environmental Matters".
LIQUIDITY AND CAPITAL RESOURCES
Liquidity
- ---------
For the twelve months ended September 30, 1996, the Company's ratio of
earnings to fixed charges and ratio of earnings to combined fixed charges and
preferred and preference dividend requirements were 3.50 and 2.72, respectively.
Capital Requirements
- --------------------
The Company's capital requirements reflect the capital-intensive nature of
the utility business. Actual capital requirements for the nine months ended
September 30, 1996, along with estimated annual amounts for the years 1996
through 1998, are reflected below.
Nine Months Ended
September 30 Calendar Year Estimate
1996 1996 1997 1998
---- ---- ---- ----
(In millions)
Utility Business:
- -----------------
Construction expenditures (excluding AFC)
Electric $153 $218 $214 $212
Gas 57 73 73 69
Common 41 49 48 44
-- -- -- --
Total construction expenditures 251 340 335 325
AFC 8 9 10 10
Nuclear fuel (uranium purchases
and processing charges) 46 49 45 44
Deferred energy conservation
expenditures 22 34 25 19
Retirement of long-term debt
and redemption of
preferred and preference stock 161 184 165 117
--- --- --- ---
Total utility business 488 616 580 515
--- --- --- ---
Diversified Businesses:
- -----------------------
Retirement of long-term debt 47 51 131 183
Investment requirements 48 83 71 82
-- -- -- --
Total diversified businesses 95 134 202 265
-- --- --- ---
Total $583 $750 $782 $780
==== ==== ==== ====
BGE Utility Capital Requirements
- --------------------------------
BGE utility capital requirements do not reflect costs to achieve the
pending merger with PEPCO which are discussed in the Notes to Consolidated
Financial Statements under the heading "Pending Merger With Potomac Electric
Power Company."
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 the second of two
5,000 kilowatt diesel generators at Calvert Cliffs Nuclear Power Plant, which
was placed in service during June 1996, and improvements in BGE's existing
generating plants and its transmission and distribution facilities. Future
electric construction expenditures do not include additional generating units.
During the twelve months ended September 30, 1996, the internal generation
of cash from utility operations provided 97% of the funds required for BGE's
capital requirements exclusive of retirements and redemptions of debt and
preference stock. During the three-year period 1996 through 1998, the Company
expects to provide through utility operations 115% of the funds required for
BGE's capital requirements, exclusive of retirements and redemptions.
19
Utility capital requirements not met through the internal generation of
cash are met through the issuance of debt and equity securities. The amount and
timing of issuances and redemptions depend upon market conditions and BGE's
actual capital requirements. From January 1, 1996 through the date of this
Report, BGE's issuances of long-term debt and common equity were $235 million
and $4 million, respectively. During the same period, $72 million principal
amount of debt and $110 million par value of preferred and preference stock
either matured or were redeemed by BGE. All outstanding preferred stock was
redeemed as described in the Notes to Consolidated Financial Statements under
the heading "BGE Financing Activity."
At the date of this Report, BGE's securities ratings are as follows:
Standard Moody's
& Poors Investors Duff & Phelps
Rating Group Service Credit Rating Co.
------------ ------- -----------------
Senior Secured Debt A+ A1 AA-
(First Mortgage Bonds)
Unsecured Debt A A2 A+
Preference Stock A "a2" A
The Constellation Companies' capital requirements are discussed below under
the heading "Diversified Businesses Capital Requirements-Debt and Liquidity."
The Constellation Companies are exploring expansion of their energy, real estate
service, and senior living facility businesses. Expansion may be achieved in a
variety of ways, including without limitation increased investment activity and
acquisitions. The Constellation Companies plan to meet their capital
requirements with a combination of debt and internal generation of cash from
their operations. Additionally, from time to time, BGE may make loans to
Constellation Holdings, Inc., or contribute equity to enhance the capital
structure of Constellation Holdings, Inc.
Historically, Constellation's energy projects have been in the United
States. Over the last year, Constellation has pursued energy projects in Latin
America. As of September 30, 1996, one of the Constellation Companies had
invested about $17.5 million and committed another $6.0 million in power
projects in Latin America. Constellation's future energy business expansion may
include domestic and international projects.
Diversified Businesses Capital Requirements
- -------------------------------------------
Debt and Liquidity
- ------------------
The Constellation Companies intend to meet capital requirements by
refinancing debt as it comes due and through internally generated cash. These
internal sources include cash that may be generated from operations, sale of
assets, and cash generated by tax benefits earned by the Constellation
Companies. In the event the Constellation Companies can obtain reasonable value
for real estate properties, additional cash may become available through the
sale of projects (for additional information see the discussion of the real
estate business and market under the heading "Diversified Businesses Earnings").
The ability of the Constellation Companies to sell or liquidate assets described
above will depend on market conditions, and no assurances can be given that such
sales or liquidations can be made. Also, to provide additional liquidity to meet
interim financial needs, CHI has a $75 million revolving credit agreement of
which $52 million was outstanding at the date of this Report.
Investment Requirements
- -----------------------
The investment requirements of the Constellation Companies include its
portion of equity funding to committed projects under development, as well as
net loans made to project partnerships. Investment requirements for the years
1996 through 1998 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 in the table under the heading "Capital Requirements" 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.
20
PART II. OTHER INFORMATION
--------------------------
ITEM 1. Legal Proceedings
- --------------------------
Asbestos
- --------
Since 1993, BGE has been served in several actions concerning asbestos. The
actions are collectively titled In re Baltimore City Personal Injuries Asbestos
Cases in the Circuit Court for Baltimore City, Maryland. The actions are based
upon the theory of "premises liability," alleging that BGE knew of and exposed
individuals to an asbestos hazard. The actions relate to two types of claims.
The first type, direct claims by individuals exposed to asbestos, were
described in a Report on Form 8-K filed August 20, 1993. BGE and approximately
70 other defendants are involved. Approximately 516 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 one manufacturer - Pittsburgh Corning Corp. -
against BGE and approximately eight others, as third-party defendants. These
claims relate to approximately 1,500 individual plaintiffs. BGE does not know
the specific facts necessary for BGE to assess its potential liability for these
type claims, such as the identity of BGE facilities containing asbestos
manufactured by the manufacturer, 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 third quarter of 1996, an additional environmental action was
instituted.
In September, 1996, BGE received an information request from the U.S.
Environmental Protection Agency concerning the Drumco Drum Dump Site, located in
the Curtis Bay area of Maryland. This site was the subject of an emergency drum
removal action in 1991, due to a concern about hazardous substances leaking from
drums and posing a threat to human health and the environment. According to EPA
documents, approximately $2 million dollars was spent on the drum removal
action. To our knowledge, no long-term remediation is planned for this site. In
addition, we understand that EPA has sent information requests to approximately
17 other parties. BGE's records indicate that it sold empty drums to Drumco,
Inc. from approximately 1983-1990. BGE is currently reviewing all relevant
documents and interviewing employees involved in selling the drums to Drumco.
BGE's potential liability cannot be estimated at this time. However we believe
that any liability is not likely to be material based on BGE's records showing
that only empty storage drums were sold to Drumco, Inc.
21
PART II. OTHER INFORMATION (Continued)
--------------------------------------
ITEM 6. Exhibits and Reports on Form 8-K
- ----------------------------------------
(a) Exhibit No. 2* Registration Statement on Form S-4
of Constellation Energy
Corporation, as amended, which
became effective February 9,
1996, Registration No. 33-64799.
Exhibit No. 3 Articles of Restatement, dated as
of August 16, 1996, to the Charter
of Baltimore Gas and Electric
Company.
Exhibit No. 10(a) Baltimore Gas and Electric Company
Executive Benefits Plan, as
amended and restated.
Exhibit No. 10(b) Baltimore Gas and Electric Company
Manager Benefits Plan, as amended
and restated.
Exhibit No. 12 Computation of Ratio of Earnings
to Fixed Charges and Computation
of Ratio of Earnings to Combined
Fixed Charges and Preferred and
Preference Dividend Requirements.
Exhibit No. 27 Financial Data Schedule.
*Incorporated by Reference.
(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 November 14, 1996 /s/ C.W. Shivery
-------------------
C. W. Shivery, Vice President
on behalf of the Registrant and
as Principal Financial Officer
22
EXHIBIT INDEX
Exhibit
Number
------
2* Registration Statement on Form S-4 of
Constellation Energy Corporation, as
amended, which became effective
February 9, 1996, Registration No. 33-
64799.
3 Articles of Restatement, dated as of
August 16, 1996, to the Charter of
Baltimore Gas and Electric Company.
10(a) Baltimore Gas and Electric Company
Executive Benefits Plan, as amended and
restated.
10(b) Baltimore Gas and Electric Company
Manager Benefits Plan, as amended and
restated.
12 Computation of Ratio of Earnings to
Fixed Charges and Computation of Ratio
of Earnings to Combined Fixed Charges
and Preferred and Preference Dividend
Requirements.
27 Financial Data Schedule.
*Incorporated by Reference.
23